UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-K
| x | ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the Fiscal Year Ended December 31, 2004
OR
| ¨ | TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
| Commission File Number |
Name of Registrant; State of Incorporation; Address of Principal Executive Offices; and Telephone Number |
IRS Employer Identification Number | ||
| 1-16169 |
EXELON CORPORATION (a Pennsylvania corporation) 10 South Dearborn Street—37th Floor P.O. Box 805379 Chicago, Illinois 60680-5379 (312) 394-7398 |
23-2990190 | ||
| 1-1839 |
COMMONWEALTH EDISON COMPANY (an Illinois corporation) 10 South Dearborn Street—37th Floor P.O. Box 805379 Chicago, Illinois 60680-5379 (312) 394-4321 |
36-0938600 | ||
| 1-1401 |
PECO ENERGY COMPANY (a Pennsylvania corporation) P.O. Box 8699 2301 Market Street Philadelphia, Pennsylvania 19101-8699 (215) 841-4000 |
23-0970240 | ||
| 333-85496 |
EXELON GENERATION COMPANY, LLC (a Pennsylvania limited liability company) 300 Exelon Way Kennett Square, Pennsylvania 19348 (610) 765-6900 |
23-3064219 |
Securities registered pursuant to Section 12(b) of the Act:
| Title of Each Class |
Name of Each Exchange on Which Registered | |
| EXELON CORPORATION: |
||
| Common Stock, without par value |
New York, Chicago and Philadelphia | |
| PECO ENERGY COMPANY: |
||
| Cumulative Preferred Stock, without par value: $4.68 Series, $4.40 Series, $4.30 Series and $3.80 Series |
New York | |
| Trust Receipts of PECO Energy Capital Trust III, each representing a 7.38% Cumulative Preferred Security, Series D, $25 stated value, issued by PECO Energy Capital, L.P. and unconditionally guaranteed by PECO Energy Company |
New York |
Securities registered pursuant to Section 12(g) of the Act:
COMMONWEALTH EDISON COMPANY:
Common Stock Purchase Warrants, 1971 Warrants and Series B Warrants
Indicate by check mark whether the registrants (1) have filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) have been subject to such filing requirements for the past 90 days. Yes x No ¨
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrants’ knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. ¨
Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Act).
| Exelon Corporation |
Yes x | No ¨ | ||
| Commonwealth Edison Company |
Yes ¨ | No x | ||
| PECO Energy Company |
Yes ¨ | No x | ||
| Exelon Generation Company, LLC |
Yes ¨ | No x |
The estimated aggregate market value of the voting and non-voting common equity held by nonaffiliates of each registrant as of June 30, 2004, was as follows:
| Exelon Corporation Common Stock, without par value |
$22,048,288,415 | |
| Commonwealth Edison Company Common Stock, $12.50 par value |
No established market | |
| PECO Energy Company Common Stock, without par value |
None | |
| Exelon Generation Company, LLC |
Not applicable |
The number of shares outstanding of each registrant’s common stock as of January 31, 2005 was as follows:
| Exelon Corporation Common Stock, without par value |
664,807,122 | |
| Commonwealth Edison Company Common Stock, $12.50 par value |
127,016,502 | |
| PECO Energy Company Common Stock, without par value |
170,478,507 | |
| Exelon Generation Company, LLC |
Not applicable |
TABLE OF CONTENTS
| Page No. | ||||
| 1 | ||||
| 1 | ||||
| 1 | ||||
| PART I |
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| ITEM 1. |
2 | |||
| 2 | ||||
| 4 | ||||
| 11 | ||||
| 22 | ||||
| 22 | ||||
| 23 | ||||
| 29 | ||||
| Other Subsidiaries of ComEd and PECO with Publicly Held Securities |
30 | |||
| 31 | ||||
| ITEM 2. |
34 | |||
| 34 | ||||
| 35 | ||||
| ITEM 3. |
37 | |||
| 37 | ||||
| 37 | ||||
| 37 | ||||
| ITEM 4. |
38 | |||
| PART II |
||||
| ITEM 5. |
39 | |||
| ITEM 6. |
41 | |||
| 41 | ||||
| 43 | ||||
| 44 | ||||
| 45 | ||||
| ITEM 7. |
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATION |
46 | ||
| 55 | ||||
| 225 | ||||
| 282 | ||||
| 330 | ||||
| ITEM 7A. |
121 | |||
| 121 | ||||
| 244 | ||||
| 297 | ||||
| 349 | ||||
| ITEM 8. |
131 | |||
| 131 | ||||
| 245 | ||||
| 298 | ||||
| 350 | ||||
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| Page No. | ||||
| ITEM 9. |
CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE |
411 | ||
| ITEM 9A. |
411 | |||
| 411 | ||||
| 411 | ||||
| 411 | ||||
| 411 | ||||
| PART III |
||||
| ITEM 10. |
412 | |||
| 412 | ||||
| 414 | ||||
| 415 | ||||
| 416 | ||||
| ITEM 11. |
417 | |||
| 417 | ||||
| 422 | ||||
| 427 | ||||
| 432 | ||||
| ITEM 12. |
SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT |
449 | ||
| 449 | ||||
| 450 | ||||
| 452 | ||||
| 453 | ||||
| ITEM 13. |
453 | |||
| 453 | ||||
| 453 | ||||
| 454 | ||||
| 453 | ||||
| ITEM 14. |
454 | |||
| 454 | ||||
| 455 | ||||
| 455 | ||||
| 455 | ||||
| PART IV |
||||
| ITEM 15. |
457 | |||
| 474 | ||||
| 474 | ||||
| 475 | ||||
| 476 | ||||
| 477 | ||||
ii
This combined Form 10-K is being filed separately by Exelon Corporation (Exelon), Commonwealth Edison Company (ComEd), PECO Energy Company (PECO) and Exelon Generation Company, LLC (Generation) (collectively, the Registrants). Information contained herein relating to any individual registrant is filed by such registrant on its own behalf. No registrant makes any representation as to information relating to any other registrant.
Certain of the matters discussed in this Report are forward-looking statements, within the meaning of the Private Securities Litigation Reform Act of 1995, that are subject to risks and uncertainties. The factors that could cause actual results to differ materially from the forward-looking statements made by a registrant include those factors discussed herein, including those discussed in (a) ITEM 7. Management’s Discussion and Analysis of Financial Condition and Results of Operation—Business Outlook and the Challenges in Managing the Business for each of Exelon, ComEd, PECO and Generation, (b) ITEM 8. Financial Statements and Supplementary Data: Exelon—Note 21, ComEd—16, PECO—Note 15 and Generation—Note 17 and (c) other factors discussed in filings with the United States Securities and Exchange Commission (SEC) by the Registrants. Readers are cautioned not to place undue reliance on these forward-looking statements, which apply only as of the date of this Report. None of the Registrants undertakes any obligation to publicly release any revision to its forward-looking statements to reflect events or circumstances after the date of this Report.
WHERE TO FIND MORE INFORMATION
The public may read and copy any reports or other information that a registrant files with the SEC at the SEC’s public reference room at 450 Fifth Street, N.W., Washington, D.C. 20549. The public may obtain information on the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330. These documents are also available to the public from commercial document retrieval services, the web site maintained by the SEC at www.sec.gov and Exelon’s website at www.exeloncorp.com. Information contained on Exelon’s website shall not be deemed incorporated into, or to be a part of, this Report.
The Exelon corporate governance guidelines and the charters of the standing committees of its Board of Directors, together with the Exelon Code of Business Conduct and additional information regarding Exelon’s corporate governance, are available on Exelon’s website at www.exeloncorp.com and will be made available, without charge, in print to any shareholder who requests such documents from Katherine K. Combs, Vice President and Corporate Secretary, Exelon Corporation, P.O. Box 805398, Chicago, Illinois 60680-5398.
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PART I
Exelon, a registered public utility holding company, through its subsidiaries, operates in three business segments—Energy Delivery, Generation and Enterprises—as described below. See Note 22 of Exelon’s Notes to Consolidated Financial Statements for further segment information. In addition to Exelon’s three business segments, Exelon Business Services Company (BSC), a subsidiary of Exelon, provides Exelon and its subsidiaries with financial, human resource, legal, information technology, supply management and corporate governance services.
Exelon was incorporated in Pennsylvania in February 1999. Exelon’s principal executive offices are located at 10 South Dearborn Street, Chicago, Illinois 60603, and its telephone number is 312-394-7398.
Proposed Merger with Public Service Enterprise Group Incorporated
On December 20, 2004, Exelon entered into an Agreement and Plan of Merger (Merger Agreement) with Public Service Enterprise Group Incorporated (PSEG), the holding company for an electric and gas utility company primarily located and serving customers in New Jersey, whereby PSEG will be merged with and into Exelon (Merger). Under the Merger Agreement, each share of PSEG common stock will be converted into 1.225 shares of Exelon common stock. As of December 31, 2004, PSEG’s market capitalization was over $12 billion. Additionally, PSEG, on a consolidated basis, has approximately $14 billion of outstanding debt which is currently anticipated to become part of Exelon’s consolidated debt.
The Merger Agreement contains certain termination rights for both Exelon and PSEG, and further provides that, upon termination of the Merger Agreement under specified circumstances, (i) Exelon may be required to pay PSEG a termination fee of $400 million plus PSEG’s transaction expenses up to $40 million and (ii) PSEG may be required to pay Exelon a termination fee of $400 million plus Exelon’s transaction expenses up to $40 million. The Merger Agreement has been unanimously approved by both companies’ boards of directors but is contingent upon, among other things, the approval by shareholders of both companies, antitrust clearance and a number of regulatory approvals or reviews by federal and state energy authorities. The parties have made certain of the regulatory filings to obtain necessary regulatory approvals. It is anticipated that this approval process will be completed and the Merger will close within 12 months to 15 months after the announcement of the Merger Agreement in December 2004. Further information concerning the proposed Merger is included in the preliminary joint proxy statement/prospectus contained in the registration statement on Form S-4 filed by Exelon in connection with the Merger. For additional information related to the Merger, see ITEM 7. Management’s Discussion and Analysis of Financial Condition and Results of Operation—Exelon—Executive Overview—Proposed Merger with PSEG and Note 2 of Exelon’s Notes to Consolidated Financial Statements.
Energy Delivery
Exelon’s energy delivery business consists of the purchase and regulated sale of electricity and distribution and transmission services by ComEd in northern Illinois, including the City of Chicago, and by PECO in southeastern Pennsylvania, including the City of Philadelphia, and the purchase and regulated sale of natural gas and distribution services by PECO in the Pennsylvania counties surrounding the City of Philadelphia (collectively, Energy Delivery).
ComEd was organized in the State of Illinois in 1913 as a result of the merger of Cosmopolitan Electric Company into the original corporation named Commonwealth Edison Company, which was
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incorporated in 1907. ComEd’s principal executive offices are located at 10 South Dearborn Street, Chicago, Illinois 60603, and its telephone number is 312-394-4321. PECO was incorporated in Pennsylvania in 1929. PECO’s principal executive offices are located at 2301 Market Street, Philadelphia, Pennsylvania 19103 and its telephone number is 215-841-4000.
Generation
At December 31, 2004, Exelon’s generation business consists of the owned and contracted-for electric generating facilities and energy marketing operations of Generation, a 50% interest in Sithe Energies, Inc. (Sithe), 49.5% interests in two power stations in Mexico and the competitive retail sales business of Exelon Energy Company (Exelon Energy). On January 31, 2005, Exelon purchased the remaining 50% of Sithe and immediately sold its entire interest in Sithe.
Exelon Generation Company, LLC was formed in 2000 as a Pennsylvania limited liability company. Generation began operations as a result of a corporate restructuring effective January 1, 2001 in which Exelon separated its generation and other competitive businesses from its regulated energy delivery business at ComEd and PECO. Generation’s principal executive offices are located at 300 Exelon Way, Kennett Square, Pennsylvania 19348, and its telephone number is 610-765-6900.
Enterprises
Exelon’s enterprises business is comprised of infrastructure and electrical contracting services of Exelon Enterprises Company, LLC (Enterprises) and other investments weighted towards the communications and energy services industries. During 2004 and 2003, Enterprises exited a significant number of businesses and investments. Exelon plans to divest or wind down the remaining assets of Enterprises during 2005.
Federal and State Regulation
Exelon, a registered holding company under the Public Utility Holding Company Act of 1935 (PUHCA), is subject to Federal and state regulation. ComEd is a public utility under the Illinois Public Utilities Act subject to regulation by the Illinois Commerce Commission (ICC). PECO is a public utility under the Pennsylvania Public Utility Code subject to regulation by the Pennsylvania Public Utility Commission (PUC). ComEd, PECO and Generation are electric utilities under the Federal Power Act subject to regulation by the Federal Energy Regulatory Commission (FERC). Specific operations of Exelon are also subject to the jurisdiction of various other Federal, state, regional and local agencies, including the United States Nuclear Regulatory Commission (NRC).
Exelon is subject to a number of restrictions under PUHCA. These restrictions generally involve financing, investments and affiliate transactions. Under PUHCA, Exelon cannot issue debt or equity securities or guarantees without approval of the United States Securities and Exchange Commission (SEC) or, in the case of ComEd and PECO, the ICC and the PUC, respectively. On April 1, 2004, Exelon obtained a new order under PUHCA authorizing, through April 15, 2007, financing transactions, including the issuance of common stock, preferred securities, equity-linked securities, long-term debt and short-term debt in an aggregate amount not to exceed $8.0 billion above the amount outstanding for the Exelon holding company and Generation at December 31, 2003. No securities have been issued under the above described limit as of December 31, 2004. Exelon is also authorized to issue up to $6.0 billion in guarantees or letters of credit or otherwise provide credit support with respect to the obligations of their subsidiaries and non-affiliated third parties in the normal course of business. As of December 31, 2004, Exelon had $2.0 billion of guarantees and letters of credit outstanding pursuant to SEC authorization.
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PUHCA also limits the businesses in which Exelon may engage and the investments that Exelon may make. With limited exceptions, Exelon may only engage in traditional electric and gas utility businesses and other businesses that are reasonably incidental or economically necessary or appropriate to the operations of the utility business. The exceptions include Exelon’s ability to invest in exempt telecommunications companies, exempt wholesale generating businesses and foreign utility companies (these investments are capped at $4 billion in the aggregate), energy-related companies (as defined in SEC rules and subject to a cap on these investments of 15% of Exelon’s consolidated capitalization), and other businesses, subject to SEC approval. In addition, PUHCA requires that all of a registered holding company’s utility subsidiaries constitute a single system that can be operated in an efficient, coordinated manner.
For additional information about restrictions on the payment of dividends and other effects of PUHCA on Exelon and its subsidiaries, see ITEM 7. Management’s Discussion and Analysis of Financial Condition and Results of Operation—Exelon.
Energy Delivery consists of Exelon’s regulated energy delivery operations conducted by ComEd and PECO.
ComEd is engaged principally in the purchase, transmission, distribution and sale of electricity to a diverse base of residential, commercial, industrial and wholesale customers in northern Illinois. ComEd is subject to extensive regulation by the ICC as to rates, the issuance of securities, and certain other aspects of ComEd’s operations. ComEd is also subject to regulation by the FERC as to transmission rates and certain other aspects of ComEd’s business.
ComEd’s retail service territory has an area of approximately 11,300 square miles and an estimated population of eight million. The service territory includes the City of Chicago, an area of about 225 square miles with an estimated population of three million. ComEd has approximately 3.7 million customers.
ComEd’s franchises are sufficient to permit it to engage in the business it now conducts. ComEd’s franchise rights are generally nonexclusive rights documented in agreements and, in some cases, certificates of public convenience issued by the ICC. With few exceptions, the franchise rights have stated expiration dates ranging from 2005 to 2060 and subsequent years. ComEd anticipates working with the appropriate agencies to extend or replace the franchise agreements upon expiration.
PECO is engaged principally in the purchase, transmission, distribution and sale of electricity to residential, commercial and industrial customers in southeastern Pennsylvania and in the purchase, distribution and sale of natural gas to residential, commercial and industrial customers in the Pennsylvania counties surrounding Philadelphia. PECO is subject to extensive regulation by the PUC as to electric and gas rates, the issuances of certain securities and certain other aspects of PECO’s operations. PECO is also subject to regulation by the FERC as to transmission rates, gas pipelines and certain other aspects of PECO’s business.
PECO’s retail service territory has an area of approximately 2,100 square miles and an estimated population of 3.8 million. PECO provides electric delivery service in an area of approximately 2,000 square miles, with a population of approximately 3.7 million, including 1.5 million in Philadelphia. Natural gas service is supplied in an area of approximately 1,900 square miles in southeastern Pennsylvania adjacent to Philadelphia, with a population of approximately 2.3 million. PECO delivers electricity to approximately 1.5 million customers and natural gas to approximately 460,000 customers.
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PECO has the necessary authorizations to furnish regulated electric and gas service in the various municipalities or territories in which it now supplies such services. PECO’s authorizations consist of charter rights and certificates of public convenience issued by the PUC and/or “grandfather rights.” These rights are generally unlimited as to time and are generally exclusive from competition from other electric and gas utilities. In a few defined municipalities, PECO’s gas service territory authorizations overlap with that of another gas utility but PECO does not consider those situations as posing a material competitive or financial threat.
Energy Delivery’s kilowatthour (kWh) sales and load of electricity are generally higher during the summer periods and winter periods, when temperature extremes create demand for either summer cooling or winter heating. ComEd’s highest peak load occurred on August 21, 2003 and was 22,054 megawatts (MWs); its highest peak load during a winter season occurred on December 22, 2004 and was 15,222 MWs. PECO’s highest peak load occurred on August 14, 2002 and was 8,164 MWs; its highest peak load during a winter season occurred on December 20, 2004 and was 6,838 MWs.
PECO’s gas sales are generally higher during the winter periods when temperature extremes create demand for winter heating. PECO’s highest daily gas send out occurred on January 17, 2000 and was 718 million cubic feet (mmcf).
Retail Electric Services
Electric utility restructuring legislation was adopted in Pennsylvania in December 1996 and in Illinois in December 1997. Both Illinois and Pennsylvania permit competition by alternative generation suppliers for retail generation supply while transmission and distribution service remains regulated. The legislation and related regulatory orders in both states allow customers to choose an alternative electric generation supplier; required rate reductions and imposed freezes or caps on rates during a transition period following the adoption of the legislation; and allow the collection of competitive transition charges (CTCs) from customers to recover costs that might not otherwise be recovered in a competitive market (stranded costs) during the transition period.
Under Illinois and Pennsylvania legislation, ComEd and PECO are required to provide generation services to customers, except for certain large customers of ComEd, who do not or cannot choose an alternative supplier. Provider of last resort (POLR) obligations refer to the obligation of a utility to provide generation services to those customers who do not take service from an alternative generation supplier or who choose to return to the utility after taking service from an alternative supplier. Because the choice generally lies with the customer, POLR obligations make it difficult for the utility to predict and plan for the level of customers and associated energy demand.
ComEd. All of ComEd’s customers are eligible to choose an alternative electric supplier and most non-residential customers can also elect the power purchase option (PPO) that allows the purchase of electric energy from ComEd at market-based prices. As of December 31, 2004, no alternative electric supplier had approval from the ICC, and no electric utilities had chosen to enter the residential market for the supply of electricity in ComEd’s service territory. At December 31, 2004, approximately 22,100 non-residential customers, representing approximately 35% of ComEd’s annual retail kilowatthour sales, had elected to purchase their electric energy from an alternative electric supplier or had chosen the PPO. Customers who receive energy from an alternative electric supplier and customers who have elected the PPO continue to pay a delivery charge to ComEd, which generally includes a CTC. ComEd is unable to predict the long-term impact of customer choice on its results of operations.
On November 14, 2002, the ICC allowed ComEd, by operation of law, to revise its POLR obligation to be the back-up energy supplier at market-based rates for certain customers with energy demands of at least three MWs. About 370 of ComEd’s largest energy customers are affected,
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representing an aggregate of approximately 2,500 MWs. These customers will not have a right to take bundled service after June 2006 or to return to bundled rates if they choose an alternative supplier prior to June 2006. On March 28, 2003, the ICC approved changes to ComEd’s real-time pricing tariff for non-residential customers, including those with energy demands of at least three MWs who choose hourly energy supply for their electric power and energy. These ICC orders were affirmed on appeal.
In addition to retail competition for generation services, the Illinois legislation provided for residential base rate reductions, a sharing with customers of any earnings over a defined threshold and a base rate freeze, reflecting the residential base rate reductions, through January 1, 2007. A 15% residential base rate reduction became effective on August 1, 1998, and a further 5% residential base rate reduction became effective October 1, 2001. A utility may request a rate increase during the rate freeze period only when necessary to ensure the utility’s financial viability. Under the Illinois legislation, if the two-year average of the earned return on common equity of a utility through December 31, 2006 exceeds an established threshold, one-half of the excess earnings must be refunded to customers. The threshold rate of return on common equity is based on a two-year average of the Monthly Treasury Bond Long-Term Average Rates (20 years and above) plus 8.5% in the years 2000 through 2006. Earnings for purposes of ComEd’s threshold include ComEd’s net income calculated in accordance with accounting principles generally accepted in the United States (GAAP) and reflect the amortization of regulatory assets. Under the Illinois statue, any impairment of goodwill has no impact on the determination of the cap on ComEd’s allowed equity return during the transition period. As a result of the Illinois legislation, at December 31, 2004, ComEd had a regulatory asset related to recoverable transition costs with an unamortized balance of $87 million, which it expects to fully recover and amortize by the end of 2006. Consistent with the provisions of the Illinois legislation, regulatory assets may be recovered in amounts that provide ComEd an earned return on common equity within the Illinois legislation earnings threshold. The earned return on common equity and the threshold return on common equity for ComEd are each calculated on a two-year average basis. ComEd has not triggered the earnings sharing provision through 2004 and does not currently expect to trigger the earnings sharing provision in 2005 or 2006.
ComEd expects its capital expenditures will exceed depreciation on its rate base assets through at least 2005. The base rate freeze, coupled with other provisions of the Illinois restructuring law, generally precludes rate recovery of and on such incremental investments prior to January 1, 2007. Unless ComEd can offset the additional carrying costs against cost reductions, its return on investment will be reduced during the remaining period of the rate freeze and until rate increases are approved authorizing a return of and on this new investment.
The rates for the generation service provided by ComEd under bundled rates are subject to a rate freeze during the transition period ending December 31, 2006. ComEd has entered into a power purchase agreement (PPA) with Generation under which Generation has agreed to supply all of ComEd’s load requirements through 2006. Prices for this energy vary depending upon the time of day and month of delivery. Subsequent to 2006, ComEd expects to procure all of its supply from market sources, which could include Generation.
The Illinois legislation also provided for the collection of a CTC from customers who choose to purchase electric energy from an alternative electric supplier or elect the PPO during the transition period which extends through 2006. The CTC is applied on a cents per kWh basis, considers the revenue that would have been collected from a customer under tariffed rates, reduced by the revenue the utility will receive for providing delivery services to the customer, the market price for electricity and a defined mitigation factor, which represents the utility’s opportunity to develop new revenue sources and achieve cost reductions. The CTC allows ComEd to recover some of its costs that might otherwise be unrecoverable under market-based rates.
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ComEd’s market value energy credit is used to determine the price for specified market-based rate offerings and the amount of the CTC that ComEd is allowed to collect from customers who select an alternative electric supplier or the PPO. The credit was adjusted upwards through agreed upon “adders” which took effect in June 2003 and has had and will continue to have the effect of reducing ComEd’s CTCs to customers. Prior to 2003, all CTCs were subject to annual mid-year adjustments based on the forward market prices for on-peak energy and historical market prices for off-peak energy. The current annual market price adjustment reflects forward, rather than historical, market prices for off-peak energy and allows customers to lock in current levels of CTCs for multi-year periods during the regulatory transition period ending in 2006. These changes provide customers and suppliers greater price certainty and have resulted in an increase in the number of customers electing to purchase energy from alternate suppliers.
In 2004 and 2003, ComEd collected $169 million and $304 million in CTC revenues, respectively. As a result of increasing mitigation factors, changes in energy prices and the ability of certain customers to establish fixed, multi-year CTC rates beginning in 2003, ComEd estimates that CTC revenue will amount to approximately $90 million to $110 million in each of the years 2005 and 2006.
The Illinois legislation provides that an electric utility, such as ComEd, will be liable for actual damages suffered by customers in the event of a continuous power outage of four hours or more affecting 30,000 or more customers and provides for reimbursement of governmental emergency and contingency expenses incurred in connection with any such outage. The legislation bars recovery of consequential damages. The legislation also allows an affected utility to seek relief from these provisions from the ICC when the utility can show that the cause of the outage was unpreventable due to weather events or conditions, customer tampering or third-party causes. During the years 2002, 2003 and 2004, ComEd did not have any outages that triggered the reimbursement requirement.
PECO. Under the Pennsylvania Electricity Generation Customer Choice and Competition Act (Competition Act), all of PECO’s retail electric customers have the right to choose their generation suppliers. At December 31, 2004, approximately 4% of PECO’s residential load, 23% of its small commercial and industrial load and 6% of its large commercial and industrial load were purchasing generation service from alternative generation suppliers. Customers who purchase energy from an alternative electric supplier continue to pay a delivery charge to PECO.
In addition to retail competition for generation services, PECO’s 1998 settlement of its restructuring case mandated by the Competition Act established caps on generation and distribution rates. The 1998 settlement also authorized PECO to recover $5.3 billion of stranded costs and to securitize up to $4.0 billion of its stranded cost recovery, which was subsequently increased to $5.0 billion.
Under the 1998 settlement, PECO’s distribution rates were capped through June 30, 2005 at the level in effect on December 31, 1996. Generation rates, consisting of the charge for stranded cost recovery and a shopping credit or capacity and energy charge, were capped through December 31, 2010. For 2004, the generation rate cap was $0.0698 per kWh, increasing to $0.0751 per kWh in 2006 and $0.0801 per kWh in 2007. The rate caps are subject to limited exceptions, including significant increases in Federal or state taxes or other significant changes in law or regulations that would not allow PECO to earn a fair rate of return. Under the settlement agreement entered into by PECO in 2000 relating to the PUC’s approval of the merger among PECO, Unicom Corporation (Unicom), the former parent company of ComEd, and Exelon (PECO / Unicom Merger), PECO agreed to $200 million in aggregate rate reductions for all customers over the period January 1, 2002 through December 31, 2005 and extended the rate cap on distribution rates through December 31, 2006. The remaining required rate reductions are $40 million in 2005.
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As a mechanism for utilities to recover their allowed stranded costs, the Competition Act provides for the imposition and collection of non-bypassable transition charges on customers’ bills. Transition charges are assessed to and collected from all retail customers who have been assigned stranded cost responsibility and access the utility’s transmission and distribution systems. As the transition charges are based on access to the utility’s transmission and distribution system, they are assessed regardless of whether the customer purchases electricity from the utility or an alternative electric supplier. The Competition Act provides, however, that the utility’s right to collect transition charges is contingent on the continued operation, at reasonable availability levels, of the assets for which the stranded costs were awarded, except where continued operation is no longer cost efficient because of the transition to a competitive market.
PECO has been authorized by the PUC to recover stranded costs of $5.3 billion over a twelve-year period ending December 31, 2010, with a return on the unamortized balance of 10.75%. See the “Business Outlook and the Challenges Managing the Business” section of ITEM 7 of this Form 10-K for the estimated revenues and amortization expense associated with CTC collection and stranded cost recovery through 2010.
Under the Competition Act, licensed entities, including alternative electric suppliers, may act as agents to provide a single bill and provide associated billing and collection services to retail customers located in PECO’s retail electric service territory. In that event, the alternative supplier or other third party replaces the customer as the obligor with respect to the customer’s bill and PECO generally has no right to collect such receivable from the customer. Third-party billing would change PECO’s customer profile (and risk of non-payment by customers) by replacing multiple customers with the entity providing third-party billing for those customers. PUC-licensed entities may also finance, install, own, maintain, calibrate and remotely read advanced meters for service to retail customers in PECO’s retail electric service territory. To date, no third parties are providing billing of PECO’s charges to customers or advanced metering. Only PECO can physically disconnect or reconnect a customer’s distribution service.
PECO has entered into a PPA with Generation under which PECO obtains substantially all of its electric supply from Generation through 2010. Prices for this energy vary depending upon the time of day and month of delivery. Subsequent to 2010, PECO expects to procure all of its supply from market sources, which could include Generation.
In November 2004, Pennsylvania adopted Act 213, the Alternative Energy Portfolio Standards (AEPS) Act of 2004. For more information, see “Environmental Regulation—Renewable and Alternative Energy Portfolio Standards” below.
Transmission Services
Energy Delivery provides wholesale and unbundled retail transmission service under rates established by the FERC. The FERC has used its regulation of transmission to encourage competition for wholesale generation services and the development of regional structures to facilitate regional wholesale markets. Under the FERC’s open transmission access policy promulgated in Order No. 888, ComEd and PECO, as owners of transmission facilities, are required to provide open access to their transmission facilities under filed tariffs at cost-based rates. Under the FERC’s Order No. 889, ComEd and PECO are required to comply with the FERC’s Standards of Conduct regulation, as amended, governing the communication of non-public information between the transmission owner’s transmission employees and wholesale merchant employees or the employees of any energy affiliate of the transmission owner. The FERC recently issued Order No. 2004, amending the Standards of Conduct regulation. The amendments do not detrimentally affect Exelon’s business.
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PJM Interconnection, LLC (PJM) is the independent system operator and the FERC-approved regional transmission organization (RTO) for the Mid-Atlantic and Midwest regions in which it operates. PJM is the transmission provider under, and the administrator of, the PJM Open Access Transmission Tariff (PJM Tariff), operates the PJM Interchange Energy Market and Capacity Credit Markets, and controls through central dispatch the day-to-day operations of the bulk power system of the PJM region. ComEd and PECO are members of PJM, and their transmission systems are currently under the dispatch control of PJM. Under the PJM Tariff, transmission service is provided on a region-wide, open-access basis using the transmission facilities of the PJM members at rates based on the costs of transmission service.
The FERC has attempted to expand the development of regional markets, which has generated substantial opposition from some state regulators and other governmental bodies. In addition, efforts to develop an RTO have been abandoned in certain regions. Notwithstanding these difficulties, the Midwest Independent System Operator, Inc. (MISO), has been certified as an RTO by FERC. MISO is attempting to develop central generation dispatch and transmission operations across the Midwestern United States, contiguous to PJM’s footprint. The FERC has ordered the elimination of rate barriers and protocol differences between MISO and PJM. Exelon supports the development of RTOs and implementation of standard market protocols, but cannot predict their success or whether they will lead to the development of the envisioned large, successful wholesale markets. The development of large competitive wholesale electricity markets would facilitate an auction to meet ComEd’s and PECO’s POLR load obligations with reliable wholesale electricity supply when their PPAs with Generation expire.
In November 2004, the FERC issued two orders authorizing ComEd and PECO to recover from various entities revenue representing amounts ComEd and PECO will lose as a result of the elimination of through and out (T&O) charges, for energy flowing across ComEd’s and PECO’s transmission systems, that were terminated pursuant to the FERC orders effective December 1, 2004. The collection of this revenue will be over a transitional period of December 1, 2004 through March 31, 2006. Several parties have sought rehearing of the FERC orders and there likely will be appeals filed in the matter after the rehearing order is issued. During 2004 prior to the termination of the T&O charges, ComEd and PECO collected net T&O charges of approximately $50 million and $3 million, respectively. As a result of the proceeding, ComEd may see reduced net collections and PECO may become a net payer of these charges. The ultimate outcome of this proceeding is uncertain and may have a material adverse effect on ComEd’s and PECO’s financial condition, results of operations or cash flows.
Certain PJM transmission owners, including ComEd and PECO, are subject to a rate design proceeding before the FERC. The issues in this proceeding involve the methodology used by PJM to charge customers for each PJM transmission owner’s regulated revenue requirement associated with its electric transmission facilities. On January 31, 2005, certain PJM transmission owners, including ComEd and PECO, made two separate filings in which the transmission owners jointly proposed to retain the present modified zonal rate design applicable within PJM and to implement three separate rate options for recovery of the revenue requirement associated with their new and existing facilities. As part of the group of PJM transmission owners, both ComEd and PECO proposed to retain the present rate design through January 2008, at which time the FERC could reevaluate the continuation of the rate design in PJM. The ultimate outcome of this proceeding is uncertain and may have a material adverse effect on ComEd’s and PECO’s financial condition, results of operations or cash flows.
ComEd. On June 2, 2003, ComEd began receiving electric transmission reservation services from PJM and transferred control of ComEd’s Open Access Same Time Information System to PJM. On April 27, 2004, the FERC issued its order approving ComEd’s application to complete its integration
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into PJM, subject to certain stipulations including a provision to hold certain utilities in Michigan and Wisconsin harmless from the associated impacts for ComEd to join PJM. ComEd agreed to these stipulations and transferred functional control of its transmission assets to PJM and integrated fully into PJM’s energy market structures on May 1, 2004. In the fourth quarter of 2004, ComEd entered into settlement agreements with all such Michigan and Wisconsin utilities requiring a total payment of approximately $4 million by ComEd. FERC has approved these agreements and payment is expected to be made in the first quarter of 2005.
On November 10, 2003, the FERC issued an order allowing ComEd to put into effect, subject to refund and rehearing, new transmission rates designed to reflect nearly $500 million of infrastructure improvements made since 1998; however, because of the Illinois retail rate freeze and the method for calculating CTCs, the increase is not expected to have a significant effect on operating revenues until after December 31, 2006. During the third quarter of 2004, a settlement agreement was reached which was approved by the FERC during the fourth quarter of 2004, which established new rates that became effective May 1, 2004.
PECO. PECO provides regional transmission service pursuant to PJM’s regional open-access transmission tariff. PECO and the other transmission owners in PJM have turned over control of their transmission facilities to PJM.
Gas
PECO’s gas sales and gas transportation revenues are derived pursuant to rates regulated by the PUC. PECO’s purchased gas cost rates, which represent a portion of total rates, are subject to quarterly adjustments designed to recover or refund the difference between the actual cost of purchased gas and the amount included in rates.
PECO’s gas customers have the right to choose their gas suppliers or to purchase their gas supply from PECO at cost. Approximately 32% of PECO’s current total yearly throughput is provided by gas suppliers other than PECO. Gas transportation service provided to customers by PECO remains subject to rate regulation. PECO also provides billing, metering, installation, maintenance and emergency response services.
PECO’s natural gas supply is provided by purchases from a number of suppliers for terms of up to eight years. These purchases are delivered under several long-term firm transportation contracts. PECO’s aggregate annual firm supply under these firm transportation contracts is 47.7 million dekatherms. Peak gas is provided by PECO’s liquefied natural gas (LNG) facility and propane-air plant. PECO also has under contract 22.0 million dekatherms of underground storage through service agreements. Natural gas from underground storage represents approximately 29% of PECO’s 2004-2005 heating season planned supplies.
Construction Budget
Energy Delivery’s business is capital intensive and requires significant investments in energy transmission and distribution facilities, and in other internal infrastructure projects. The following table shows Exelon’s most recent estimate of capital expenditures for plant additions and improvements for ComEd and PECO for 2005:
| (in millions) |
ComEd |
PECO | ||||
| Transmission and distribution |
$ | 716 | $ | 210 | ||
| Gas |
— | 62 | ||||
| Other |
26 | 9 | ||||
| Total |
$ | 742 | $ | 281 | ||
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Approximately 50% of ComEd’s and 65% of PECO’s 2005 budgeted capital expenditures are for additions to or upgrades of existing facilities, including improvements to reliability. The remainder of the capital expenditures support customer and load growth.
Generation is one of the largest competitive electric generation companies in the United States, as measured by owned and controlled MWs. Generation combines its large generation fleet with an experienced wholesale power marketing operation and the competitive retail sales business of Exelon Energy Company.
At December 31, 2004, Generation owned generation assets with a net capacity of 25,756 MWs, including 16,751 MWs of nuclear capacity. Generation controls another 8,701 MWs of capacity through long-term contracts.
Generation’s wholesale marketing unit, Power Team, a major wholesale marketer of energy, uses Generation’s energy generation portfolio, transmission rights and expertise to ensure delivery of energy to Generation’s wholesale customers under long-term and short-term contracts, including the load requirements of ComEd and PECO. In addition, Power Team markets energy in the wholesale bilateral and spot markets.
Exelon Energy Company became part of Generation effective as of January 1, 2004. Exelon Energy provides retail electric and gas services as an unregulated retail energy supplier in Illinois, Michigan and Ohio. Exelon Energy’s business is dependent upon continued deregulation of retail electric and gas markets and its ability to obtain supplies of electricity and gas at competitive prices in the wholesale market. The low-margin nature of the business makes it important to service customers with higher volumes so as to manage costs.
Generating Resources
At December 31, 2004, the generating resources of Generation consisted of the following:
| Type of Capacity |
MWs | |
| Owned generation assets (a) |
||
| Nuclear |
16,751 | |
| Fossil (b) |
7,372 | |
| Hydroelectric |
1,633 | |
| Owned generation assets |
25,756 | |
| Long-term contracts (c) |
8,701 | |
| TEG and TEP (d) |
230 | |
| Total generating resources |
34,687 | |
| (a) | See ITEM 1. Business—Generation “Fuel” for sources of fuels used in electric generation. |
| (b) | Included 663 MWs related to directly owned generating assets of Sithe and 222 MWs related to the total capacity of the Southeast Chicago Energy Project. See Note 25 of Exelon’s Notes to Consolidated Financial Statements for additional information regarding the 2005 sale of Sithe. |
| (c) | Contracts range from 4 to 29 years. |
| (d) | Generation, through its investments in Termoeléctrica del Golfo (TEG) and Termoeléctrica Peñoles (TEP), owns 49.5% interests in two facilities in Mexico, each with a capacity of 230 MWs. |
The owned generating resources of Generation are located in the Mid-Atlantic region (approximately 45% of capacity), the Midwest region (approximately 43% of capacity), the Southern
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region (approximately 10%), and the Northeast region (approximately 2% of capacity). The 8,701 MWs of capacity that Generation controls through long-term contracts are in the Midwest, Southeast and South Central regions.
In December 2003, Generation purchased British Energy plc’s (British Energy) 50% interest in AmerGen Energy Company, LLC (AmerGen), making AmerGen a wholly owned subsidiary of Generation. The final purchase price was $267 million after working capital adjustments.
On November 25, 2003, Generation, Reservoir Capital Group (Reservoir) and Sithe completed a series of transactions resulting in Generation and Reservoir each indirectly owning a 50% interest in Sithe with put and call options that could result in either party owning Sithe outright. On September 29, 2004, Generation exercised its call option and entered into an agreement to acquire Reservoir’s 50% interest in Sithe and, on November 1, 2004, Generation entered into an agreement to sell Sithe to Dynegy Inc. The acquisition of Reservoir’s 50% interest in Sithe and the subsequent sale of 100% of Sithe to Dynegy occurred on January 31, 2005. The sale did not include Sithe International Inc. (Sithe International), which was sold to a subsidiary of Generation on October 13, 2004. Sithe International, through its subsidiaries, has 49.5% interests in two Mexican business trusts that own the TEG and TEP power stations, two 230 MW petcoke-fired generating facilities in Tamuín, Mexico. Effective January 26, 2005, Sithe International’s name was changed to Tamuin International Inc. See further discussion of these transactions in Notes 3 and 25 of Exelon’s Notes to Consolidated Financial Statements.
On May 25, 2004, Exelon and Generation completed the sale, transfer and assignment of ownership of their indirect wholly owned subsidiary Boston Generating, LLC (Boston Generating), which owns the companies that own Mystic 4-7, Mystic 8 and 9 and Fore River generating facilities, to a special purpose entity owned by the lenders under Boston Generating’s $1.25 billion credit facility. Responsibility for plant operations and power marketing activities were transferred to the lenders’ special purpose entity and its contractors on September 1, 2004. See Note 2 of Exelon’s Notes to Consolidated Financial Statements for additional information regarding the sale of Boston Generating.
Nuclear Facilities
Generation has ownership interests in eleven nuclear generating stations currently in service, consisting of 19 units with 16,751 MW of capacity. For additional information, see ITEM 2. Properties. Generation’s nuclear generating stations are operated by Generation, with the exception of the two units at the Salem Generating Station (Salem), which are operated by PSEG Nuclear, LLC, an indirect, wholly owned subsidiary of PSEG. AmerGen operates the Clinton Nuclear Power Station, Three Mile Island (TMI) Unit 1 and Oyster Creek Nuclear Generating Station facilities.
Effective January 17, 2005, through an Operating Services Contract (OSC), Generation began overseeing daily plant operations at Salem and Hope Creek nuclear generating stations. Hope Creek is a PSEG wholly owned nuclear generating station. Under the OSC, PSEG Nuclear, LLC will continue as the license holder with exclusive legal authority to operate and maintain the plants, will retain responsibility for management oversight and will have full authority with respect to the marketing of its share of the output from the facilities.
In 2004, over 67% of Generation’s electric supply was generated from the nuclear generating facilities. During 2004 and 2003, the nuclear generating facilities operated by Generation operated at weighted average capacity factors of 93.5% and 93.4%, respectively.
Licenses. Generation has 40-year operating licenses from the NRC for each of its nuclear units and has received 20-year operating license renewals for the Peach Bottom Units 2 and 3, Dresden
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Units 2 and 3, and the Quad Cities Units. In December 2004, the NRC issued an order that will permit Oyster Creek to operate beyond its license expiration in April 2009 if the NRC has not completed reviewing the application for renewal. The application for Oyster Creek’s license renewal is expected to be filed by August 2005 in order to comply with this agreement. Generation is currently evaluating the other nuclear units for possible license renewal. The operating license renewal process takes approximately four to five years from the commencement of the project until completion of the NRC’s review. The NRC review process takes approximately two years from the docketing of an application. Each requested license renewal is expected to be for 20 years beyond the current license expiration. Depreciation provisions are based on the estimated useful lives of the stations, which assume the renewal of the operating licenses for all of Generation’s operating nuclear generating stations.
In 2004, Generation joined a consortium of eleven companies, NuStart Energy Development, LLC, which was formed for the purpose of seeking a license to build a new nuclear facility under the NRC’s new permitting process.
The following table summarizes the current operating license expiration dates for Generation’s nuclear facilities in service:
| Station |
Unit |
In-Service Date |
Current License Expiration | |||
| Braidwood |
1 | 1988 | 2026 | |||
| 2 | 1988 | 2027 | ||||
| Byron |
1 | 1985 | 2024 | |||
| 2 | 1987 | 2026 | ||||
| Clinton |
1 | 1987 | 2026 | |||
| Dresden |
2 | 1970 | 2029 | |||
| 3 | 1971 | 2031 | ||||
| LaSalle |
1 | 1984 | 2022 | |||
| 2 | 1984 | 2023 | ||||
| Limerick |
1 | 1986 | 2024 | |||
| 2 | 1990 | 2029 | ||||
| Oyster Creek |
1 | 1969 | 2009 | |||
| Peach Bottom |
2 | 1974 | 2033 | |||
| 3 | 1974 | 2034 | ||||
| Quad Cities |
1 | 1973 | 2032 | |||
| 2 | 1973 | 2032 | ||||
| Salem |
1 | 1977 | 2016 | |||
| 2 | 1981 | 2020 | ||||
| Three Mile Island |
1 | 1974 | 2014 |
Regulation of Nuclear Power Generation. Generation is subject to the jurisdiction of the NRC with respect to the operation of its nuclear generating stations, including the licensing of operation of each station. The NRC subjects nuclear generating stations to continuing review and regulation covering, among other things, operations, maintenance, emergency planning, security and environmental and radiological aspects of those stations. The NRC may modify, suspend or revoke operating licenses and impose civil penalties for failure to comply with the Atomic Energy Act, the regulations under such Act or the terms of such licenses. Changes in regulations by the NRC may require a substantial increase in capital expenditures for nuclear generating facilities or increased operating costs of nuclear generating units.
NRC reactor oversight results for the fourth quarter of 2004 indicate that the performance indicators for the nuclear plants operated by Generation are all in the highest performance band.
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Nuclear Waste Disposal. There are no facilities for the reprocessing or permanent disposal of spent nuclear fuel (SNF) currently in operation in the United States, nor has the NRC licensed any such facilities. Generation currently stores all SNF generated by nuclear generating facilities in on-site storage pools and, in the case of Peach Bottom, Oyster Creek and Dresden, some SNF has been placed in dry cask storage facilities. Not all of Generation’s SNF storage pools have sufficient storage capacity for the life of the plant. Generation is developing dry cask storage facilities, as necessary, to support operations.
As of December 31, 2004, Generation had 43,156 SNF assemblies (10,360 tons) stored on site in SNF pools or dry cask storage. On-site dry cask storage in concert with on-site storage pools will be capable of meeting all current and future SNF storage requirements at Generation’s sites. The following table describes the current status of Generation’s SNF storage facilities.
| Site |
Date for loss of full core reserve (a) | |
| Dresden |
Dry cask storage in operation | |
| Quad Cities (b) |
2004 | |
| Byron |
2011 | |
| LaSalle |
2012 | |
| Braidwood |
2013 | |
| Clinton (c) |
2006 | |
| Peach Bottom |
Dry cask storage in operation | |
| Limerick |
2009 | |
| Oyster Creek |
Dry cask storage in operation | |
| Three Mile Island |
Life of plant storage capable in SNF pool | |
| Salem |
2011 |
| (a) | The date for loss of full core reserve identifies when the on-site storage pool will no longer have sufficient space to discharge a full complement of fuel from the reactor core. |
| (b) | Dry cask storage to begin operation in 2005. |
| (c) | A modification to the on-site storage pool is in progress to increase the amount of SNF that can be stored in the pool. This will move the date for loss of full core reserve at Clinton out to approximately 2012. |
Under the Nuclear Waste Policy Act of 1982 (NWPA), the U.S. Department of Energy (DOE) is responsible for the development of a repository for and the disposal of SNF and high-level radioactive waste. As required by the NWPA, Generation is a party to contracts with the DOE (Standard Contracts) to provide for disposal of SNF from its nuclear generating stations. In accordance with the NWPA and the Standard Contracts, Generation pays the DOE one mill ($.001) per kWh of net nuclear generation for the cost of SNF disposal. This fee may be adjusted prospectively in order to ensure full cost recovery. The NWPA and the Standard Contracts required the DOE to begin taking possession of SNF generated by nuclear generating units by no later than January 31, 1998. The DOE, however, failed to meet that deadline and its performance will be delayed significantly. The DOE’s current estimate for opening a SNF permanent disposal facility is 2012. This extended delay in SNF acceptance by the DOE has led to Generation’s adoption of dry cask storage at its Dresden, Quad Cities, Peach Bottom and Oyster Creek Stations and its consideration of dry cask storage at other stations. See Note 14 of Exelon’s Notes to Consolidated Financial Statements for additional information regarding spent fuel storage claims and issues.
During the third quarter of 2004, Exelon and the U.S. Department of Justice, in close consultation with the DOE, reached a settlement of a suit originally commenced by ComEd in 1998. Under the settlement, the government will reimburse Exelon for costs associated with storage of spent fuel at Generation’s nuclear stations pending DOE’s fulfilment of its obligations to take possession of SNF. Under the settlement agreement, Generation received $80 million in gross reimbursements for storage
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costs already incurred ($53 million net, after considering amounts due from Exelon to co-owners of certain nuclear stations), with additional amounts to be reimbursed annually for future costs. In all cases, reimbursements will be made only after costs are incurred and only for costs resulting from DOE delays in accepting the SNF.
The Standard Contracts with the DOE also required the payment to the DOE of a one-time fee applicable to nuclear generation through April 6, 1983. The fee related to the former PECO units has been paid. Pursuant to the Standard Contracts, ComEd previously elected to pay the one-time fee of $277 million for its units (which are now part of Generation), with interest to the date of payment, just prior to the first delivery of SNF to the DOE. As of December 31, 2004, the unfunded liability for the one-time fee with interest (which has been assumed by Generation) was $878 million. Interest accrues at the 13-week Treasury Rate, which was 1.987% at December 31, 2004. The outstanding one-time fee obligation for the Oyster Creek and TMI units remains with the former owner. The Clinton unit has no outstanding obligation.
As a by-product of their operations, nuclear generating units produce low-level radioactive waste (LLRW). LLRW is accumulated at each generating station and permanently disposed of at Federally licensed disposal facilities. The Federal Low-Level Radioactive Waste Policy Act of 1980 provides that states may enter into agreements to provide regional disposal facilities for LLRW and restrict use of those facilities to waste generated within the region. Illinois and Kentucky have entered into an agreement, although neither state currently has an operational site and none is currently expected to be operational until after 2011. Pennsylvania, which had agreed to be the host site for LLRW disposal facilities for generators located in Pennsylvania, Delaware, Maryland and West Virginia, has suspended the search for a permanent disposal site.
Generation has temporary on-site storage capacity at its nuclear generation stations for limited amounts of LLRW and has been shipping its LLRW to disposal facilities in South Carolina and Utah. The number of LLRW disposal facilities is decreasing, and Generation anticipates the possibility of continuing difficulties in disposing of LLRW. Generation is pursuing alternative disposal strategies for LLRW, including a LLRW reduction program to minimize cost impacts.
The National Energy Policy Act of 1992 requires that the owners of nuclear reactors pay for the decommissioning and decontamination of the DOE uranium enrichment facilities. The total cost to all domestic utilities covered by this requirement was originally $150 million per year through 2006, of which Generation’s share was approximately $20 million per year. Payments are adjusted annually to reflect inflation. Including the effect of inflation, Generation paid $26 million in 2004.
Nuclear Insurance. The Price-Anderson Act limits the liability of nuclear reactor owners for claims that could arise from a single incident. As of December 31, 2004, the current limit was $10.76 billion and is subject to change to account for the effects of inflation and changes in the number of licensed reactors. As required by the Price-Anderson Act, Generation carries the maximum available amount of nuclear liability insurance (currently $300 million for each operating site) and the remaining $10.46 billion is provided through mandatory participation in a financial protection pool. Under the Price-Anderson Act, all nuclear reactor licensees can be assessed a maximum charge per reactor per incident. The maximum assessment for all nuclear operators per reactor per incident (including a 5% surcharge) is $100.6 million, payable at no more than $10 million per reactor per incident per year. This assessment is subject to inflation and state premium taxes. In addition, the U.S. Congress could impose revenue-raising measures on the nuclear industry to pay claims.
The Price-Anderson Act expired on August 1, 2002 and was subsequently extended to the end of 2003 by the U.S. Congress. Only facilities applying for NRC licenses subsequent to the expiration of the Price-Anderson Act are affected by the expiration of the Price-Anderson Act. Existing commercial
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generating facilities, such as those owned and operated by Generation, remain subject to the provisions of the Price-Anderson Act and are unaffected by its expiration. However, new licenses are not covered under the Price-Anderson Act and any new plant initiatives would need to address this exposure.
See “Nuclear Insurance” within Note 16 of Generation’s Notes to Consolidated Financial Statements for a description of nuclear-related insurance coverage.
For information regarding property insurance, see ITEM 2. Properties—Generation. Generation is self-insured to the extent that any losses may exceed the amount of insurance maintained. Such losses could have a material adverse effect on Generation’s financial condition and results of operations.
Decommissioning. NRC regulations require that licensees of nuclear generating facilities demonstrate reasonable assurance that funds will be available in certain minimum amounts at the end of the life of the facility to decommission the facility. As more fully described below, both ComEd and PECO are currently collecting amounts from ratepayers, which are ultimately remitted to the trust funds maintained by Generation that will be used to decommission nuclear facilities. The AmerGen facilities are not covered by the ComEd, PECO or any other rate recovery of decommissioning funding from customers. Decommissioning expenditures are expected to occur primarily after the plants are retired. Based on current operating licenses and anticipated license renewals, decommissioning expenditures for plants in operation are currently estimated to begin in 2029.
In connection with the transfer of ComEd’s nuclear generating stations to Generation, ComEd asked the ICC to approve the continued recovery of decommissioning costs after the transfer. On December 20, 2000, the ICC issued an order finding that the ICC has the legal authority to permit ComEd to continue to recover decommissioning costs from customers for the six-year term of the PPA between ComEd and Generation. Under the ICC order, ComEd was permitted to recover $73 million per year from customers for decommissioning for the years 2001 through 2004. In 2005 and 2006, ComEd is permitted to recover up to $73 million annually, depending upon the portion of the output of the former ComEd nuclear stations that ComEd purchases from Generation. Because ComEd is not expected to take all of the output of these stations, actual collections are expected to be less than $73 million annually in 2005 and 2006. Under the ICC order, subsequent to 2006, there will be no further recoveries though rates of decommissioning costs from ComEd’s customers. The ICC order also provides that any surplus funds after the nuclear stations are decommissioned must be refunded to ComEd’s customers. The ICC order has been upheld on appeal.
Nuclear decommissioning costs associated with the nuclear generating stations formerly owned by PECO continue to be recovered currently through rates charged by PECO to customers. Amounts recovered, currently $33 million per year, are remitted to Generation as allowed by the PUC.
Generation believes that the amounts currently being collected from ComEd and PECO, coupled with Generation’s nuclear decommissioning trust funds and the expected investment earnings thereon will be sufficient to fully fund Generation’s decommissioning obligations. AmerGen maintains decommissioning trust funds for each of its plants in accordance with NRC regulations. Generation believes that amounts in these trust funds, including expected investment earnings thereon, will be sufficient to fully fund AmerGen’s decommissioning obligations.
See Critical Accounting Policies and Estimates within ITEM 7.—Management’s Discussion and Analysis of Financial Condition and Results of Operation—Generation for a further discussion of nuclear decommissioning.
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Zion, a two-unit nuclear generation station, Peach Bottom Unit 1 and Dresden Unit 1 have permanently ceased power generation. SNF at Zion and Dresden Unit 1 is currently being stored in on-site storage pools and dry cask storage, respectively, until a permanent repository under the NWPA is completed. All of Peach Bottom Unit 1’s SNF has been moved off site. Generation has recorded a liability totaling $762 million at December 31, 2004, which represents the estimated cost of decommissioning Zion, Peach Bottom Unit 1 and Dresden Unit 1 in current year dollars. Certain decommissioning costs are currently being incurred; however, the majority of decommissioning expenditures are expected to occur primarily after 2013, 2033 and 2030 for Zion, Peach Bottom Unit 1 and Dresden Unit 1, respectively.
Fossil and Hydroelectric Facilities
Generation operates various fossil and hydroelectric facilities and maintains ownership interest in several other facilities such as La Porte, Keystone, Conemaugh and Wyman, which are operated by third parties. In 2004, approximately 8% of Generation’s electric supply was generated from Generation’s owned fossil and hydroelectric generating facilities. The majority of this output was dispatched to support Generation’s power marketing activities. For additional information regarding Generation’s electric generating facilities, see ITEM 2. Properties—Generation.
Licenses. Fossil generation plants are generally not licensed and, therefore, the decision on when to retire plants is, fundamentally, a commercial one. Hydroelectric plants are licensed by the FERC. The Muddy Run and Conowingo facilities have licenses that expire in September 2014. Generation is considering applying to the FERC for license renewals of 40 years for the Muddy Run and Conowingo plants, but the duration of any license renewal will depend on then-current policies at the FERC. The processing of a renewal to a hydroelectric license generally takes at least eight years.
Insurance. Generation does not purchase business interruption insurance for its wholly owned fossil and hydroelectric operations. For its other types of insured losses, Generation is self-insured to the extent that losses are within the policy deductible or exceed the amount of insurance maintained. Such losses could have a material adverse effect on Exelon and Generation’s financial condition and their results of operations and cash flows. For information regarding property insurance, see ITEM 2. Properties—Generation.
Long-Term Contracts
In addition to energy produced by owned generation assets, Generation sells electricity purchased under the long-term contracts described below:
| Seller |
Location |
Expiration |
Capacity (MWs) | |||
| Kincaid Generation, LLC |
Kincaid, Illinois | 2013 | 1,108 | |||
| Tenaska Georgia Partners, LP |
Franklin, Georgia | 2030 | 925 | |||
| Tenaska Frontier, Ltd |
Shiro, Texas | 2020 | 830 | |||
| Green Country Energy, LLC |
Jenks, Oklahoma | 2022 | 795 | |||
| Elwood Energy, LLC |
Elwood, Illinois | 2012 | 772 | |||
| Lincoln Generating Facility, LLC |
Manhattan, Illinois | 2011 | 664 | |||
| Reliant Energy Aurora, LP |
Aurora, Illinois | 2008 | 600 | |||
| Others |
Various | 2005 to 2021 | 3,007 | |||
| Total |
8,701 | |||||
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Federal Power Act
The Federal Power Act gives the FERC exclusive rate-making jurisdiction over wholesale sales of electricity and the transmission of electricity in interstate commerce. Pursuant to the Federal Power Act, all public utilities subject to the FERC’s jurisdiction are required to file rate schedules with the FERC with respect to wholesale sales and transmission of electricity. Transmission tariffs established under FERC regulation give Generation access to transmission lines that enable it to participate in competitive wholesale markets.
Because Generation sells power in the wholesale markets, Generation is a public utility for purposes of the Federal Power Act and is required to obtain the FERC’s acceptance of the rate schedules for wholesale sales of electricity. In 2000, Generation received authorization from the FERC to sell power at market-based rates. As is customary with market-based rate schedules, the FERC reserved the right to suspend market-based rate authority on a retroactive basis if it subsequently determined that Generation or any of its affiliates exercised or has the ability to exercise market power. The FERC is also authorized to order refunds if it finds that the market-based rates are not just and reasonable.
In December 1999, the FERC issued Order No. 2000 to encourage the voluntary formation of RTOs which would provide transmission service across multiple transmission systems. The intended benefits of establishing these entities includes the development of larger wholesale markets and the elimination or reduction of transmission charges imposed by successive transmission systems when wholesale generators cross several transmission systems to deliver capacity. Order No. 2000 and the FERC’s effort to promote RTOs throughout the states have generated substantial opposition by some state regulators and other governmental bodies. In addition, efforts to develop a RTO have been abandoned in certain regions.
PJM has been approved as a RTO, as has the Midwest ISO. ISO New England, the system operator for New England where Generation also owns facilities, was approved as a RTO on February 2, 2005.
Exelon supports the development of RTOs and implementation of standard market protocols but cannot predict their success or whether they will lead to the development of the envisioned large, successful wholesale markets. The FERC issued a final rule establishing standardized generator interconnection policies and procedures. Under this interconnection policy generators will benefit from not having to deal on a case-by-case basis with different and sometimes inconsistent requirements of different transmission providers.
The FERC recently announced new market power tests for suppliers to qualify to sell power at market-based rates. These new tests, the market share test and the pivotal supplier test, must both be passed by Generation, or market power mitigation must be imposed for Generation to continue to make sales of capacity and energy in the wholesale market at market based rates. Generation filed its analysis of the application of the tests on September 27, 2004, which proposed that Generation passed the market power screens. The FERC allows the relevant geographic market to include a RTO’s footprint, and Generation used an expanded PJM footprint as the relevant market. Because ComEd and PECO, which purchase most of Generation’s power, are members of PJM, Generation, for the most part, is selling into the PJM market. On January 5, 2005, the FERC issued a deficiency letter to Generation requesting a response to twelve separate questions relating to Generation’s filing. On January 26, 2005, Generation filed an initial response to the deficiency letter, answering certain questions and requesting until February 14, 2005 to complete the response to the deficiency letter. The FERC continues to process Generation’s application and market power analysis, as well as other applicants’ filings. Management expects that Generation will eventually pass the market power
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screens; however, there is no certainty as to what final determination will be made by the FERC in regard to Generation’s filing and the filings of other applicants.
Currently, a significant portion of Generation’s capacity is located within the PJM RTO area. If the FERC were to suspend Generation’s market-based rate authority, Generation would be required to supply and implement a plan for mitigation of market power. FERC’s default mitigation would require Generation to file and obtain FERC acceptance of cost-based rate schedules or schedules tied to a public index. In addition, the loss of market-based rate authority would subject Generation to the accounting, record-keeping and reporting requirements that are imposed on public utilities with cost-based rate schedules.
Fuel
The following table shows sources of electric supply in gigawatthours (GWhs) for 2004 and estimated for 2005:
| Source of Electric Supply | ||||
| 2004 |
2005 (Est.) | |||
| Nuclear units |
136,621 | 137,870 | ||
| Purchases—non-trading portfolio |
48,968 | 44,479 | ||
| Fossil and hydroelectric units |
17,010 | 21,325 | ||
| Total supply |
202,599 | 203,674 | ||
The fuel costs for nuclear generation are substantially less than for fossil-fuel generation. Consequently, nuclear generation is generally the most cost-effective way for Generation to meet its commitment to supply the requirements of ComEd and PECO, some of Exelon Energy’s requirements, and for sales to other utilities.
The cycle of production and utilization of nuclear fuel includes the mining and milling of uranium ore into uranium concentrates, the conversion of uranium concentrates to uranium hexafluoride, the enrichment of the uranium hexafluoride and the fabrication of fuel assemblies. Generation has uranium concentrate inventory and supply contracts sufficient to meet all of its uranium concentrate requirements through 2007. Generation’s contracted conversion services are sufficient to meet all of its uranium conversion requirements through 2007. All of Generation’s enrichment requirements have been contracted through 2007. Contracts for fuel fabrication have been obtained through 2007. Generation does not anticipate difficulty in obtaining the necessary uranium concentrates or conversion, enrichment or fabrication services for its nuclear units.
Generation obtains approximately 25% of its uranium enrichment services from European suppliers. There is an ongoing trade action by USEC, Inc. alleging dumping in the United States against European enrichment services suppliers. In January 2002, the U.S. International Trade Commission determined that USEC, Inc. was “materially injured or threatened with material injury” by low-enriched uranium exported by European suppliers. The U.S. Department of Commerce has assessed countervailing and anti-dumping duties against the European suppliers. Both USEC, Inc. and the European suppliers have appealed these decisions. Generation is uncertain at this time as to the outcome of the pending appeals; however, as a result of these actions, Generation may incur higher costs for uranium enrichment services necessary for the production of nuclear fuel.
Coal is obtained for coal-fired plants primarily through annual contracts with the remainder supplied through either short-term contracts or spot-market purchases.
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Natural gas requirements for operating stations are procured through annual, monthly and spot-market purchases. Some fossil generation stations can use either oil or gas as fuel. Fuel oil inventories are managed so that in the winter months sufficient volumes of fuel are available in the event of extreme weather conditions and during the remaining months to take advantage of favorable market pricing.
Generation uses financial instruments to mitigate price risk associated with commodity price exposures. Generation also hedges forward price risk with both over-the-counter and exchange-traded instruments.
Power Team
Generation’s wholesale operations include the physical delivery and marketing of power obtained through its generation capacity, and long-, intermediate- and short-term contracts. Generation seeks to maintain a net positive supply of energy and capacity, through ownership of generation assets and power purchase and lease agreements, to protect it from the potential operational failure of one of its owned or contracted power generating units. Generation has also contracted for access to additional generation through bilateral long-term PPAs. These agreements are commitments related to power generation of specific generation plants and/or are dispatchable in nature similar to asset ownership. Generation enters into PPAs with the objective of obtaining low-cost energy supply sources to meet its physical delivery obligations to customers. Power Team may buy power to meet the energy demand of its customers, including Energy Delivery. These purchases may be made for more than the energy demanded by Power Team’s customers. Power Team then sells this open position, along with capacity not used to meet customer demand, in the wholesale energy market. Generation has also purchased transmission service to ensure that it has reliable transmission capacity to physically move its power supplies to meet customer delivery needs.
Power Team also manages the price and supply risks for energy and fuel associated with generation assets and the risks of power marketing activities. The maximum length of time over which cash flows related to energy commodities are currently being hedged is three years. Generation’s hedge ratio in 2005 for its energy marketing portfolio is approximately 90%. This hedge ratio represents the percentage of forecasted aggregate annual generation supply that is committed to firm sales, including sales to Energy Delivery’s retail load. The hedge ratio is not fixed and will vary from time to time depending upon market conditions, demand and volatility. During peak periods, the amount hedged declines to assure Generation’s commitment to meet Energy Delivery’s demand, for which the peak demand is during the summer. For the portion of generation supply that is unhedged, fluctuations in market price of energy will cause volatility in Generation’s results of operations.
Power Team also uses financial and commodity contracts for proprietary trading purposes but this activity accounts for only a small portion of Power Team’s efforts. The trading portfolio is subject to a risk management policy that includes stringent risk management limits including volume, stop-loss and value-at-risk limits to manage exposure to market risk. Additionally, the corporate risk management group and Exelon’s Risk Management Committee (RMC) monitor the financial risks of the power marketing activities.
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At December 31, 2004, Generation’s long-term commitments, relating to the purchase and sale of energy, capacity and transmission rights from and to unaffiliated utilities and others were as follows:
| (in millions) |
Net Capacity Purchases (a) |
Power Only Sales |
Power Only Purchases from Non-Affiliates |
Transmission Rights | ||||||||
| 2005 |
$ | 578 | $ | 2,551 | $ | 1,446 | $ | 31 | ||||
| 2006 |
581 | 961 | 605 | 3 | ||||||||
| 2007 |
533 | 167 | 254 | — | ||||||||
| 2008 |
462 | 9 | 195 | — | ||||||||
| 2009 |
437 | 9 | 194 | — | ||||||||
| Thereafter |
3,664 | 343 | 548 | — | ||||||||
| Total (c) |
$ | 6,255 | $ | 4,040 | $ | 3,242 | $ | 34 | ||||
| (a) | Net capacity purchases include tolling agreements that are accounted for as operating leases. Amounts presented in the commitments represent Generation’s expected payments under these arrangements at December 31, 2004. Expected payments include certain capacity charges which are conditional on plant availability. |
| (b) | Transmission rights purchases include estimated commitments in 2005 and 2006 for additional transmission rights that will be required to fulfill firm sales contracts. |
| (c) | Included in the totals are $395 million of power only sales commitments related to Sithe, which were not retained by Generation following the sale of Sithe. See Note 3 and Note 25 of Exelon’s Notes to Consolidated Financial Statements for further discussion of these transactions. |
In connection with the 2001 corporate restructuring, Generation entered into a PPA, as amended, with ComEd under which Generation has agreed to supply all of ComEd’s load requirements through 2006. Under the ComEd PPA, prices for energy vary depending upon the time of day and month of delivery. Subsequent to 2006, ComEd expects to procure all of its supply from market sources, which could include Generation. Additionally, Generation has a PPA with PECO under which Generation has agreed to supply PECO with substantially all of PECO’s electric supply needs through 2010. PECO has also assigned its rights and obligations under various PPAs and fuel supply agreements to Generation. Generation supplies power to PECO from the transferred generation assets, assigned PPAs and other market sources. Subsequent to 2010, PECO expects to procure all of its supply from market sources, which could include Generation.
When AmerGen acquired Clinton Nuclear Power Station (Clinton), AmerGen entered into a power sales agreement with the seller, Illinois Power Company (Illinois Power). The agreement with Illinois Power was for 68.8% of Clinton’s output for a term that expired on December 31, 2004. Generation has subsequently entered into a separate agreement with Illinois Power to provide fixed quantities of power under a power sales agreement over future periods beginning January 1, 2005. This agreement is included in the commitment table presented above.
Capital Expenditures
Generation’s business is capital intensive and requires significant investments in energy generation and in other internal infrastructure projects. Generation’s estimated capital expenditures for 2005 are as follows:
| (in millions) |
|||
| Production plant |
$ | 575 | |
| Nuclear fuel |
498 | ||
| Total |
$ | 1,073 | |
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During 2004 and 2003, Enterprises exited a significant number of businesses and investments, as described below. As of December 31, 2004, Enterprises consisted primarily of the remaining electrical contracting business of F&M Holdings, LLC. Enterprises is continuing to pursue opportunities to sell its remaining businesses.
Exelon Energy Company. Effective January 1, 2004, Enterprises competitive retail sales business, Exelon Energy Company, was transferred to Generation.
InfraSource, Inc. On September 24, 2003, Enterprises sold the electric construction and services, underground and telecom businesses of InfraSource, Inc. for cash proceeds of approximately $175 million, net of transaction costs and cash transferred to the buyer upon sale plus a $30 million subordinated note. Enterprises recorded a net pre-tax loss and minority interest of $4 million associated with the sale and goodwill impairment charge in 2003.
Exelon Services, Inc. During 2004, Enterprises disposed of or wound down all of the operating businesses of Exelon Services, Inc. (Exelon Services), including Exelon Solutions, the mechanical services businesses and the Integrated Technology Group. Total expected proceeds and the pre-tax net gain on sale recorded in 2004 related to the disposition of the Exelon Services businesses were $61 million and $9 million, respectively.
Exelon Thermal Holdings, Inc. On June 30, 2004, Enterprises sold its Chicago businesses of Exelon Thermal Holdings, Inc. (Thermal) for net cash proceeds of $134 million and expected proceeds of $2 million from a working capital settlement, resulting in a pre-tax gain of $36 million, net of debt prepayment penalties. On September 29, 2004, Enterprises closed on the sale of ETT Nevada, Inc., the holding company for its investment in Northwind Aladdin, LLC, for a net cash outflow of $1 million, subject to working capital adjustments. Enterprises recorded a pre-tax loss of $3 million related to the disposition. On October 28, 2004, Northwind Windsor, of which Enterprises owns a 50% interest, sold substantially all of its assets, providing Enterprises with cash proceeds of $8 million, resulting in a pre-tax gain of $2 million.
PECO TelCove. On June 30, 2004, Enterprises sold its investment in PECO TelCove, a communications joint venture, along with certain telecommunications assets, for proceeds of $49 million, resulting in a pre-tax gain of $9 million.
Exelon Capital Partners Holdings, LLC. During 2004, Enterprises sold its direct investments and investments in three of its four venture capital funds.
As of December 31, 2004, Exelon and its subsidiaries had approximately 17,300 employees in the following companies:
| ComEd |
5,600 | |
| PECO |
2,100 | |
| Generation |
7,500 | |
| Enterprises |
100 | |
| Corporate (a) |
2,000 | |
| Total |
17,300 | |
| (a) | Includes shared services employees. |
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Approximately 5,500 employees, including 3,800 employees of ComEd, 1,600 employees of Generation and 100 employees of BSC, are covered by collective bargaining agreements (CBAs) with Local 15 of the International Brotherhood of Electrical Workers (IBEW Local 15). AmerGen has separate CBAs for each of its nuclear facilities, which cover an aggregate of approximately 700 employees. The Generation CBA with IBEW Local 15 has been extended to September 30, 2007. The CBA for ComEd and BSC expires on September 30, 2008. The Clinton, Oyster Creek and TMI CBAs expire on December 15, 2005, January 31, 2006 and February 28, 2009, respectively. Exelon Power, an operating unit of Generation, has negotiated and ratified its first agreement with IBEW Local 614. The agreement expires on January 31, 2008 and covers approximately 200 employees.
In addition to IBEW Local 15, IBEW Local 614 and the four IBEW locals covering the AmerGen facilities, approximately 50 Generation employees are represented by the Utility Workers Union of America.
During 2004, two elections were held at PECO which resulted in union representation for approximately 1,100 employees in the Philadelphia service territory. PECO and IBEW Local 614 will begin negotiations for an initial agreement in the first quarter of 2005.
The employees of the Limerick and Peach Bottom nuclear stations are not currently covered by a CBA. IBEW 614 has filed a petition with the National Labor Relations Board to hold a certification election at these sites. The election will be held in the first quarter of 2005.
General
Specific operations of Exelon, primarily those of ComEd, PECO and Generation, are subject to regulation regarding environmental matters by the United States and by various states and local jurisdictions where Exelon operates its facilities. The United States Environmental Protection Agency (EPA) administers certain Federal statutes relating to such matters, as do various interstate and local agencies. The Illinois Pollution Control Board (IPCB) has jurisdiction over environmental control in the State of Illinois, together with the Illinois Environmental Protection Agency, which enforces regulations of the IPCB and issues permits in connection with environmental control. The Pennsylvania Department of Environmental Protection (PDEP) has jurisdiction over environmental control in the Commonwealth of Pennsylvania. The Texas Commission on Environmental Quality has jurisdiction in Texas, and the Massachusetts Department of Environmental Protection has jurisdiction in Massachusetts. State regulation includes the authority to regulate air, water and noise emissions and solid waste disposals.
Water
Under the Federal Clean Water Act, National Pollutant Discharge Elimination System (NPDES) permits for discharges into waterways are required to be obtained from the EPA or from the state environmental agency to which the permit program has been delegated. Those permits must be renewed periodically. Generation either has NPDES permits for all of its generating stations or has pending applications for renewals of such permits while operating under an administrative extension.
In July 2004, the EPA issued the final Phase II rule implementing Section 316(b) of the Clean Water Act. This rule establishes national requirements for reducing the adverse environmental impacts from the entrainment and impingement of aquatic organisms at existing power plants. The rule identifies particular standards of performance with respect to entrainment and impingement and requires each facility to monitor and validate this performance in future years. The requirements will be
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implemented through state-level NPDES permit programs. All of Generation’s power generation facilities with cooling water systems are subject to the regulations. Facilities without closed-cycle recirculating systems are potentially most affected. Those facilities are Clinton, Cromby, Dresden, Eddystone, Fairless Hills, Handley, Mountain Creek, New Boston, Oyster Creek, Peach Bottom, Quad Cities and Salem. Generation is currently evaluating compliance options at its affected plants. At this time, Generation cannot estimate the effect that compliance with the Phase II rule requirements will have on the operation of its generating facilities and its future results of operations, financial condition and cash flows. There are many factors to be considered and evaluated to determine how Generation will comply with the Phase II rule requirements and the extent to which such compliance may result in financial and operational impacts. The considerations and evaluations include, but are not limited to obtaining clarifying interpretations of the requirements from state regulators, resolving outstanding litigation proceedings concerning the requirements, completing studies to establish biological baselines for each facility, and performing environmental and economic cost benefit evaluation of the potential compliance alternatives in accordance with the requirements. Generation is also subject to the jurisdiction of certain other state and interstate agencies, including the Delaware River Basin Commission and the Susquehanna River Basin Commission.
In June 2001, the New Jersey Department of Environmental Protection (NJDEP) issued a renewed National Pollutant Discharge Elimination System permit for Salem, expiring in July 2006, allowing for the continued operation of Salem with its existing cooling water system. An application for renewal of that permit, including a demonstration of compliance with the requirements of the recently published Federal Water Pollution Control Act Section 316(b) regulations, must be submitted to NJDEP by February 2, 2006 unless NJDEP grants additional time to collect information to comply with the new regulations. NJDEP advised PSEG in a letter dated July 12, 2004 that it strongly recommends reducing cooling water intake flow commensurate with closed-cycle cooling as a compliance option for Salem. PSEG has not made a determination regarding how it will demonstrate compliance with the Section 316(b) regulations. If application of the Section 316(b) regulations requires the retrofitting of Salem’s cooling water intake structure to reduce cooling water intake flow commensurate with closed-cycle cooling, the retrofit and an resulting cost of interim replacement power could result in material costs of compliance to the owners of the facility.
Solid and Hazardous Waste
The Comprehensive Environmental Response, Compensation and Liability Act of 1980, as amended (CERCLA), provides for immediate response and removal actions coordinated by the EPA in the event of threatened releases of hazardous substances into the environment and authorizes the U.S. Government either to clean up sites at which hazardous substances have created actual or potential environmental hazards or to order persons responsible for the situation to do so. Under CERCLA, generators and transporters of hazardous substances, as well as past and present owners and operators of hazardous waste sites, are strictly, jointly and severally liable for the cleanup costs of waste at sites, most of which are listed by the EPA on the National Priorities List (NPL). These potentially responsible parties (PRPs) can be ordered to perform a cleanup, can be sued for costs associated with an EPA-directed cleanup, may voluntarily settle with the U.S. Government concerning their liability for cleanup costs, or may voluntarily begin a site investigation and site remediation under state oversight prior to listing on the NPL. Various states, including Illinois and Pennsylvania, have enacted statutes that contain provisions substantially similar to CERCLA. In addition, the Resource Conservation and Recovery Act (RCRA) governs treatment, storage and disposal of solid and hazardous wastes and cleanup of sites where such activities were conducted.
ComEd, PECO and Generation and their subsidiaries are or are likely to become parties to proceedings initiated by the EPA, state agencies and/or other responsible parties under CERCLA and RCRA with respect to a number of sites, including manufactured gas plant (MGP) sites, or may
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undertake to investigate and remediate sites for which they may be subject to enforcement actions by an agency or third party.
By notice issued in November 1986, the EPA notified over 800 entities, including ComEd and PECO, that they may be PRPs under CERCLA with respect to releases of radioactive and/or toxic substances from the Maxey Flats disposal site, a LLRW disposal site near Moorehead, Kentucky, where ComEd and PECO disposed of low level radioactive wastes resulting from their nuclear generation activities, which are now the responsibility of Generation. A settlement was reached among the Federal and private PRPs, including ComEd and PECO, the Commonwealth of Kentucky (Kentucky) and the EPA concerning their respective roles and responsibilities in conducting remedial activities at the site. Under the settlement, which was incorporated into a Federal court Consent Decree, the private PRPs agreed to perform the initial remedial work at the site and Kentucky agreed to assume responsibility for long-range maintenance and final remediation of the site. On October 5, 2003, the EPA issued a Certificate of Completion indicating that the private PRPs have completed their obligations under the Consent Decree. The site is being turned over to Kentucky as provided in the Consent Decree. The private PRPs, including Generation, will maintain oversight of Kentucky’s activities to assure the stability of the site since the private PRPs have residual liability if there is a remedy failure over the next ten years.
By notice issued in December 1987, the EPA notified several entities, including PECO, that they may be PRPs under CERCLA with respect to wastes resulting from the treatment and disposal of transformers and miscellaneous electrical equipment at a site located in Philadelphia, Pennsylvania (Metal Bank of America site). Several of the PRPs, including PECO, formed a steering committee to investigate the nature and extent of possible involvement in this matter. On May 29, 1991, a Consent Order was issued by the EPA pursuant to which the members of the steering committee agreed to perform the remedial investigation and feasibility study as described in the work plan issued with the Consent Order. PECO’s share of the cost of the study was approximately 30%. On July 19, 1995, the EPA issued a proposed plan for remediation of the site, which involves removal of contaminated soil, sediment and groundwater and which the EPA estimated would cost approximately $17 million to implement. On June 26, 1998, the EPA issued an order to the non-de minimis PRP group members, and others, including the owner, to implement the remedial design and remedial action.
The PRP group has conducted the remedial design and submitted to the EPA the revised final design on January 15, 2003. During the design process, the PRP group proposed certain revisions to the EPA’s preferred remedy, in response to which the EPA has issued two explanations of significant differences that are expected to reduce the costs of the preferred remedy. The final design estimates for the cost to implement the remedial action range from $14 million to $17 million. Significant progress has been made in settlement discussions between the EPA, the PRP group and the former owners and operators of the site. Exelon now believes that it is probable that the parties will agree to a settlement within the remedial range and that Exelon’s share of such settlement will be approximately 30%. This amount does not include Exelon’s share of the PRP group’s future legal and technical expenses, which are not expected to be material. The settlement amount will also not include any damages for natural resource damages that the EPA or state environmental agencies may seek to obtain in the future, and at this time PECO cannot predict with reasonable certainty the likelihood that such damages will be sought or the amount of any such damages.
Cotter Corporation
The EPA has advised Cotter Corporation (Cotter), a former ComEd subsidiary, that it is potentially liable in connection with radiological contamination at a site known as the West Lake Landfill in Missouri. Cotter is alleged to have disposed of approximately 39,000 tons of soils mixed with 8,700
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tons of leached barium sulfate at the site. Cotter, along with three other companies identified by the EPA as PRPs, has submitted a draft feasibility study addressing options for remediation of the site. The PRPs are also engaged in discussions with the State of Missouri and the EPA. The estimated costs of the anticipated remediation strategy for the site ranges up to $22 million. Once a remedy is selected, it is expected that the PRPs will agree on an allocation of responsibility for the costs. On February 18, 2000, ComEd sold Cotter to an unaffiliated third party. As part of the sale, ComEd agreed to indemnify Cotter for liability from the West Lake Landfill and the litigation described under ITEM 3. Litigation—Generation. In connection with Exelon’s 2001 corporate restructuring, the responsibility to indemnify Cotter for any liability related to these matters was transferred by ComEd to Generation.
MGP Sites
MGPs manufactured gas in Illinois and Pennsylvania from approximately 1850 to 1950. ComEd and PECO generally did not operate MGPs as corporate entities but did, however, acquire MGP sites as part of the absorption of smaller utilities. Approximately half of the ComEd sites were transferred to Nicor Gas as part of a general conveyance in 1954. ComEd also acquired former MGP sites as vacant real estate on which ComEd facilities have been constructed. To date, ComEd has identified 42 former MGP sites for which it may be liable for remediation. Of these 42 sites, the Illinois Environmental Protection Agency has approved the clean-up of four sites. Similarly, PECO has identified 27 sites where former MGP activities may have resulted in site contamination. Of these 27 sites, the PDEP has approved the clean-up of nine sites. With respect to these sites, ComEd and PECO are presently engaged in performing various levels of activities, including initial evaluation to determine the existence and nature of the contamination, detailed evaluation to determine the extent of the contamination and the necessity and possible methods of remediation, and implementation of remediation. ComEd and PECO are working closely with regulatory authorities in the various jurisdictions to develop and implement appropriate plans and schedules for evaluation, risk ranking, detailed study and remediation activities on an individual site and overall program basis. The status of each of the sites in the program varies and is reviewed periodically with the regulatory authorities. At December 31, 2004, ComEd and PECO had accrued $55 million (discounted) and $41 million (discounted), respectively, for investigation and remediation of these MGP sites that currently can be reasonably estimated. ComEd and PECO believe that they could incur additional liabilities with respect to MGP sites, which cannot be reasonably estimated at this time. PECO has settled in principle with all of the insurers in the insurance litigation lawsuit for remediation costs associated with former MGP sites. PECO expects to finalize all settlement agreements in the first quarter of 2005. ComEd is in settlement negotiations with one insurance carrier for remediation costs associated with former MGP sites. Additionally, PECO is currently collecting through regulated gas rates, revenues to offset expenditures on MGP site remediation.
Air
Air quality regulations promulgated by the EPA and the various state environmental agencies in Pennsylvania, Massachusetts, Illinois and Texas in accordance with the Federal Clean Air Act and the Clean Air Act (CAA) Amendments of 1990 (Amendments) impose restrictions on emission of particulates, sulfur dioxide (SO2), nitrogen oxides (NOx) and other pollutants and require permits for operation of emission sources. Such permits have been obtained by Exelon’s subsidiaries and must be renewed periodically.
The Amendments establish a comprehensive and complex national program to substantially reduce air pollution. The Amendments include a two-phase program to reduce acid rain effects by significantly reducing emissions of SO2 and NOx from electric power plants. Flue-gas desulphurization systems (scrubbers) have been installed at all of Generation’s coal-fired units other than the Keystone Station. Keystone is subject to, and in compliance with, the Phase II SO2 and NOx limits of the
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Amendments, which became effective January 1, 2000. Generation and the other Keystone co-owners are purchasing SO2 emission allowances to comply with the Phase II limits.
Generation has completed implementation of measures, including the installation of NOx emissions controls and the imposition of certain operational constraints, to comply with the Reasonably Available Control Technology limitations and state-level ozone season (May to September) NOx reduction regulations. These state-level regulations were developed by eastern states to reduce summertime NOx emissions pursuant to several Federal NOx reduction regulations adopted by the Federal EPA during 1998 and 1999 to address regional “ozone transport.” State level NOx reduction regulations took effect May 1, 2003 in Pennsylvania and Massachusetts. Compliance in Illinois started May 31, 2004. Texas is not covered by the EPA’s ozone transport regulations. The EPA’s ozone transport regulations currently require 19 eastern states to reduce summertime NOx emissions.
Generation has evaluated options for compliance with the new NOx regulations and installed controls on the two coal-fired units at the Eddystone Generating Station (Selective Non-Catalytic Reduction) and installed controls on the two coal-fired units (Selective Catalytic Reduction) at the Keystone Generating Station. Generation’s NOx compliance program will be supplemented with the purchase of additional NOx allowances on an as-needed basis. The eight new peaking units commissioned during 2002 at the Southeast Chicago Generating Station are equipped with NOx controls that meet requirements for new sources. The Handley and Mountain Creek stations in the Dallas/Fort Worth (DFW) area are required to comply with the DFW NOx State Implementation Plan (SIP) that commenced on May 1, 2003, with full implementation on May 1, 2005. Additionally, beginning May 1, 2003, these plants were required to comply with the Emission Banking and Trading of Allowances (EBTA) program established by the State of Texas for the purpose of achieving substantial reductions in NOx from grandfathered electric generating facilities. To comply with both the DFW NOx SIP and EBTA program, Generation, as of June 30, 2004, had installed Selective Catalytic Reduction technology on Handley Units 3, 4 and 5, as well as Mountain Creek Unit 8. Additionally, Induced Flue Gas Recirculation Technology was installed on Mountain Creek Unit 6. Induced Flue Gas Recirculation Technology will be installed on Mountain Creek Unit 7 in 2005 prior to the DFW NOx SIP program being fully implemented on May 1, 2005. This will complete all NOx control technology upgrades planned for the DFW plants.
Many other provisions of the Amendments affect activities of Exelon’s businesses, primarily Generation. The Amendments establish stringent control measures for geographical regions that have been determined by the EPA not to meet National Ambient Air Quality Standards (NAAQS); establish limits on the purchase and operation of motor vehicles and require increased use of alternative fuels; establish stringent controls on emissions of toxic air pollutants and provide for possible future designation of some utility emissions as toxic; establish new permit and monitoring requirements for sources of air emissions; and provide for significantly increased enforcement power, and civil and criminal penalties.
Several other legislative and regulatory proposals regarding the control of emissions of air pollutants from a variety of sources, including generating plants, are under active consideration. On the Federal legislative front, several multi-pollutant bills have been introduced in Congress that would reduce generating plant emissions of NOx, SO2, mercury and/or carbon dioxide starting late this decade. On the Federal regulatory front, the EPA issued several new proposed rulemakings during 2004 to reduce powerplant emissions of SO2, NOx and mercury. In its proposed “Clean Air Interstate Rule (CAIR)” rulemaking, the EPA has proposed NOx and SO2 emission caps in 29 eastern states, to be phased-in during 2010 and 2015, that are substantially below current industry emission levels. The CAIR rule is intended to support regional attainment of Federal ground-level ozone (eight-hour) and fine particulate (PM2.5) NAAQS. In a separate hazardous air pollutant-related rulemaking, the EPA has also proposed several options to regulate mercury emissions from coal-fired power plants under either
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Section 112 or Section 111 of the CAA. Regulation of nickel emissions from oil-fired power plants is also contemplated as part of this latter proposed rulemaking. Exelon is unable at this time to ascertain which proposals may take effect, what requirements they may contain, or how they may affect Exelon’s businesses. At this time, Exelon can provide no assurance that these proposals if adopted will not have a significant effect on Generation’s operations and cash flows.
Global Climate Change
The United States is currently not a party to the United Nations’ Kyoto Protocol (Protocol) that became effective for signatories on February 16, 2005. The Protocol process generally requires developed countries to cap greenhouse gas (GHG) emissions at certain levels during the 2008-2012 time period. Although it is not a signatory to the Protocol, the United States may adopt a national, mandatory GHG program at some point in the future. At this time, Exelon is unable to predict the potential impacts of any future mandatory governmental GHG legislative or regulatory requirements on its businesses.
In the absence of a mandatory national program, Exelon has joined the U.S. EPA Climate Leaders Partnership (Climate Leader). As a Climate Leader partner, Exelon is conducting an annual inventory of its GHG emissions, developing a GHG emission reduction goal, and annually reporting its GHG emissions and progress toward achieving GHG reductions.
As an integrated electric and gas utility, approximately 90% of Generation’s GHG emissions result from the combustion of fossil fuels to generate electricity, with carbon dioxide (CO2) representing the largest quantity of GHG emitted. The majority of Generation’s owned generation is comprised of nuclear and hydro-electric assets that have negligible GHG emissions compared to fossil-based electric generation alternatives. By virtue of Generation’s significant investment in these low carbon intensity assets, Generation’s owned-generation portfolio CO2 emission intensity, or rate of CO2 emitted per kilowatt-hour of electricity generated, is among the lowest in the industry.
Renewable and Alternative Energy Portfolio Standards
Approximately 17 states have adopted some form of renewable portfolio standard (RPS) legislation. On November 30, 2004, Pennsylvania adopted Act 213, the Alternative Energy Portfolio Standards Act of 2004 (AEPS Act). The AEPS Act mandates that two years after its effective date (February 28, 2005) at least 1.5% of electric energy sold by an electric distribution company or electric generation supplier to Pennsylvania retail electric customers must come from Tier I alternative energy resources. The Tier I requirement escalates to 8.0% by the 15th year after the effective date of the AEPS Act. The AEPS Act also establishes a Tier II requirement of 4.2% for years one through four. This requirement grows to 10.0% by the 15th year.
Tier I resources include: solar photovoltaic energy, wind power, low-impact hydro, geothermal energy, biologically derived methane gas, fuel cells, biomass energy and coal mine methane. A small percentage of the Tier I requirements must be met specifically by solar photovoltaic technologies (starting at 0.0013% in year 1 and escalating to 0.25% by year 10). Tier II resources include: waste coal, distributed generation systems, demand side management, large-scale hydropower, municipal solid waste and several other technologies.
The AEPS Act provides an exemption for electric distribution companies that have not reached the end of their cost recovery period during which competitive transition charges or intangible transition charges are being recovered. At the conclusion of the electric distribution company’s cost recovery period, this exemption no longer applies and compliance by the electric distribution company is required at the percentages in effect at that time. PECO’s cost recovery period expires December 31, 2010.
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In the first year after the end of an electric distribution company’s cost recovery period, the AEPS Act provides for cost recovery on a full and current basis pursuant to an automatic energy adjustment charge as a cost of generation supply. The banking of credits from voluntary sales of Tier I and Tier II sources sold by electric distribution companies prior to the expiration of their specific cost recovery periods is also allowed under the AEPS Act. Voluntary sales under the AEPS Act are deferred as a regulatory asset by the electric distribution company and are fully recoverable at the end of the cost recovery period, also pursuant to an automatic energy adjustment clause as a cost of generation supply.
The PUC is required to establish regulations to implement the AEPS Act. These regulations will be material to a complete assessment of the effects of the AEPS Act on PECO. While Generation is not directly affected from a compliance perspective, increased deployment of renewable and alternative energy resources within the regional power pool resulting from the AEPS Act will have some influence on regional energy markets.
In addition to the AEPS Act, similar legislation has been, and may be, considered by the United States Congress. Also, states that currently do not have RPS requirements, including Illinois, may determine to adopt such legislation in the future.
Exelon is currently evaluating the potential impacts of RPS legislation on its businesses.
Costs
At December 31, 2004, ComEd, PECO and Generation had accrued $61 million, $47 million and $16 million, respectively, for various environmental investigation and remediation. These costs include approximately $55 million at ComEd and $41 million at PECO for former MGP sites as described above. ComEd, PECO and Generation cannot currently predict whether they will incur other significant liabilities for additional investigation and remediation costs at sites presently identified or additional sites which may be identified by ComEd, PECO and Generation, environmental agencies or others, or whether all such costs will be recoverable through rates or from third parties.
The budgets for expenditures in 2005 at ComEd, PECO and Generation for compliance with environmental requirements total approximately $8 million, $8 million and $7 million, respectively. In addition, ComEd, PECO and Generation may be required to make significant additional expenditures not presently determinable.
Exelon does not know the impact that future terrorist attacks or threats of terrorism may have on the electric and gas industry in general and on Exelon in particular. Exelon has initiated security measures to safeguard its employees and critical operations from threats of terrorism and is actively participating in industry initiatives to identify methods to maintain the reliability of Exelon’s energy production and delivery systems. Additionally, the energy industry is working with governmental authorities to ensure that emergency plans are in place and critical infrastructure vulnerabilities are addressed in order to maintain the reliability of the country’s energy systems. These measures will involve additional expenses to develop and implement, but will provide increased assurances as to Exelon’s ability to maintain critical operations.
Generation has met or exceeded all security measures mandated by the NRC for nuclear plants. On a continuing basis, Exelon is evaluating enhanced security measures at certain critical locations, enhanced response, and recovery plans and assessing long-term design changes and redundancy measures.
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Other Subsidiaries of ComEd and PECO with Publicly Held Securities
ComEd Transitional Funding Trust (ComEd Funding Trust), a Delaware statutory trust, was formed on October 28, 1998, pursuant to a trust agreement among First Union Trust Company, National Association, now Wachovia Bank, National Association, as Delaware trustee, and two individual trustees appointed by ComEd. ComEd Funding LLC, a special purpose Delaware limited liability company, was organized on July 21, 1998. ComEd Funding Trust was created for the sole purpose of issuing transitional funding notes to securitize intangible transition property granted to ComEd Funding LLC, a ComEd affiliate, by an ICC order issued July 21, 1998. On December 16, 1998, ComEd Funding Trust issued $3.4 billion of transitional funding notes, the proceeds of which were used to purchase the intangible transition property held by ComEd Funding LLC. ComEd Funding LLC transferred the proceeds to ComEd where they were used, among other things, to repurchase outstanding debt and equity securities of ComEd. The transitional funding notes are solely obligations of ComEd Funding Trust and are secured by the intangible transition property, which represents the right to receive instrument funding charges collected from ComEd’s customers. The instrument funding charges represent a non-bypassable, usage-based, per kWh charge on designated consumers of electricity.
ComEd Financing II, a Delaware statutory trust, was formed by ComEd on November 20, 1996. ComEd Financing II was created solely for the purpose of issuing and selling preferred and common securities. On January 24, 1997, ComEd Financing Trust II issued $150 million of trust preferred securities, carrying an annual distribution rate of 8.50%, which are mandatorily redeemable on January 15, 2027. ComEd is the sole owner of all of the common securities of ComEd Financing Trust II. The sole assets of ComEd Financing II are $155 million principal amount of 8.50% subordinated deferrable interest debentures due January 15, 2027, issued by ComEd.
ComEd Financing III, a Delaware statutory trust, was formed by ComEd on September 5, 2002. ComEd Financing III was created for the sole purpose of issuing and selling preferred and common securities. On March 17, 2003, ComEd Financing III issued $200 million of trust preferred securities, carrying an annual distribution rate of 6.35%, which are mandatorily redeemable on March 15, 2033. ComEd is the sole owner of all of the common securities of ComEd Financing Trust III. The sole assets of ComEd Financing III are $206 million principal amount of 6.35% subordinated deferrable interest debentures due March 15, 2033, issued by ComEd.
PECO Energy Transition Trust (PETT), a Delaware statutory trust wholly owned by PECO, was formed on June 23, 1998 pursuant to a trust agreement among PECO, as grantor, First Union Trust Company, National Association, now Wachovia Bank, National Association, as issuer trustee, and two beneficiary trustees appointed by PECO. PETT was created for the sole purpose of issuing transition bonds to securitize a portion of PECO’s authorized stranded cost recovery. On March 25, 1999, PETT issued $4 billion of its Series 1999-A Transition Bonds. On May 2, 2000, PETT issued $1 billion of its Series 2000-A Transition Bonds and on March 1, 2001, PETT issued $805 million of its Series 2001-A Transition Bonds to refinance a portion of the Series 1999-A Transition Bonds. The Transition Bonds are solely obligations of PETT secured by intangible transition property, representing the right to collect transition charges sufficient to pay the principal and interest on the Transition Bonds.
PECO Energy Capital Corp., a wholly owned subsidiary of PECO (PECC), is the sole general partner of PECO Energy Capital, L.P., a Delaware limited partnership (PEC L.P.). PEC L.P. was created solely for the purpose of issuing preferred securities, representing limited partnership interests and lending the proceeds thereof to PECO and entering into similar financing arrangements. The loans to PECO are evidenced by PECO’s deferrable interest subordinated debentures (Subordinated Debentures), which are the only assets of PEC L.P. The only revenues of PEC L.P. are interest on the Subordinated Debentures. All of the operating expenses of PEC L.P. are paid by PECC. As of
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December 31, 2004, PEC L.P. held $81 million aggregate principal amount of the Subordinated Debentures.
PECO Energy Capital Trust III (PECO Trust III), a Delaware statutory trust, was formed by PECO in April 1998. PECO Trust III was created solely for the purpose of issuing $78 million trust receipts (Trust III Receipts) each representing a 7.38% Cumulative Preferred Security, Series D (Series D Preferred Securities) of PEC L.P. PEC L.P. is the sponsor of PECO Trust III. As of December 31, 2004, PECO Trust III had outstanding 78,105 Trust III Receipts. At December 31, 2004, the assets of PECO Trust III consisted solely of 78,105 Series D Preferred Securities with an aggregate stated liquidation preference of $81 million.
PECO Energy Capital Trust IV (PECO Trust IV), a Delaware statutory trust, was formed by PECO in May 2003. PECO Trust IV was created solely for the purpose of issuing and selling preferred and common securities. On June 17, 2003, PECO Trust IV issued $100 million of trust preferred securities, carrying an annual distribution rate of 5.75%, which are mandatorily redeemable on June 15, 2033. PECO is the sole owner of all of the common securities of the PECO Trust IV. The sole assets of PECO Trust IV are $103 million principal amount of 5.75% subordinated debentures issued by PECO.
The financing trusts discussed above were deconsolidated from the financial statements of Exelon, ComEd and PECO in 2003. See Note 1 of Exelon’s Notes to Consolidated Financial Statements for additional information.
Executive Officers of the Registrants at December 31, 2004
Exelon
| Name |
Age |
Position | ||
| Rowe, John W. |
59 | Chairman, Chief Executive Officer and President | ||
| Clark, Frank M. |
59 | Executive Vice President and Chief of Staff | ||
| McLean, Ian P. |
55 | Executive Vice President | ||
| Mehrberg, Randall E. |
49 | Executive Vice President and General Counsel | ||
| Moler, Elizabeth A. |
55 | Executive Vice President | ||
| Shapard, Robert S. |
49 | Executive Vice President and Chief Financial Officer | ||
| Skolds, John L. |
54 | Executive Vice President | ||
| Snodgrass, S. Gary |
53 | Executive Vice President and Chief Human Resources Officer | ||
| Strobel, Pamela B. |
52 | Executive Vice President and Chief Administrative Officer | ||
| Young, John F. |
48 | Executive Vice President | ||
| Hilzinger, Matthew F. |
41 | Vice President and Corporate Controller |
ComEd
| Name |
Age |
Position | ||
| Rowe, John W. |
59 | Chairman, Chief Executive Officer and President, Exelon, and Chair and Director | ||
| Shapard, Robert S. |
49 | Executive Vice President and Chief Financial Officer, Exelon, and Director | ||
| Snodgrass, S. Gary |
53 | Executive Vice President and Chief Human Resources Officer, Exelon, and Director | ||
| Skolds, John L. |
54 | President, Exelon Energy Delivery, and Director | ||
| Clark, Frank M. |
59 | President and Director | ||
| Gillis, Ruth Ann M. |
50 | Executive Vice President | ||
| Mitchell, J. Barry |
56 | Senior Vice President, Treasurer and Chief Financial Officer | ||
| Hilzinger, Matthew F. |
41 | Vice President and Corporate Controller, Exelon |
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PECO
| Name |
Age |
Position | ||
| Rowe, John W. |
59 | Chairman, Chief Executive Officer and President, Exelon, and Director | ||
| Shapard, Robert S. |
49 | Executive Vice President and Chief Financial Officer, Exelon, and Director | ||
| Skolds, John L. |
54 | President, Exelon Energy Delivery, and Director | ||
| O’Brien, Denis P. |
44 | President and Director | ||
| Mitchell, J. Barry |
56 | Senior Vice President, Treasurer and Chief Financial Officer | ||
| Hilzinger, Matthew F. |
41 | Vice President and Corporate Controller, Exelon |
Generation
| Name |
Age |
Position | ||
| Rowe, John W. |
59 | Chairman, Chief Executive Officer and President, Exelon | ||
| Shapard, Robert S. |
49 | Executive Vice President and Chief Financial Officer, Exelon | ||
| Young, John F. |
48 | Executive Vice President, Exelon, and President | ||
| McLean, Ian P. |
55 | Executive Vice President, Exelon, and President, Power Team | ||
| Crane, Christopher M. |
46 | Senior Vice President, Exelon, and President and Chief Nuclear Officer, Exelon Nuclear | ||
| Schiavoni, Mark A. |
49 | Senior Vice President and President, Exelon Power | ||
| Mitchell, J. Barry |
56 | Senior Vice President, Treasurer and Chief Financial Officer | ||
| Veurink, Jon D. |
40 | Vice President and Controller |
Each of the above executive officers holds such office at the discretion of the respective company’s board of directors until his or her replacement or earlier resignation, retirement or death.
Prior to his election to his listed position, Mr. Rowe was President and Co-Chief Executive of Exelon, Co-Chief Executive Officer of ComEd and President, Co-Chief Executive Officer of PECO; and Chairman, President and Chief Executive Officer of ComEd and Unicom. Mr. Rowe was elected as an officer of Exelon effective October 20, 2000.
Prior to his election to his listed position, Mr. Clark was Senior Vice President, Distribution Customer and Marketing Services and External Affairs of ComEd; Senior Vice President of ComEd and Unicom; Vice President of ComEd; Governmental Affairs Vice President; and Governmental Affairs Manager. Mr. Clark was elected as an officer of Exelon effective October 20, 2000.
Prior to his election to his listed position, Mr. McLean was Senior Vice President of Exelon; President of the Power Team division of PECO; and Group Vice President of Engelhard Corporation. Mr. McLean was elected as an officer of Exelon effective October 20, 2000.
Prior to his election to his listed position, Mr. Mehrberg was Senior Vice President of Exelon; an equity partner with the law firm of Jenner & Block; and General Counsel and Lakefront Director of the Chicago Park District. Mr. Mehrberg was elected as an officer effective December 3, 2001.
Prior to her election to her listed position, Ms. Moler was Senior Vice President, Government Affairs and Policy of Exelon; Senior Vice President of ComEd and Unicom; Director of Unicom and ComEd; Partner at the law firm of Vinson & Elkins, LLP; Deputy Secretary of the U.S. Department of Energy; and Chair of the Federal Energy Regulatory Commission. Ms. Moler was elected as an officer effective October 20, 2000.
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Prior to his election to his listed position, Mr. Shapard was Executive Vice President and Chief Financial Officer of Covanta Energy Corporation; Executive Vice President and Chief Financial Officer of Ultramar Diamond Shamrock; Chief Executive Officer of TSU Australia, Ltd., and Vice President, Finance and Treasurer at TXU. Mr. Shapard was elected as an officer effective October 21, 2002.
Prior to his election to his listed position, Mr. Skolds was Senior Vice President, Exelon, and President and Chief Nuclear Officer, Exelon Nuclear; and President and Chief Operating Officer of South Carolina Electric and Gas. Mr. Skolds was elected as an officer effective October 20, 2000.
Prior to his election to his listed position, Mr. Snodgrass was Chief Administrative Officer of Exelon; Senior Vice President of ComEd and Unicom; Vice President of ComEd and Unicom; and Vice President of USG Corporation. Mr. Snodgrass was elected as an officer effective October 20, 2000.
Prior to her election to her listed position, Ms. Strobel was Vice Chairman of ComEd; Vice Chairman of PECO; Executive Vice President and General Counsel of ComEd and Unicom; Senior Vice President and General Counsel of ComEd and Unicom; and Vice President and General Counsel of ComEd. Ms. Strobel was elected as an officer effective October 20, 2000.
Prior to his election to his listed position, Mr. Young was President of Exelon Power; Senior Vice President of Sierra Pacific Resources Corporation; President of Avalon Consulting; and Executive Vice President of Southern Generation. Mr. Young was elected as an officer effective March 3, 2003.
Prior to his election to his listed position, Mr. Hilzinger was Executive Vice President and Chief Financial Officer of Credit Acceptance Corporation; Vice President, Controller of Kmart Corporation; Divisional Vice President, Strategic Planning and Financial Reporting of Kmart Corporation; and Assistant Treasurer of Kmart Corporation. Mr. Hilzinger was elected as an officer effective April 15, 2002.
Prior to her election to her listed position, Ms. Gillis was Senior Vice President of Exelon; President of Business Services Company; Chief Financial Officer of Exelon; and Senior Vice President and Chief Financial Officer of Unicom Corporation. Ms. Gillis was elected as an officer effective October 20, 2000.
Prior to his election to his listed position, Mr. Mitchell was Vice President and Treasurer of Exelon; and Vice President, Treasury and Evaluation, and Treasurer of PECO. Mr. Mitchell was elected as an officer of Exelon effective October 20, 2000.
Prior to his election to his listed position, Mr. O’Brien was Executive Vice President of PECO; Vice President of Operations of PECO; Director of Transmission and Substations of PECO; and Director of BucksMont Region of PECO. Mr. O’Brien was elected as an officer effective January 1, 2001.
Prior to his election to his listed position, Mr. Crane was Vice President for Exelon Nuclear; and Vice President for BWR Operations of ComEd. Mr. Crane was elected as an officer effective December 27, 2000.
Prior to his election to his listed position, Mr. Schiavoni was Vice President of Operations; and Vice President of Northeast Operations of Exelon Power. Mr. Schiavoni was elected as an officer effective September 8, 2003.
Prior to his election to his listed position, Mr. Veurink was a partner at Deloitte & Touche LLP. Mr. Veurink was elected as an officer effective January 5, 2004.
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| ITEM 2. | PROPERTIES |
The electric substations and a portion of the transmission rights of way are located on property owned by ComEd and PECO. A significant portion of the electric transmission and distribution facilities is located over or under highways, streets, other public places or property owned by others, for which permits, grants, easements or licenses, deemed satisfactory by ComEd and PECO but without examination of underlying land titles, have been obtained.
Transmission and Distribution
Energy Delivery’s higher voltage electric transmission lines owned and in service at December 31, 2004 were as follows:
| Voltage (Volts) |
Circuit Miles |
||||
| ComEd |
765,000 | 90 | |||
| 345,000 | 2,600 | ||||
| 138,000 | 2,866 | ||||
| 69,000 | 149 | ||||
| PECO |
500,000 | 188 | (a) | ||
| 220,000 | 541 | ||||
| 132,000 | 156 | ||||
| 66,000 | 153 |
| (a) | In addition, PECO has a 22.00% ownership of 127 miles of 500,000 voltage lines located in Pennsylvania and a 42.55% ownership of 151 miles of 500,000 voltage lines located in Delaware and New Jersey. |
ComEd’s electric distribution system includes 43,700 circuit miles of overhead lines and 32,900 cable miles of underground lines. PECO’s electric distribution system includes 12,150 circuit miles of overhead lines and 15,389 cable miles of underground lines.
Gas
The following table sets forth PECO’s gas pipeline miles at December 31, 2004:
| Pipeline Miles | ||
| Transmission |
31 | |
| Distribution |
6,457 | |
| Service piping |
5,282 | |
| Total |
11,770 | |
PECO has an LNG facility located in West Conshohocken, Pennsylvania which has a storage capacity of 1,200 mmcf and a send-out capacity of 157 mmcf/day and a propane-air plant located in Chester, Pennsylvania, with a tank storage capacity of 1,980,000 gallons and a peaking capability of 25 mmcf/day. In addition, PECO owns 29 natural gas city gate stations at various locations throughout its gas service territory.
Mortgages
The principal plants and properties of ComEd are subject to the lien of ComEd’s Mortgage dated July 1, 1923, as amended and supplemented, under which ComEd’s first mortgage bonds are issued.
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The principal plants and properties of PECO are subject to the lien of PECO’s Mortgage dated May 1, 1923, as amended and supplemented, under which PECO’s first mortgage bonds are issued.
Insurance
ComEd and PECO maintain property insurance against loss or damage to Energy Delivery’s properties by fire or other perils, subject to certain exceptions. For its insured losses, ComEd and PECO are self-insured to the extent that any losses are within the policy deductible or exceed the amount of insurance maintained. Any such losses could have a material adverse effect on the consolidated financial condition or results of operations of ComEd or PECO.
The following table sets forth Generation’s owned net electric generating capacity by station at December 31, 2004. The table does not include properties held by equity method investments:
| Station |
Location |
No. of Units |
Percent Owned (a) |
Primary Fuel Type |
Primary Dispatch Type (f) |
Net Generation (b) Capacity (MW) |
|||||||
| Nuclear (c) |
|||||||||||||
| Braidwood |
Braidwood, IL | 2 | Uranium | Base-load | 2,363 | ||||||||
| Byron |
Byron, IL | 2 | Uranium | Base-load | 2,336 | ||||||||
| Clinton |
Clinton, IL | 1 | Uranium | Base-load | 1,030 | ||||||||
| Dresden |
Morris, IL | 2 | Uranium | Base-load | 1,742 | ||||||||
| LaSalle |
Seneca, IL | 2 | Uranium | Base-load | 2,288 | ||||||||
| Limerick |
Limerick Twp., PA | 2 | Uranium | Base-load | 2,309 | ||||||||
| Oyster Creek |
Forked River, NJ | 1 | Uranium | Base-load | 625 | ||||||||
| Peach Bottom |
Peach Bottom Twp., PA | 2 | 50.00 | Uranium | Base-load | 1,131 | (d) | ||||||
| Quad Cities |
Cordova, IL | 2 | 75.00 | Uranium | Base-load | 1,121 | (d) | ||||||
| Salem |
Hancock’s Bridge, NJ | 2 | 42.59 | Uranium | Base-load | 969 | (d) | ||||||
| Three Mile Island |
Londonderry Twp, PA | 1 | Uranium | Base-load | 837 | ||||||||
| 16,751 | |||||||||||||
| Fossil (Steam Turbines) |
|||||||||||||
| Batavia |
Batavia, NY | 1 | 50.00 | Gas | Intermediate | 26 | (e) | ||||||
| Conemaugh |
New Florence, PA | 2 | 20.72 | Coal | Base-load | 352 | (d) | ||||||
| Cromby 1 |
Phoenixville, PA | 1 | Coal | Base-load | 144 | ||||||||
| Cromby 2 |
Phoenixville, PA | 1 | Oil/Gas | Intermediate | 201 | ||||||||
| Eddystone 1, 2 |
Eddystone, PA | 2 | Coal | Base-load | 581 | ||||||||
| Eddystone 3, 4 |
Eddystone, PA | 2 | Oil/Gas | Intermediate | 760 | ||||||||
| Fairless Hills |
Falls Twp, PA | 2 | Landfill Gas | Peaking | 60 | ||||||||
| Handley 1, 2, 4, 5 |
Fort Worth, TX | 4 | Gas | Peaking | 1,041 | ||||||||
| Handley 3 |
Fort Worth, TX | 1 | Gas | Intermediate | 400 | ||||||||
| Keystone |
Shelocta, PA | 2 | 20.99 | Coal | Base-load | 358 | (d) | ||||||
| Independence |
Oswego, NY | 1 | 50.00 | Gas | Base-load | 514 | (e) | ||||||
| Massena |
Massena, NY | 1 | 50.00 | Oil/Gas | Intermediate | 34 | (e) | ||||||
| Mountain Creek 2, 3, 6, 7 |
Dallas, TX | 4 | Gas | Peaking | 343 | ||||||||
| Mountain Creek 8 |
Dallas, TX | 1 | Gas | Intermediate | 550 | ||||||||
| New Boston 1 |
South Boston, MA | 1 | Gas | Intermediate | 353 | ||||||||
| Ogdensburg |
Ogdensburg, NY | 1 | 50.00 | Oil/Gas | Intermediate | 36 | (e) | ||||||
| Schuylkill |
Philadelphia, PA | 1 | Oil | Peaking | 166 | ||||||||
| Sterling |
Sherrill, NY | 1 | 50.00 | Gas | Intermediate | 28 | (e) | ||||||
| Wyman |
Yarmouth, ME | 1 | 5.89 | Oil | Intermediate | 36 | (d) | ||||||
| 5,983 |
(continued on next page)
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| Station (continued) |
Location |
No. of Units |
Percent Owned (a) |
Primary Fuel Type |
Primary Dispatch Type (f) |
Net Generation (b) Capacity (MW) |
|||||||
| Fossil (Combustion Turbines) |
|||||||||||||
| Chester |
Chester, PA | 3 | Oil | Peaking | 39 | ||||||||
| Croydon |
Bristol Twp., PA | 8 | Oil | Peaking | 384 | ||||||||
| Delaware |
Philadelphia, PA | 4 | Oil | Peaking | 56 | ||||||||
| Eddystone |
Eddystone, PA | 4 | Oil | Peaking | 60 | ||||||||
| Falls |
Falls Twp., PA | 3 | Oil | Peaking | 51 | ||||||||
| Framingham |
Framingham, MA | 3 | Oil | Peaking | 30 | ||||||||
| LaPorte |
Laporte, TX | 4 | Gas | Peaking | 160 | ||||||||
| Medway |
West Medway, MA | 3 | Oil | Peaking | 110 | ||||||||
| Moser |
Lower Pottsgrove Twp., PA | 3 | Oil | Peaking | 51 | ||||||||
| New Boston |
South Boston, MA | 1 | Gas | Peaking | 13 | ||||||||
| Pennsbury |
Falls Twp., PA | 2 | Landfill Gas | Peaking | 6 | ||||||||
| Richmond |
Philadelphia, PA | 2 | Oil | Peaking | 96 | ||||||||
| Salem |
Hancock’s Bridge, NJ | 1 | 42.59 | Oil | Peaking | 16 | (d) | ||||||
| Schuylkill |
Philadelphia, PA | 2 | Oil | Peaking | 30 | ||||||||
| Southeast Chicago |
Chicago, IL | 8 | 71.00 | Gas | Peaking | 222 | (d) | ||||||
| Southwark |
Philadelphia, PA | 4 | Oil | Peaking | 52 | ||||||||
| 1,376 | |||||||||||||
| Fossil (Internal Combustion/Diesel) |
|||||||||||||
| Conemaugh |
New Florence, PA | 4 | 20.72 | Oil | Peaking | 2 | (d) | ||||||
| Cromby |
Phoenixville, PA | 1 | Oil | Peaking | 3 | ||||||||
| Delaware |
Philadelphia, PA | 1 | Oil | Peaking | 3 | ||||||||
| Keystone |
Shelocta, PA | 4 | 20.99 | Oil | Peaking | 2 | (d) | ||||||
| Schuylkill |
Philadelphia, PA | 1 | Oil | Peaking | 3 | ||||||||
| 13 | |||||||||||||
| Hydroelectric |
|||||||||||||
| Conowingo |
Harford Co. MD | 11 | Hydroelectric | Base-load | 536 | ||||||||
| Muddy Run |
Lancaster, PA | 8 | Hydroelectric | Intermediate | 1,072 | ||||||||
| Allegheny |
Ford City, PA | 4 | 50.00 | Hydroelectric | Intermediate | 25 | (e) | ||||||
| 1,633 | |||||||||||||
| Total |
138 | 25,756 | |||||||||||
| (a) | 100%, unless otherwise indicated. |
| (b) | For nuclear stations, except Salem, capacity reflects the annual mean rating. All other stations, including Salem, reflect a summer rating. |
| (c) | All nuclear stations are boiling water reactors except Braidwood, Byron, Salem and Three Mile Island, which are pressurized water reactors. |
| (d) | Net generation capacity is stated at proportionate ownership share. |
| (e) | Properties are owned by Sithe. Sithe was consolidated by Generation in accordance with Financial Accounting Standards Board (FASB) Interpretation No. (FIN) 46 (revised December 2003), “Consolidation of Variable Interest Entities” (FIN 46-R) and capacity is shown at Generation’s percentage of ownership as of December 31, 2004. See Note 3 of Exelon’s and Generation’s Notes to Consolidated Financial Statements for additional information related to Sithe. As of January 31, 2005, Generation no longer holds an interest in Sithe. See Note 25 of Exelon’s and Note 20 of Generation’s Notes to Consolidated Financial Statements for further information regarding the sale of the investment in Sithe. |
| (f) | Base-load units are plants that normally operate to take all or part of the minimum continuous load of a system, and consequently produce electricity at an essentially constant rate. Intermediate units are plants that normally operate to take load of a system during the day time higher load hours, and consequently produce electricity by cycling on and off daily. Peaking units are plants that usually house low-efficiency, quick response steam units, gas turbines, diesels, or pumped-storage hydroelectric equipment normally used during the maximum load periods. |
36
The net generating capability available for operation at any time may be less due to regulatory restrictions, fuel restrictions, efficiency of cooling facilities and generating units being temporarily out of service for inspection, maintenance, refueling, repairs or modifications required by regulatory authorities.
Generation maintains property insurance against loss or damage to its principal plants and properties by fire or other perils, subject to certain exceptions. For additional information regarding nuclear insurance of generating facilities, see ITEM 1. Business—Generation. For its insured losses, Generation is self-insured to the extent that losses are within the property deductible or exceed the amount of insurance maintained. Any such losses could have a material adverse effect on Generation’s consolidated financial condition and results of operations.
| ITEM 3. | LEGAL PROCEEDINGS |
Retail Rate Law. In 1996, three developers of non-utility generating facilities filed litigation against various Illinois officials claiming that the enforcement against those facilities of an amendment to Illinois law removing the entitlement of those facilities to state-subsidized payments for electricity sold to ComEd after March 15, 1996 violated their rights under Federal and state constitutions. The developers also filed suit against ComEd for a declaratory judgment that their rights under their contracts with ComEd were not affected by the amendment and for breach of contract. On November 25, 2002, the court granted the developers’ motions for summary judgment. The judge also entered a permanent injunction enjoining ComEd from refusing to pay the retail rate on the grounds of the amendment and Illinois from denying ComEd a tax credit on account of such purchases. On March 9, 2004, the Illinois Appellate Court reversed the trial court. The Appellate Court held that the 1996 law does apply to the developers’ facilities and, therefore, they are not entitled to subsidized payments. The Court expressly ruled that the breach of contract claims against ComEd are dismissed with prejudice. Two of the developers sought review of the Appellate Court’s decision by the Illinois Supreme Court. On May 26, 2004, the Supreme Court declined to hear the earlier-filed of the two appeals. On October 6, 2004, the Supreme Court declined to hear the final appeal. The time for further appeals has now passed. Related claims remain pending in the trial court.
Real Estate Tax Appeals. PECO and Generation each have been challenging real estate taxes assessed on nuclear plants. PECO is involved in litigation in which it is contesting taxes assessed in 1997 under the Pennsylvania Public Utility Realty Tax Act of March 4, 1971, as amended (PURTA), and has appealed local real estate assessments for 1998 and 1999 on the Limerick Generating Station (Montgomery County, PA) (Limerick) and Peach Bottom Atomic Power Station (York County, PA) (Peach Bottom). Generation is involved in real estate tax appeals for 2000 through 2004, also regarding the valuation of its Limerick and Peach Bottom plants and Quad Cities Station (Rock Island County, IL), Three Mile Island Nuclear Station (Dauphin County, PA) and Oyster Creek Nuclear Generating Station (Forked River, NJ).
Cotter Corporation Litigation. During 1989 and 1991, actions were brought in Federal and state courts in Colorado against ComEd and its subsidiary, Cotter, seeking unspecified damages and injunctive relief based on allegations that Cotter permitted radioactive and other hazardous material to be released from its mill into areas owned or occupied by the plaintiffs, resulting in property damage and potential adverse health effects. On February 18, 2000, ComEd sold Cotter to an unaffiliated third party. As part of the sale, ComEd agreed to indemnify Cotter for any liability incurred by Cotter as a result of these actions. In connection with Exelon’s 2001 corporate restructuring, the responsibility to indemnify Cotter for any liability related to these matters was transferred by ComEd to Generation.
37
Several of the actions resulted in nominal jury verdicts or were settled or dismissed. One action resulted in an award for the plaintiffs of a more substantial amount, but was reversed on April 22, 2003 by the Tenth Circuit Court of Appeals and remanded for retrial. An appeal by the plaintiffs to the United States Supreme Court was denied on November 10, 2003. In October 2004, a settlement of the claims of all Cotter plaintiffs was reached and approved by the Federal District Court in Colorado. This settlement amount approximated Generation’s reserve for this matter. Settlements with the two primary Cotter insurers were also concluded, under which they paid Generation approximately $20 million, which covered the amount previously reserved as well as certain other costs incurred by Generation related to this matter. Neither of these settlements affects the environmental liability associated with the West Lake Landfill. For additional information, see ITEM 1. Environmental Regulation.
General
Exelon, ComEd, PECO and Generation are involved in various other litigation matters that are being defended and handled in the ordinary course of business. Exelon, ComEd, PECO and Generation maintain accruals for such costs that are probable of being incurred and subject to reasonable estimation. The ultimate outcomes of such matters, as well as the matters discussed above, are uncertain and may have a material adverse effect on their respective financial condition, results of operations or cash flows.
| ITEM 4. | SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS |
Exelon, ComEd, PECO and Generation
None.
38
PART II
(Dollars in million except per share data, unless otherwise noted)
| ITEM 5. | MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES |
Exelon
Exelon’s common stock is listed on the New York Stock Exchange. See Note 24 of Exelon’s Notes to Consolidated Financial Statements for the high and low sales prices, closing prices and dividends for Exelon’s common stock for 2004 and 2003 on a per share basis. As of January 31, 2005, there were 664,807,122 shares of common stock outstanding and approximately 166,575 shareholders of common stock of record.
On January 27, 2004, the Exelon Board of Directors approved a 2-for-1 stock split of Exelon’s common stock. The distribution date was May 5, 2004. The authorized common stock was increased from 600,000,000 shares with no par value to 1,200,000,000 shares with no par value. The share and per-share amounts related to Exelon included in this Form 10-K have been adjusted for all periods presented to reflect the stock split.
The attached table gives information on a monthly basis regarding purchases made by Exelon of its common stock.
| Period |
Total Number of Shares Purchased (a) |
Average Price Paid per Share |
Total Number of Shares Purchased As Part of Publicly Announced Plans or Programs (b) |
Maximum Number (or Approximate Dollar Value) of Shares that May Yet Be Purchased Under the Plans or Programs |
||||||
| October 1—October 31, 2004 |
11,396 | $ | 36.85 | — | (b | ) | ||||
| November 1—November 30, 2004 |
220,287 | 40.47 | — | (b | ) | |||||
| December 1—December 31, 2004 |
1,750 | 41.87 | — | (b | ) | |||||
| Total |
233,433 | 40.31 | — | (b | ) | |||||
| (a) | Shares other than those purchased as a part of a publicly announced plan primarily represent restricted shares surrendered by employees to satisfy tax obligations arising upon the vesting of restricted shares and shares repurchased from an executive upon retirement from Exelon. |
| (b) | In April 2004, Exelon’s Board of Directors approved a discretionary share repurchase program that allows Exelon to repurchase shares of its common stock on a periodic basis in the open market. The share repurchase program is intended to mitigate, in part, the dilutive effect of shares issued under Exelon’s employee stock option plan and Exelon’s Employee Stock Purchase Plan (ESPP). The aggregate shares of common stock repurchased pursuant to the program cannot exceed the economic benefit received after January 1, 2004 due to stock option exercises and share purchases pursuant to Exelon’s ESPP. The economic benefit consists of direct cash proceeds from purchases of stock and tax benefits associated with exercises of stock options. The share repurchase program has no specified limit and no specified termination date. |
ComEd
As of January 31, 2005, there were outstanding 127,016,502 shares of common stock, $12.50 par value, of ComEd, of which 127,002,904 shares were held by Exelon. At January 31, 2005, in addition to Exelon, there were 275 holders of ComEd common stock. There is no established market for shares of the common stock of ComEd.
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PECO
As of January 31, 2005, there were outstanding 170,478,507 shares of common stock, without par value, of PECO, all of which were held by Exelon.
Generation
As of January 31, 2005, Exelon held the entire membership interest in Generation.
Exelon, ComEd, PECO and Generation
Dividends
Under applicable Federal law, Exelon, ComEd, PECO and Generation can pay dividends only from retained, undistributed or current earnings. A significant loss recorded at ComEd, PECO or Generation may limit the dividends that these companies can distribute to Exelon.
Under Illinois law, ComEd may not pay any dividend on its stock unless, among other things, “[its] earnings and earned surplus are sufficient to declare and pay same after provision is made for reasonable and proper reserves,” or unless it has specific authorization from the ICC. At December 31, 2004, Exelon had retained earnings of $3.3 billion, which includes ComEd’s retained earnings of $1,102 million (all of which had been appropriated for future dividends), PECO’s retained earnings of $607 million and Generation’s undistributed earnings of $761 million.
The following table sets forth Exelon’s quarterly cash dividends paid during 2004 and 2003:
| 2004 |
2003 | |||||||||||||||||||||||
| (per share) |
4th Quarter |
3rd Quarter |
2nd Quarter |
1st Quarter |
4th Quarter |
3rd Quarter |
2nd Quarter |
1st Quarter | ||||||||||||||||
| Exelon |
$ | 0.400 | $ | 0.305 | $ | 0.275 | $ | 0.275 | $ | 0.250 | $ | 0.250 | $ | 0.230 | $ | 0.230 | ||||||||
The following table sets forth ComEd’s and PECO’s quarterly common dividend payments and Generation’s quarterly distributions:
| 2004 |
2003 | |||||||||||||||||||||||
| (in millions) |
4th Quarter |
3rd Quarter |
2nd Quarter |
1st Quarter |
4th Quarter |
3rd Quarter |
2nd Quarter |
1st Quarter | ||||||||||||||||
| ComEd |
$ | 137 | $ | 113 | $ | 104 | $ | 103 | $ | 95 | $ | 95 | $ | 90 | $ | 121 | ||||||||
| PECO |
115 | 96 | 90 | 90 | 79 | 79 | 75 | 90 | ||||||||||||||||
| Generation |
335 | 61 | 55 | 54 | 73 | 71 | 45 | — | ||||||||||||||||
On January 27, 2004, the Exelon Board of Directors declared a quarterly dividend of $0.275 per share on Exelon’s common stock. On July 27, 2004, the Exelon Board of Directors declared a quarterly dividend of $0.305 per share on Exelon’s common stock and approved a policy of targeting a dividend payout ratio of 50 to 60% of ongoing earnings and authorized a plan to achieve that level of payout for the full year of 2005. The actual dividend payout rate depends on Exelon achieving its objectives, including meeting cash flow targets and strengthening its balance sheet. On October 19, 2004 and January 25, 2005, the Exelon Board of Directors approved quarterly dividends of $0.40 per share, reflecting an annual dividend of $1.60 per share. The Board of Directors must approve the dividends each quarter after review of Exelon’s financial condition at that time.
The Merger Agreement between Exelon and PSEG provides that, subject to applicable law and the fiduciary duties of its board of directors, Exelon will increase its quarterly dividend so that the first
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dividend paid after completion of the Merger is an amount equal, on an exchange ratio adjusted basis, to the dividend PSEG shareholders received in the quarter immediately prior to completion of the Merger, up to a maximum of $0.47 per share of Exelon common stock (the lesser of $0.47 and the amount required to equal PSEG’s dividend on an exchange ratio adjusted basis being referred to as the threshold amount (threshold amount)). Exelon has agreed that as close to 30 days prior to the anticipated closing of the Merger as reasonably practicable, it will notify PSEG of what it believes its first quarterly dividend following completion of the Merger will be. If that dividend is less than the threshold amount, PSEG may make a one time special cash dividend to its shareholders equal to the amount of the difference between the dividend Exelon has informed PSEG it will pay and the threshold amount on an exchange ratio adjusted basis.
ComEd may not declare dividends on any shares of its capital stock in the event that: (1) it exercises its right to extend the interest payment periods on the subordinated debt securities which were issued to ComEd Financing II and ComEd Financing III (the Financing Trusts); (2) it defaults on its guarantee of the payment of distributions on the preferred trust securities of the Financing Trusts; or (3) an event of default occurs under the Indenture under which the subordinated debt securities are issued (see ITEM 1. Business—Other Subsidiaries of ComEd and PECO with Publicly Held Securities). As of December 31, 2004, ComEd had appropriated $1,102 million of retained earnings for future dividend payments.
PECO’s Articles of Incorporation prohibit payment of any dividend on, or other distribution to the holders of, common stock if, after giving effect thereto, the capital of PECO represented by its common stock together with its retained earnings is, in the aggregate, less than the involuntary liquidating value of its then outstanding preferred stock. At December 31, 2004, such capital was $2.8 billion and amounted to about 32 times the liquidating value of the outstanding preferred stock of $87 million.
PECO may not declare dividends on any shares of its capital stock in the event that: (1) it exercises its right to extend the interest payment periods on the subordinated debentures which were issued to PEC L.P. or PECO Trust IV; (2) it defaults on its guarantee of the payment of distributions on the Series D Preferred Securities of PEC L.P. or the preferred trust securities of PECO Trust IV; or (3) an event of default occurs under the Indenture under which the subordinated debentures are issued (see ITEM 1. Business—Other Subsidiaries of ComEd and PECO with Publicly Held Securities).
ITEM 6. SELECTED FINANCIAL DATA
The selected financial data presented below has been derived from the audited consolidated financial statements of Exelon. This data is qualified in its entirety by reference to and should be read in conjunction with Exelon’s Consolidated Financial Statements and Management’s Discussion and Analysis of Financial Condition and Results of Operation included in ITEM 7 of this Report on Form 10-K.
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Results for 2000 reflect the effects of the merger of Exelon Corporation, Unicom and PECO on October 20, 2000. That merger was accounted for using the purchase method of accounting with PECO as the acquiring company. Accordingly, financial results for 2000 consist of PECO’s results for 2000 and Unicom’s results after October 20, 2000.
| For the Years Ended December 31, | ||||||||||||||||
| in millions, except for per share data |
2004 |
2003 |
2002 |
2001 |
2000 | |||||||||||
| Statement of Income data: |
||||||||||||||||
| Operating revenues |
$ | 14,515 | $ | 15,812 | $ | 14,955 | $ | 14,918 | $ | 7,499 | ||||||
| Operating income |
3,433 | 2,277 | 3,299 | 3,362 | 1,527 | |||||||||||
| Income before cumulative effect of changes in accounting principles |
$ | 1,841 | $ | 793 | $ | 1,670 | $ | 1,416 | $ | 562 | ||||||
| Cumulative effect of changes in accounting principles (net of income taxes) |
23 | 112 | (230 | ) | 12 | 24 | ||||||||||
| Net income |
$ | 1,864 | $ | 905 | $ | 1,440 | $ | 1,428 | $ | 586 | ||||||
| Earnings per average common share (diluted): |
||||||||||||||||
| Income before cumulative effect of changes in accounting principles |
$ | 2.75 | $ | 1.21 | $ | 2.57 | $ | 2.19 | $ | 1.38 | ||||||
| Cumulative effect of changes in accounting principles (net of income taxes) |
0.03 | 0.17 | (0.35 | ) | 0.02 | 0.06 | ||||||||||
| Net income |
$ | 2.78 | $ | 1.38 | $ | 2.22 | $ | 2.21 | $ | 1.44 | ||||||
| Dividends per common share |
$ | 1.26 | $ | 0.96 | $ | 0.88 | $ | 0.91 | $ | 0.46 | ||||||
| Average shares of common stock outstanding—diluted |
669 | 657 | 649 | 645 | 408 | |||||||||||
| December 31, | |||||||||||||||
| in millions |
2004 |
2003 |
2002 |
2001 |
2000 | ||||||||||
| Balance Sheet data: |
|||||||||||||||
| Current assets |
$ | 3,926 | $ | 4,561 | $ | 4,125 | $ | 3,735 | $ | 4,151 | |||||
| Property, plant and equipment, net |
21,482 | 20,630 | 17,957 | 14,665 | 15,914 | ||||||||||
| Noncurrent regulatory assets |
4,790 | 5,226 | 5,546 | 5,774 | 6,045 | ||||||||||
| Goodwill |
4,705 | 4,719 | 4,992 | 5,335 | 5,186 | ||||||||||
| Other deferred debits and other assets |
7,867 | 6,800 | 5,249 | 5,460 | 5,378 | ||||||||||
| Total assets |
$ | 42,770 | $ | 41,936 | $ | 37,869 | $ | 34,969 | $ | 36,674 | |||||
| Current liabilities |
$ | 4,882 | $ | 5,720 | $ | 5,874 | $ | 4,370 | $ | 4,993 | |||||
| Long-term debt, including long-term debt to financing trusts (a) |
12,148 | 13,489 | 13,127 | 12,879 | 12,958 | ||||||||||
| Regulatory liabilities |
2,204 | 1,891 | 486 | 225 | 1,888 | ||||||||||
| Other deferred credits and other liabilities |
13,984 | 12,246 | 9,968 | 8,749 | 8,959 | ||||||||||
| Minority interest |
42 | — | 77 | 31 | 31 | ||||||||||
| Preferred securities of subsidiaries (a) |
87 | 87 | 595 | 613 | 630 | ||||||||||
| Shareholders’ equity |
9,423 | 8,503 | 7,742 | 8,102 | 7,215 | ||||||||||
| Total liabilities and shareholders’ equity |
$ | 42,770 | $ | 41,936 | $ | 37,869 | $ | 34,969 | $ | 36,674 | |||||
| (a) | The mandatorily redeemable preferred securities of ComEd and PECO were reclassified as long-term debt to financing trusts in 2003 in accordance with FIN 46-R and FIN 46, “Consolidation of Variable Interest Entities” (FIN 46). |
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The selected financial data presented below has been derived from the audited consolidated financial statements of ComEd. This data is qualified in its entirety by reference to and should be read in conjunction with ComEd’s Consolidated Financial Statements and Management’s Discussion and Analysis of Financial Condition and Results of Operation included in ITEM 7 of this Report on Form 10-K.
ComEd was the principal subsidiary of Unicom prior to the merger with Exelon on October 20, 2000. The merger was accounted for using the purchase method of accounting in accordance with GAAP. The effects of the purchase method were reflected in the consolidated financial statements of ComEd as of October 20, 2000. Accordingly, ComEd’s consolidated financial statements presented for the period after that merger reflect a new basis of accounting. The information for the year ended 2000 is presented for the periods before and after the merger.
| For the Years Ended December 31, |
Oct. 20 - Dec. 31 2000 |
Jan. 1 - Oct. 19 2000 | ||||||||||||||||
| (in millions) |
2004 |
2003 |
2002 |
2001 |
||||||||||||||
| Statement of Income data: |
||||||||||||||||||
| Operating revenues |
$ | 5,803 | $ | 5,814 | $ | 6,124 | $ | 6,206 | $ | 1,310 | $ | 5,702 | ||||||
| Operating income |
1,617 | 1,567 | 1,766 | 1,594 | 338 | 1,048 | ||||||||||||
| Income before cumulative effect of changes in accounting principles |
$ | 676 | $ | 702 | $ | 790 | $ | 607 | $ | 133 | $ | 599 | ||||||
| Cumulative effect of a change in accounting principle (net of income taxes) |
— | 5 | — | — | — | — | ||||||||||||
| Net income |
$ | 676 | $ | 707 | $ | 790 | $ | 607 | $ | 133 | $ | 599 | ||||||
| December 31, | |||||||||||||||
| (in millions) |
2004 |
2003 |
2002 |
2001 |
2000 | ||||||||||
| Balance Sheet data: |
|||||||||||||||
| Current assets |
$ | 1,196 | $ | 1,313 | $ | 1,049 | $ | 1,025 | $ | 2,172 | |||||
| Property, plant and equipment, net |
9,463 | 9,096 | 8,689 | 8,243 | 10,655 | ||||||||||
| Goodwill, net |
4,705 | 4,719 | 4,916 | 4,902 | 4,766 | ||||||||||
| Other deferred debits and other assets |
2,077 | 2,837 | 1,662 | 1,682 | 4,493 | ||||||||||
| Total assets |
$ | 17,441 | $ | 17,965 | $ | 16,316 | $ | 15,852 | $ | 22,086 | |||||
| Current liabilities |
$ | 1,764 | $ | 1,557 | $ | 2,023 | $ | 1,797 | $ | 1,723 | |||||
| Long-term debt, including long-term debt to financing trusts (a) |
4,282 | 5,887 | 5,268 | 5,850 | 6,882 | ||||||||||
| Regulatory liabilities |
2,204 | 1,891 | 486 | 225 | 1,888 | ||||||||||
| Other deferred credits and other liabilities |
2,451 | 2,288 | 2,451 | 2,568 | 5,082 | ||||||||||
| Mandatorily redeemable preferred securities of subsidiary trusts (a) |
— | — | 330 | 329 | 328 | ||||||||||
| Shareholders’ equity |
6,740 | 6,342 | 5,758 | 5,083 | 6,183 | ||||||||||
| Total liabilities and shareholders’ equity |
$ | 17,441 | $ | 17,965 | $ | 16,316 | $ | 15,852 | $ | 22,086 | |||||
| (a) | Due to the adoption of FIN 46-R in 2003, the mandatorily redeemable preferred securities were reclassified as long-term debt to financing trusts as of December 31, 2003. |
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The selected financial data presented below has been derived from the audited consolidated financial statements of PECO. This data is qualified in its entirety by reference to and should be read in conjunction with PECO’s Consolidated Financial Statements and Management’s Discussion and Analysis of Financial Condition and Results of Operation included in ITEM 7 of this Report on Form 10-K.
| For the Years Ended December 31, | |||||||||||||||
| (in millions) |
2004 |
2003 |
2002 |
2001 |
2000 | ||||||||||
| Statement of Income data: |
|||||||||||||||
| Operating revenues |
$ | 4,487 | $ | 4,388 | $ | 4,333 | $ | 3,965 | $ | 5,950 | |||||
| Operating income |
1,014 | 1,056 | 1,093 | 999 | 1,222 | ||||||||||
| Income before cumulative effect of a change in accounting principle |
$ | 455 | $ | 473 | $ | 486 | $ | 425 | $ | 483 | |||||
| Cumulative effect of a change in accounting principle (net of income taxes) |
— | — | — | — | 24 | ||||||||||
| Net income |
$ | 455 | $ | 473 | $ | 486 | $ | 425 | $ | 507 | |||||
| Net income on common stock |
$ | 452 | $ | 468 | $ | 478 | $ | 415 | $ | 497 | |||||
| December 31, | |||||||||||||||
| (in millions) |
2004 |
2003 |
2002 |
2001 |
2000 | ||||||||||
| Balance Sheet data: |
|||||||||||||||
| Current assets |
$ | 773 | $ | 696 | $ | 927 | $ | 813 | $ | 1,779 | |||||
| Property, plant and equipment, net |
4,329 | 4,256 | 4,159 | 4,039 | 5,138 | ||||||||||
| Noncurrent regulatory assets |
4,790 | 5,226 | 5,546 | 5,774 | 6,046 | ||||||||||
| Other deferred debits and other assets |
241 | 232 | 88 | 112 | 1,813 | ||||||||||
| Total assets |
$ | 10,133 | $ | 10,410 | $ | 10,720 | $ | 10,738 | $ | 14,776 | |||||
| Current liabilities |
$ | 794 | $ | 713 | $ | 1,538 | $ | 1,335 | $ | 2,974 | |||||
| Long-term debt, including long-term debt to financing trusts (a) |
4,628 | 5,239 | 4,951 | 5,438 | 6,002 | ||||||||||
| Deferred credits and other liabilities |
3,313 | 3,442 | 3,342 | 3,358 | 3,860 | ||||||||||
| Mandatorily redeemable preferred securities of subsidiary trusts (a) |
— | — | 128 | 128 | 128 | ||||||||||
| Mandatorily redeemable preferred stock |
— | — | 19 | 37 | |||||||||||
| Shareholders’ equity |
1,398 | 1,016 | 761 | 460 | 1,775 | ||||||||||
| Total liabilities and shareholders’ equity |
$ | 10,133 | $ | 10,410 | $ | 10,720 | $ | 10,738 | $ | 14,776 | |||||
| (a) | Due to the adoptions of FIN 46 and FIN 46-R in 2003, the mandatorily redeemable preferred securities were reclassified as long-term debt to financing trusts in 2003. |
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The selected financial data presented below has been derived from the audited consolidated financial statements of Generation. This data is qualified in its entirety by reference to and should be read in conjunction with Generation’s Consolidated Financial Statements and Management’s Discussion and Analysis of Financial Condition and Results of Operation included in ITEM 7 of this Report on Form 10-K.
The consolidated financial statements of Generation as of December 31, 2000 and for the year then ended present the financial position, results of operations and net cash flows of the generation- related business of Exelon prior to its corporate restructuring on January 1, 2001. The results of operations for Exelon Energy Company are not included in periods prior to 2004.
| For the Years Ended December 31, | ||||||||||||||||
| (in millions) |
2004 |
2003 |
2002 |
2001 |
2000 | |||||||||||
| Statement of Income data: |
||||||||||||||||
| Operating revenues |
$ | 7,938 | $ | 8,135 | $ | 6,858 | $ | 6,826 | $ | 3,274 | ||||||
| Operating income (loss) |
1,030 | (115 | ) | 509 | 872 | 441 | ||||||||||
| Income (loss) before cumulative effect of changes in accounting principles |
$ | 641 | $ | (241 | ) | $ | 387 | $ | 512 | $ | 260 | |||||
| Cumulative effect of changes in accounting principles (net of income taxes) |
32 | 108 | 13 | 12 | — | |||||||||||
| Net income (loss) |
$ | 673 | $ | (133 | ) | $ | 400 | $ | 524 | $ | 260 | |||||
| December 31, | ||||||||||||||||
| (in millions) |
2004 |
2003 |
2002 |
2001 |
2000 | |||||||||||
| Balance Sheet data: |
||||||||||||||||
| Current assets |
$ | 2,321 | $ | 2,438 | $ | 1,805 | $ | 1,435 | $ | 1,793 | ||||||
| Property, plant and equipment, net |
7,536 | 7,106 | 4,698 | 2,003 | 1,727 | |||||||||||
| Deferred debits and other assets |
6,581 | 5,105 | 4,402 | 4,700 | 4,742 | |||||||||||
| Total assets |
$ | 16,438 | $ | 14,649 | $ | 10,905 | $ | 8,138 | $ | 8,262 | ||||||
| Current liabilities |
$ | 2,416 | $ | 3,553 | $ | 2,594 | $ | 1,097 | $ | 2,176 | ||||||
| Long-term debt |
2,583 | 1,649 | 2,132 | 1,021 | 205 | |||||||||||
| Deferred credits and other liabilities |
8,356 | 6,488 | 3,226 | 3,212 | 3,271 | |||||||||||
| Minority interest |
44 | 3 | 54 | — | — | |||||||||||
| Member’s equity |
3,039 | 2,956 | 2,899 | 2,808 | 2,610 | |||||||||||
| Total liabilities and member’s equity |
$ | 16,438 | $ | 14,649 | $ | 10,905 | $ | 8,138 | $ | 8,262 | ||||||
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| ITEM 7. | MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATION |
Exelon, ComEd, PECO and Generation
The Critical Accounting Policies and Estimates and New Accounting Pronouncement sections presented below indicate the registrant or registrants to which each policy, estimate or accounting standard is applicable.
Critical Accounting Policies and Estimates
The preparation of financial statements in conformity with GAAP requires that management apply accounting policies and make estimates and assumptions that affect results of operations and the amounts of assets and liabilities reported in the financial statements. Management discusses these policies, estimates and assumptions within its Accounting and Disclosure Governance Committee on a regular basis and provides periodic updates on management decisions to the Audit Committee of the Exelon Board of Directors. Management believes that the areas described below require significant judgment in the application of accounting policy or in making estimates and assumptions in matters that are inherently uncertain and that may change in subsequent periods. Further discussion of the application of these accounting policies can be found in the Registrants’ Notes to Consolidated Financial Statements.
Asset Retirement Obligations (Exelon, ComEd, PECO and Generation)
Nuclear Decommissioning (Exelon and Generation)
Generation must make significant estimates and assumptions in accounting for its obligation to decommission its nuclear generating plants in accordance with SFAS No. 143, “Accounting for Asset Retirement Obligations” (SFAS No. 143).
SFAS No. 143 requires that Generation estimate the fair value of its obligation for the future decommissioning of its nuclear generating plants. To estimate that fair value, Generation uses a probability-weighted, discounted cash flow model considering multiple outcome scenarios based upon significant assumptions embedded in the following:
Decommissioning Cost Studies. Generation uses decommissioning cost studies prepared by a third party to provide a marketplace assessment of costs and the timing of decommissioning activities validated by comparison to current decommissioning projects and other third-party estimates.
Cost Escalation Studies. Cost escalation studies are used to determine escalation factors and are based on inflation indices for labor, equipment and materials, energy and low-level radioactive waste disposal costs.
Probabilistic Cash Flow Models. Generation’s probabilistic cash flow models include the assignment of probabilities to various cost levels and various timing scenarios. The probability of various timing scenarios incorporate the factors of current license lives, anticipated license renewals and the timing of DOE acceptance for disposal of spent nuclear fuel.
Discount Rates. The probability-weighted estimated cash flows using these various scenarios are discounted using credit-adjusted, risk-free rates applicable to the various businesses.
Changes in the assumptions underlying the foregoing items could materially affect the decommissioning obligation recorded and could affect future updates to the decommissioning obligation to be recorded in the consolidated financial statements. For example, the 20-year average cost escalation rates used in the current ARO calculation approximate 3% to 4%. A uniform increase in these escalation rates of 25 basis points would increase the total ARO recorded by Exelon by
46
approximately 11% or more than $400 million. Under SFAS No. 143, the nuclear decommissioning obligation is adjusted on an ongoing basis due to the passage of time and revisions to either the timing or amount of the original estimate of undiscounted cash flows. For more information regarding the adoption and ongoing application of SFAS No. 143, see Note 1 and Note 14 of Exelon’s Notes to Consolidated Financial Statements.
Other Asset Retirement Obligations (Exelon, ComEd, PECO and Generation)
The FASB has issued an exposure draft of proposed interpretations of SFAS No. 143. The exposure draft addresses the accounting for conditional asset retirement obligations. The proposed guidance is not anticipated to have any impact on Generation’s asset retirement obligations for nuclear decommissioning but may result in the recording of liabilities at Exelon, ComEd, PECO and Generation for conditional legal obligations meeting the scope of the interpretation.
Asset Impairments (Exelon, ComEd, PECO and Generation)
Goodwill (Exelon and ComEd)
Exelon and ComEd had approximately $4.7 billion of goodwill recorded at December 31, 2004, which relates entirely to the goodwill recorded upon the acquisition of ComEd. Exelon and ComEd perform assessments for impairment of their goodwill at least annually, or more frequently if events or circumstances indicate that goodwill might be impaired. Application of the goodwill impairment test requires management’s judgments, including the identification of reporting units, assigning assets and liabilities to reporting units, assigning goodwill to reporting units, and determining the fair value of each reporting unit.
Exelon and ComEd performed their annual assessments of goodwill impairment as of November 1, 2004 and determined that goodwill was not impaired. Exelon assesses goodwill impairment at its Energy Delivery reporting unit; accordingly, a goodwill impairment charge at ComEd may not necessarily affect Exelon’s results of operations as the goodwill impairment test for Exelon considers the cash flows of the entire consolidated Energy Delivery business segment, which includes both ComEd and PECO.
In the assessments, Exelon and ComEd estimated the fair value of the Energy Delivery and ComEd reporting units using a probability-weighted, discounted cash flow model with multiple scenarios. The fair value determination is dependent on many sensitive, interrelated and uncertain variables, including changing interest rates, utility sector market performance, the capital structures of Energy Delivery and ComEd, market prices for power, post-2006 rate regulatory structures, operating and capital expenditure requirements, and other factors. Changes in assumptions regarding these variables or in the assessment of how they interrelate could produce a different impairment result, which could be material. For example, a hypothetical decrease of approximately 10% in Energy Delivery’s and ComEd’s expected discounted cash flows would result in no impairment at Exelon, but an estimated impairment of goodwill of approximately $1.7 billion at ComEd.
Long-Lived Assets (Exelon, ComEd, PECO and Generation)
Exelon, ComEd, PECO and Generation evaluate the carrying value of their long-lived assets, excluding goodwill, when circumstances indicate the carrying value of those assets may not be recoverable. The review of long-lived assets for impairment requires significant assumptions about operating strategies and estimates of future cash flows, which require assessments of current and projected market conditions. For the generation business, forecasting future cash flows requires assumptions regarding forecasted commodity prices for the sale of power and costs of fuel. A variation in the assumptions used could lead to a different conclusion regarding the realizability of an asset and, thus, could have a significant effect on the consolidated financial statements.
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Investments (Exelon, ComEd, PECO and Generation)
Exelon, ComEd, PECO and Generation had approximately $6,066 million, $91 million, $109 million and $5,365 million, respectively, of investments, including investments held in nuclear decommissioning trust funds, recorded as of December 31, 2004. Exelon, ComEd, PECO and Generation consider investments to be impaired when a decline in fair value below cost is judged to be other-than-temporary. If the cost of an investment exceeds its fair value, they evaluate, among other factors, general market conditions, the duration and extent to which the fair value is less than cost, as well as their intent and ability to hold the investment. The Registrants also consider specific adverse conditions related to the financial health of and business outlook for the investee.
Defined Benefit Pension and Other Postretirement Welfare Benefits (Exelon, ComEd, PECO and Generation)
Exelon sponsors defined benefit pension plans and postretirement welfare benefit plans applicable to essentially all ComEd, PECO, Generation and BSC employees and certain Enterprises employees. See Note 15 of Exelon’s Notes to Consolidated Financial Statements for further information regarding the accounting for Exelon’s defined benefit pension plans and postretirement welfare benefit plans.
The costs of providing benefits under these plans are dependent on historical information such as employee age, length of service and level of compensation, and the actual rate of return on plan assets. Also, Exelon utilizes assumptions about the future, including the expected rate of return on plan assets, the discount rate applied to benefit obligations, rate of compensation increases and the anticipated rate of increase in health care costs.
The selection of key actuarial assumptions utilized in the measurement of the plan obligations and costs drives the results of the analysis and the resulting charges. The long-term expected rate of return on plan assets (EROA) assumption used in calculating pension cost was 9.00% in 2004 and 2003 compared to 9.50% for 2002. The weighted average EROA assumption used in calculating other postretirement benefit costs ranged from 8.33% to 8.35% in 2004 compared to 8.40% in 2003 and 8.80% for 2002. A lower EROA is used in the calculation of other postretirement benefit costs, as the other postretirement benefit trust activity is partially taxable while the pension trust activity is non-taxable. The Moody’s Aa Corporate Bond Index was used as the basis in selecting the discount rate for determining the plan obligations, using 5.75%, 6.25% and 6.75% at December 31, 2004, 2003 and 2002, respectively. The reduction in the discount rate is due to the decline in Moody’s Aa Corporate Bond Index in 2004 and 2003.
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The following tables illustrate the effects of changing the major actuarial assumptions discussed above:
| Change in Actuarial Assumption |
Impact on Projected Benefit Obligation at December 31, 2004 |
Impact on Pension Liability at December 31, 2004 |
Impact on 2005 Pension Cost | ||||||
| Pension benefits |
|||||||||
| Decrease discount rate by 0.5% |
$626 | $535 | $40 | ||||||
| Decrease rate of return on plan assets by 0.5% |
— | — | 35 | ||||||
| Change in Actuarial Assumption |
Impact on Other Postretirement Benefit Obligation at December 31, 2004 |
Impact on Postretirement Benefit Liability at December 31, 2004 |
Impact on 2005 Postretirement Benefit Cost | ||||||
| Postretirement benefits |
|||||||||
| Decrease discount rate by 0.5% |
$ | 174 | $ | — | $ | 17 | |||
| Decrease rate of return on plan assets by 0.5% |
— | — | 5 | ||||||
Assumed health care cost trend rates also have a significant effect on the costs reported for Exelon’s postretirement benefit plans. To estimate the 2004 cost, Exelon assumed a health care cost trend rate of 10%, decreasing to an ultimate trend rate of 4.5% in 2011, compared to the 2003 assumption of 8.5%, decreasing to an ultimate trend rate of 4.5% in 2008. To estimate the 2005 cost, Exelon will assume a health care cost trend rate of 9%, decreasing to an ultimate trend rate of 5% in 2010. A one-percentage point change in assumed health care cost trend rates in 2004 would have the following effects:
| Effect of a one percentage point increase in assumed health care cost trend |
||||
| on total service and interest cost components |
$ | 34 | ||
| on postretirement benefit obligation |
$ | 327 | ||
| Effect of a one percentage point decrease in assumed health care cost trend |
||||
| on total service and interest cost components |
$ | (28 | ) | |
| on postretirement benefit obligation |
$ | (276 | ) |
The assumptions are reviewed at the beginning of each year during Exelon’s annual review process and at any interim remeasurement of the plan obligations. The impact of assumption changes is reflected in the recorded pension amounts as they occur, or over a period of time if allowed under applicable accounting standards. As these assumptions change from period to period, recorded pension amounts and funding requirements could also change.
In 2004, Exelon incurred approximately $294 million in costs associated with its pension and postretirement benefit plans, including curtailment and settlement costs of $24 million. Although 2005 pension and postretirement benefit costs will depend on market conditions, Exelon believes that its pension and postretirement benefit costs will decrease in 2005 due to an anticipated contribution of approximately $2 billion to the pension plans, partially offset by an increase in postretirement benefit costs due to a change in the assumed healthcare cost trend rate. Depending on the timing of the pension contribution, the estimated net decrease in 2005 pension and postretirement benefit costs could range from approximately $30 million to approximately $120 million. If the contribution is made on July 1, 2005, the estimated net decrease in 2005 pension and postretirement benefit cost would be approximately $75 million.
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Regulatory Accounting (Exelon, ComEd and PECO)
Exelon, ComEd and PECO account for their regulated electric and gas operations in accordance with SFAS No. 71, “Accounting for the Effects of Certain Types of Regulation” (SFAS No. 71), which requires Exelon, ComEd and PECO to reflect the effects of rate regulation in their financial statements. Use of SFAS No. 71 is applicable to utility operations that meet the following criteria: (1) third-party regulation of rates; (2) cost-based rates; and (3) a reasonable assumption that all costs will be recoverable from customers through rates. As of December 31, 2004, Exelon, ComEd and PECO have concluded that the operations of ComEd and PECO meet the criteria. If it is concluded in a future period that a separable portion of their businesses no longer meets the criteria, Exelon, ComEd and PECO are required to eliminate the financial statement effects of regulation for that part of their business, which would include the elimination of any or all regulatory assets and liabilities that had been recorded in their Consolidated Balance Sheets. The impact of not meeting the criteria of SFAS No. 71 could be material to the financial statements as a one-time extraordinary item and through impacts on continuing operations. See Note 5 and Note 2 of Exelon’s and ComEd’s Notes to Consolidated Financial Statements, respectively, for further information regarding regulatory issues.
Regulatory assets represent costs that have been deferred to future periods when it is probable that the regulator will allow for recovery through rates charged to customers. Regulatory liabilities represent revenues received from customers to fund expected costs that have not yet been incurred. As of December 31, 2004, Exelon and PECO had recorded $4.8 billion of net regulatory assets within their Consolidated Balance Sheets. At December 31, 2004, Exelon and ComEd had recorded $2.2 billion of net regulatory liabilities within their Consolidated Balance Sheets. See Note 21 of Exelon’s Notes to Consolidated Financial Statements for further information regarding the significant regulatory assets and liabilities of Exelon, ComEd and PECO.
For each regulatory jurisdiction where they conduct business, Exelon, ComEd and PECO continually assess whether the regulatory assets and liabilities continue to meet the criteria for probable future recovery or settlement. This assessment includes consideration of factors such as changes in applicable regulatory environments, recent rate orders to other regulated entities in the same jurisdiction, the status of any pending or potential deregulation legislation and the ability to recover costs through regulated rates.
The electric businesses of both ComEd and PECO are currently subject to rate freezes or rate caps that limit the opportunity to recover increased costs and the costs of new investment in facilities through rates during the rate freeze or rate cap period. Because the current rates include the recovery of existing regulatory assets and liabilities and rates in effect during the rate freeze or rate cap periods are expected to allow Exelon, ComEd and PECO to earn a reasonable rate of return during that period, management believes the existing regulatory assets and liabilities are probable of recovery. This determination reflects the current political and regulatory climate at the Federal level and in the states where ComEd and PECO do business but is subject to change in the future. If future recovery of costs ceases to be probable, the regulatory assets and liabilities would be recognized in current period earnings. A write-off of regulatory assets could limit the ability to pay dividends under PUHCA and state law.
Accounting for Derivative Instruments (Exelon, ComEd, PECO and Generation)
The Registrants enter into derivatives to manage their exposure to fluctuations in interest rates, changes in interest rates related to planned future debt issuances and changes in the fair value of outstanding debt. Generation utilizes derivatives with respect to energy transactions to manage the utilization of its available generating capability and provisions of wholesale energy to its affiliates. Generation also utilizes energy option contracts and energy financial swap arrangements to limit the
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market price risk associated with forward energy commodity contracts. Additionally, Generation enters into energy-related derivatives for trading purposes. All of the Registrant’s derivative activities are in accordance with Exelon’s Risk Management Policy (RMP).
The Registrants account for derivative financial instruments under SFAS No. 133, “Accounting for Derivatives and Hedging Activities” (SFAS No. 133). Under the provisions of SFAS No. 133, all derivatives are recognized on the balance sheet at their fair value unless they qualify for a normal purchases or normal sales exception. Derivatives recorded at fair value on the balance sheet are presented as current or noncurrent mark-to-market derivative assets or liabilities. Changes in the derivatives recorded at fair value are recognized in earnings unless specific hedge accounting criteria are met, in which case those changes are recorded in earnings as an offset to the changes in fair value of the exposure being hedged or deferred in accumulated other comprehensive income and recognized in earnings as hedged transaction occur.
Normal Purchases and Normal Sales Exception. The availability of the normal purchases and normal sales exception is based upon the assessment of the ability and intent to deliver or take delivery of the underlying item. This assessment is based primarily on internal models that forecast customer demand and electricity and gas supply. These models include assumptions regarding customer load growth rates, which are influenced by the economy, weather and the impact of customer choice, and generating unit availability, particularly nuclear generating unit capability factors. Significant changes in these assumptions could result in these contracts not qualifying for the normal purchases and normal sales exception.
Energy Contracts. Identification of an energy contract as a qualifying cash-flow hedge requires Generation to determine that the contract is in accordance with the RMP, the forecasted future transaction is probable, and the hedging relationship between the energy contract and the expected future purchase or sale of energy is expected to be highly effective at the initiation of the hedge and throughout the hedging relationship. Internal models that measure the statistical correlation between the derivative and the associated hedged item determine the effectiveness of such an energy contract designated as a hedge. Generation reassesses its cash-flow hedges on a regular basis to determine if they continue to be effective and that the forecasted future transactions are probable. When a contract does not meet the effective or probable criteria of SFAS No. 133, “Accounting for Derivatives and Hedging Activities” (SFAS No. 133) hedge accounting is discontinued and changes in the fair value of the derivative are recorded through earnings.
As a part of accounting for derivatives, the Registrants make estimates and assumptions concerning future commodity prices, load requirements, interest rates, the timing of future transactions and their probable cash flows, the fair value of contracts and the expected changes in the fair value in deciding whether or not to enter into derivative transactions, and in determining the initial accounting treatment for derivative transactions. Generation uses quoted exchange prices to the extent they are available or external broker quotes in order to determine the fair value of energy contracts. When external prices are not available, Generation uses internal models to determine the fair value. These internal models include assumptions of the future prices of energy based on the specific market in which the energy is being purchased, using externally available forward market pricing curves for all periods possible under the pricing model. Generation uses the Black model, a standard industry valuation model, to determine the fair value of energy derivative contracts that are marked-to-market.
Interest-Rate Derivative Instruments. To determine the fair value of interest-rate swap agreements, the Registrants use external dealer prices or internal valuation models that utilize assumptions of available market pricing curves.
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Depreciable Lives of Property, Plant and Equipment (Exelon, ComEd, PECO and Generation)
The Registrants have a significant investment in electric generation assets and electric and natural gas transmission and distribution assets. Depreciation of these assets is generally provided over their estimated service lives on a straight-line basis using the composite method. The estimation of service lives requires management judgment regarding the period of time that the assets will be in use. As circumstances warrant, depreciation estimates are reviewed to determine if any changes are needed. Changes to depreciation estimates in future periods could have a significant impact on the amount of depreciation charged to the financial statements.
In 2001, Generation extended the estimated service lives of certain nuclear-fuel generating facilities based upon Generation’s intent to apply for license renewals for these facilities. While Generation expects to apply for and obtain approval of license renewals for these facilities, circumstances may arise that would prevent Generation from obtaining additional license renewals. A change in depreciation estimates resulting from Generation’s inability to receive additional license renewals could have a significant effect on Generation’s results of operations.
Accounting for Contingencies (Exelon, ComEd, PECO and Generation)
In the preparation of their financial statements, the Registrants make judgments regarding the future outcome of contingent events and record amounts that are probable and reasonably estimated based upon available information. The amounts recorded may differ from the actual income or expense that occurs when the uncertainty is resolved. The estimates that the Registrants make in accounting for contingencies and the gains and losses that they record upon the ultimate resolution of these uncertainties have a significant effect on their financial statements. The accounting for taxation and environmental costs are further discussed below.
Taxation
The Registrants are required to make judgments regarding the potential tax effects of various financial transactions and ongoing operations to estimate their obligations to taxing authorities. These tax obligations include income, real estate, use and employment-related taxes, including taxes that are subject to ongoing appeals. Judgments include estimating reserves for potential adverse outcomes regarding tax positions that they have taken. The Registrants must also assess their ability to generate capital gains in future periods to realize tax benefits associated with capital losses previously generated or expected to be generated in future periods. Capital losses may be deducted only to the extent of capital gains realized during the year of the loss or during the three prior or five succeeding years. The Registrants do not record valuation allowances for deferred tax assets related to capital losses that the Registrants believe will be realized in future periods. Generation has recorded valuation allowances against certain deferred assets associated with capital losses due to the consolidation of Sithe. While the Registrants believe the resulting tax reserve balances as of December 31, 2004 reflect the probable expected outcome of these tax matters in accordance with SFAS No. 5, “Accounting for Contingencies,” and SFAS No. 109, “Accounting for Income Taxes,” the ultimate outcome of such matters could result in favorable or unfavorable adjustments to their consolidated financial statements and such adjustments could be material.
Environmental Costs
As of December 31, 2004, Exelon, ComEd, PECO and Generation had accrued liabilities of $124 million, $61 million, $47 million and $16 million, respectively, for environmental investigation and remediation costs. These liabilities are based upon estimates with respect to the number of sites for which the Registrants will be responsible, the scope and cost of work to be performed at each site, the portion of costs that will be shared with other parties and the timing of the remediation work. Where
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timing and costs of expenditures can be reliably estimated, amounts are discounted. These amounts represent $96 million, $55 million and $41 million, respectively, of the total accrued for Exelon, ComEd and PECO. Where timing and amounts cannot be reliably estimated, amounts are recognized on an undiscounted basis. Such amounts represent $28 million, $6 million, $6 million and $16 million, respectively, of the total accrued liabilities for Exelon, ComEd, PECO and Generation. Estimates can be affected by the factors noted above as well as by changes in technology, regulations or the requirements of local governmental authorities.
Severance Accounting (Exelon, ComEd, PECO and Generation)
The Registrants provide severance benefits to terminated employees pursuant to pre-existing severance plans primarily based upon each individual employee’s years of service with the Registrants and compensation level. The Registrants accrue severance benefits that are considered probable and can be reasonably estimated in accordance with SFAS No. 112, “Employer’s Accounting for Postemployment Benefits, an amendment of FASB Statements No. 5 and 43” (SFAS No. 112). A significant assumption in estimating severance charges is the determination of the number of positions to be eliminated. The Registrants base their estimates on their current plans and ability to determine the appropriate staffing levels to effectively operate their businesses. Exelon, ComEd, PECO and Generation recorded severance charges of $32 million, $10 million, $3 million and $2 million, respectively, in 2004 and severance charges of $135 million, $61 million, $16 million and $38 million, respectively, in 2003, related to personnel reductions. The Registrants may incur further severance costs if they identify additional positions to be eliminated. These costs will be recorded in the period in which the costs can be reasonably estimated.
Revenue Recognition (Exelon, ComEd, PECO and Generation)
Revenues related to the sale of energy are recorded when service is rendered or energy is delivered to customers. The determination of Energy Delivery’s and Exelon Energy Company’s energy sales to individual customers, however, is based on systematic readings of customer meters generally on a monthly basis. At the end of each month, amounts of energy delivered to customers since the date of the last meter reading are estimated, and corresponding unbilled revenue is recorded. This unbilled revenue is estimated each month based on daily customer usage measured by generation or gas throughput volume, estimated customer usage by class, estimated losses of energy during delivery to customers and applicable customer rates. Customer accounts receivable of ComEd, PECO, and Generation included estimates of $275 million, $143 million, and $64 million, respectively, for unbilled revenue as of December 31, 2004 as a result of unread meters at ComEd, PECO and Exelon Energy Company. Increases in volumes delivered to the utilities’ customers and favorable rate mix due to changes in usage patterns in customer classes in the period would increase unbilled revenue. Changes in the timing of meter reading schedules and the number and type of customers scheduled for each meter reading date would also have an effect on the estimated unbilled revenue; however, total operating revenues would remain materially unchanged.
The determination of Generation’s energy sales, excluding Exelon Energy Company, is based on estimated amounts delivered as well as fixed quantity sales. At the end of each month, amounts of energy delivered to customers during the month are estimated and the corresponding unbilled revenue is recorded. Customer accounts receivable of Exelon and Generation as of December 31, 2004 include unbilled energy revenues of $385 million related to unbilled energy sales of Generation. Increases in volumes delivered to the wholesale customers in the period would increase unbilled revenue.
Accounting for Ownership Interests in Variable Interest Entities (Exelon, ComEd, PECO and Generation)
At December 31, 2004, Exelon, through Generation, had a 50% interest in Sithe. In accordance with FIN 46-R, Exelon and Generation consolidated Sithe within their financial statements as of
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March 31, 2004. The determination that Sithe qualified as a variable interest entity and that Generation was the primary beneficiary under FIN 46-R required analysis of the economic benefits accruing to all parties pursuant to their ownership interests supplemented by management’s judgment. Sithe’s total assets and total liabilities as of December 31, 2004 were $1,356 million and $1,289 million, respectively. As required by FIN 46-R, upon the occurrence of a future triggering event, such as a change in ownership, the Registrant would reassess their investments to determine if they continue to qualify as the primary beneficiary. See Notes 3 and 25 of Exelon’s Notes to Consolidated Financial Statements for a discussion of the sale of Generation’s interest in Sithe, which was completed on January 31, 2005. Subsequent to the sale, Sithe will no longer be consolidated within the financial statements of Exelon or Generation.
In addition to Sithe, the Registrants reviewed other entities with which they have business relationships to determine if those entities were variable interest entities that should be consolidated under FIN 46-R and concluded that those entities should not be consolidated within the financial statements.
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Executive Overview
Financial Results. Exelon’s net income was $1,864 million in 2004 as compared to $905 million in 2003 and diluted earnings per average common share were $2.78 for 2004 as compared to $1.38 for 2003, primarily as a result of increased net income at Generation, lower losses at Enterprises and several significant charges in 2003 that did not recur in 2004, partially offset by decreased net income at Energy Delivery. Key drivers included the following:
| • | Increased net income at Generation—Generation provided net income of $673 million in 2004 compared to a net loss of $151 million in 2003. The increase in Generation’s net income reflects improved wholesale prices in 2004, the inclusion of a full year of AmerGen’s results in 2004, and impairment charges in 2003 of $945 million and $255 million (before income taxes) related to the long-lived assets of Boston Generating and Generation’s investment in Sithe, respectively. Generation’s 2004 income also includes an after-tax gain of $52 million on the sale of Boston Generating during the second quarter of 2004. See further discussion in “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Generation.” |
| • | Decreased losses at Enterprises—Enterprises reported a net loss of $22 million in 2004 compared to a net loss of $118 million in 2003. Enterprises’ comparative results reflect net pre-tax gains of $41 million recorded in 2004 related to the dispositions of certain businesses and investments, as well as investment impairment charges of $54 million recorded in 2003. See further discussion under “Investment Strategy” below and in “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Exelon Corporation—Results of Operations—Enterprises.” |
| • | Favorable tax effects from investments in synthetic fuel-producing facilities—Exelon’s investments in synthetic fuel-producing facilities increased 2004 after-tax earnings by $65 million as compared to 2003. |
| • | Decreased net income at Energy Delivery—Energy Delivery provided net income of $1,128 million in 2004 compared to $1,175 million in 2003. This decrease was primarily attributable to unfavorable weather conditions and charges recorded in connection with the early retirement of debt, partially offset by growth in Energy Delivery’s retail customer base and reduced severance and other charges in 2004 as compared to 2003. See further discussion in “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Energy Delivery.” |
Investment Strategy. In 2004, Exelon continued to follow a disciplined approach to investing to maximize earnings and cash flows from its assets and businesses, while selling those that do not meet its strategic goals. Highlights from 2004 include the following:
| • | Proposed Merger with PSEG—On December 20, 2004, Exelon entered into the Merger Agreement with PSEG, the holding company for an electric and gas utility company primarily located and serving customers in New Jersey, whereby PSEG will be merged with and into Exelon. Under the Merger Agreement, each share of PSEG common stock will be converted into 1.225 shares of Exelon common stock. As of December 31, 2004, PSEG’s market capitalization was over $12 billion. Additionally, PSEG, on a consolidated basis, has approximately $14 billion of outstanding debt which is currently anticipated to become part of Exelon’s consolidated debt. |
The Merger Agreement contains certain termination rights for both Exelon and PSEG, and further provides that, upon termination of the Merger Agreement under specified circumstances, (i) Exelon may be required to pay PSEG a termination fee of $400 million plus
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PSEG’s transaction expenses up to $40 million and (ii) PSEG may be required to pay Exelon a termination fee of $400 million plus Exelon’s transaction expenses up to $40 million. The Merger Agreement has been unanimously approved by both companies’ boards of directors but is contingent upon, among other things, the approval by shareholders of both companies, antitrust clearance and a number of regulatory approvals or reviews by federal and state energy authorities. On February 4, 2005, Exelon and PSEG filed for approval of the merger with the FERC, the New Jersey Board of Public Utilities (BPU) and the PUC. Exelon also filed a notice of the Merger with the ICC.
Exelon anticipates that the Merger will close within 12 months to 15 months after the announcement of the Merger Agreement in December 2004, subject to shareholder and regulatory approvals which cannot be assured.
| • | OSC with PSEG—Concurrent with the Merger Agreement, Generation entered into the OSC with PSEG Nuclear, LLC which commenced on January 17, 2005 relating to the operation of the Salem and Hope Creek nuclear generating stations. The OSC provides for Generation to provide a chief nuclear officer and other key personnel to oversee daily plant operations at the Hope Creek and Salem nuclear generating stations and to implement the Exelon operating model. PSEG Nuclear, LLC will continue as the license holder with exclusive legal authority to operate and maintain the plants, will retain responsibility for management oversight and will have full authority with respect to the marketing of its share of the output from the facilities. |
| • | Boston Generating—On May 25, 2004, Generation completed the sale, transfer and assignment of ownership of its indirect wholly owned subsidiary Boston Generating, which owns directly or indirectly the companies that own Mystic 4-7, Mystic 8 and 9 and Fore River generating facilities, to a special purpose entity owned by the lenders under Boston Generating’s $1.25 billion credit facility, resulting in an after-tax gain of $52 million. On September 1, 2004, Generation completed the transfer of plant operations and power marketing arrangements to the lenders’ special purpose entity and its contractors under Boston Generating’s credit facility. |
| • | Sithe—On September 29, 2004, Generation exercised its call option and entered into an agreement to acquire Reservoir’s 50% interest in Sithe for $97 million and, on November 1, 2004, Generation entered into an agreement to sell its anticipated 100% interest in Sithe to Dynegy Inc. for $135 million in cash. Generation closed on the call exercise and the sale of the resulting 100% interest in Sithe on January 31, 2005. The sale did not include Sithe International, Inc. (Sithe International), which was sold to a subsidiary of Generation on October 13, 2004. |
| • | Enterprises—Exelon continued its divestiture strategy for Enterprises by selling or winding down substantially all components of Enterprises. At December 31, 2004, Enterprises’ remaining assets totaled approximately $274 million in comparison to $697 million at December 31, 2003. Enterprises expects to receive aggregate proceeds of $268 million and recorded a net pre-tax gain of $41 million related to the dispositions of assets and investments in 2004. |
Financing Activities. During 2004, Exelon substantially strengthened its balance sheet and met its capital resource requirements primarily with internally generated cash. When necessary, Exelon obtains funds from external sources, including capital markets, and through bank borrowings. Highlights from 2004 include the following:
| • | ComEd retired $1.2 billion of its outstanding debt, including $1.0 billion prior to its maturity and $206 million at maturity, pursuant to an accelerated liability management plan. In connection with these retirements, ComEd recorded pre-tax charges totaling $130 million related to debt prepayment premiums and the write-off of previously deferred debt financing fees. |
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| • | In addition to the accelerated liability management plan, payments of approximately $728 million were made for the purpose of retiring PECO and ComEd transition trust long-term debt and approximately $176 million of other net long-term debt during 2004. |
| • | Exelon replaced its $750 million 364-day unsecured revolving credit agreement with a $1 billion five-year facility and reduced its $750 million three-year facility to $500 million. |
| • | Exelon’s Board of Directors approved a discretionary share repurchase program under which Exelon purchased common stock, now held as treasury shares, totaling $75 million during 2004. |
| • | Exelon’s Board of Directors approved a policy of targeting a dividend payout ratio of 50% to 60% of ongoing earnings, and Exelon expects a dividend payout in that range for the full year of 2005. The actual dividend payout rate depends on Exelon achieving its objectives, including meeting cash flow targets and strengthening its balance sheet. On October 29, 2004, the Exelon Board of Directors approved an increased quarterly dividend of $0.40 per share, which was consistent with the dividend policy approved in 2004. The Board of Directors must approve the dividends each quarter after review of Exelon’s financial condition at the time, and there can be no guarantees that this targeted dividend payout ratio will be achieved. |
Regulatory Developments—PJM Integration. On May 1, 2004, ComEd fully integrated its transmission facilities into PJM. PECO’s and ComEd’s membership in PJM supports Exelon’s commitment to competitive wholesale electric markets and will provide Exelon the benefits of more transparent, liquid and competitive markets for the sale and purchase of electric energy and capacity. Upon joining PJM, ComEd began incurring administrative fees, which are expected to approximate $25 million annually. Exelon believes such costs will ultimately be offset by the benefits of full access to a wholesale competitive marketplace and increased revenue requirements, particularly after ComEd’s regulatory transition period ends in 2006; however, changes in market dynamics could affect the ultimate financial impact on Exelon.
Outlook for 2005 and Beyond. Exelon’s future financial results will be affected by a number of factors, including the following:
Shorter Term: Weather conditions, wholesale market prices of electricity, fuel costs, interest rates, successful implementation of operational improvement initiatives and Exelon’s ability to generate electricity at low costs all affect Exelon’s operating revenues and related costs. If weather is warmer than normal in the summer months or colder than normal in the winter months, operating revenues at Exelon generally will be favorably affected. Operating revenues will also generally be favorably affected by increases in wholesale market prices.
Longer Term: The proposed merger with PSEG is expected to have a significant impact on Exelon’s results of operations, cash flows and financial position. See further discussion above at “Proposed Merger with PSEG” and in ITEM 1. Business—Proposed Merger with PSEG. Following is a discussion of the other non-merger-related items that will have a longer term impact on Exelon.
Restructuring in the U.S. electric industry is at a crossroads at both the Federal and state levels, with continuing debate on RTO and standard market platform issues, and in many states on the “post-transition” format. Some states abandoned failed transition plans (e.g., California); some states are adjusting current transition plans (e.g., Ohio); and the states of Illinois (by 2007) and Pennsylvania (by 2011) are considering options to preserve choice for large customers and rate stability for mass-market customers, while ensuring the financial returns needed for continuing investments in reliability. Exelon will continue to be an active participant in these policy debates, while continuing to focus on improving operations, controlling costs and providing a fair return to its investors.
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As Exelon looks toward the end of the restructuring transition periods and related rate freezes or caps in Illinois and Pennsylvania, Exelon will also continue to work with Federal and state regulators, state and local governments, customer representatives and other interested parties to develop appropriate processes for establishing future rates in restructured electricity markets. Exelon will strive to ensure that future rate structures recognize the substantial improvements Exelon has made, and will continue to make, in its transmission and distribution systems. ComEd and PECO will also work to ensure that ComEd’s and PECO’s rates are adequate to cover their costs of obtaining electric power and energy from their suppliers, which could include Generation, for the costs associated with procuring full-requirements power given Energy Delivery’s POLR obligations. ComEd intends to make various filings during 2005 to begin the process to establish rates for the post-transition period. As in the past, by working together with all interested parties, Exelon believes it can successfully meet these objectives and obtain fair recovery of its costs for providing service to its customers; however, if Exelon is unsuccessful, its results of operations and cash flows could be negatively affected after the transition periods.
Generation’s financial results will be affected by a number of factors, including the market changes in Illinois and Pennsylvania discussed above. While Generation has significantly hedged its market exposure in the short-term, over the long-term, Generation’s results will be affected by long-term changes in the market prices of power and fuel caused by supply and demand forces and environmental regulations. Generating companies must also work with regulators to ensure that a viable capacity market exists and that new units will be constructed in a timely manner to meet the growing demand for power. On the operating side, to meet Exelon’s financial goals, Generation’s nuclear units must continue their superior performance while controlling costs despite inflationary pressures and increasing security costs.
Exelon’s current plans are based on moderate kilowatthour sales growth (1% to 2%) from their current levels and stable wholesale power markets. Continued cost reduction initiatives are important to offset labor and material cost escalation, especially the double digit increases in health care costs. Despite these challenges, Exelon’s diverse mix of generation (nuclear, coal, purchased power, natural gas, hydroelectric, wind and other renewables), linked to a stable base of over five million customers, will provide a solid platform from which it will strive to meet these challenges.
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Results of Operations
Year Ended December 31, 2004 Compared to Year Ended December 31, 2003
Significant Operating Trends—Exelon
| Exelon Corporation |
2004 |
2003 |
Favorable (unfavorable) variance |
|||||||||
| Operating revenues |
$ | 14,515 | $ | 15,812 | $ | (1,297 | ) | |||||
| Purchased power and fuel expense |
5,082 | 6,375 | 1,293 | |||||||||
| Impairment of Boston Generating, LLC long-lived assets |
— | 945 | 945 | |||||||||
| Operating and maintenance expense |
3,976 | 4,508 | 532 | |||||||||
| Depreciation and amortization expense |
1,305 | 1,126 | (179 | ) | ||||||||
| Operating income |
3,433 | 2,277 | 1,156 | |||||||||
| Other income and deductions |
(921 | ) | (1,148 | ) | 227 | |||||||
| Income before income taxes, minority interest and cumulative effect of changes in accounting principles |
2,512 | 1,129 | 1,383 | |||||||||
| Income before cumulative effect of changes in accounting principles |
1,841 | 793 | 1,048 | |||||||||
| Income taxes |
692 | 331 | (361 | ) | ||||||||
| Net income |
1,864 | 905 | 959 | |||||||||
| Diluted earnings per share |
2.78 | 1.38 | 1.40 | |||||||||
Net Income. Net income for 2004 reflects income of $32 million, net of income taxes, for the adoption of FIN 46-R, partially offset by a loss of $9 million, net of income taxes, related to the adoption of Emerging Issues Task Force (EITF) Issue No. 03-16, “Accounting for Investments in Limited Liability Companies” (EITF 03-16). Net income for 2003 reflects income of $112 million, net of income taxes, for the adoption of SFAS No. 143. See Note 1 of Exelon’s Notes to Consolidated Financial Statements for further information regarding the adoptions of FIN 46-R, EITF 03-16 and SFAS No. 143.
Operating Revenues. Operating revenues decreased primarily due to decreased revenues at Enterprises due to the sale of the majority of its businesses since the third quarter of 2003, the sale of Boston Generating and Generation’s adoption of EITF No. 03-11, “Reporting Realized Gains and Losses on Derivative Instruments That Are Subject to FASB Statement No. 133, ‘Accounting for Derivative Instruments and Hedging Activities,’ and Not ‘Held for Trading Purposes’ as Defined in EITF Issue No. 02-3, ‘Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities’” (EITF 03-11) in the first quarter of 2004, which changed the presentation of certain power transactions and decreased 2004 operating revenues by $980 million. The adoption of EITF 03-11 had no impact on net income. Operating revenues were favorably affected by Generation’s acquisition of the remaining 50% of AmerGen and the consolidation of Sithe. Operating revenues were also favorably affected by Energy Delivery’s increased volume growth and transmission revenues collected from PJM, partially offset by unfavorable weather conditions and customer choice initiatives. See further discussion of operating revenues by segment below.
Purchased Power and Fuel Expense. Purchased power and fuel expense decreased primarily due to Generation’s adoption of EITF 03-11 during 2004 which resulted in a decrease in purchased power expense and fuel expense of $980 million. In addition, purchased power decreased due to Generation’s acquisition of the remaining 50% of AmerGen in December 2003, which was only partially offset by an increase in fuel expense, and the sale of Boston Generating. Purchased power represented 24% of Generation’s total supply in 2004 compared to 37% in 2003. Purchased power
59
also decreased due to Energy Delivery’s unfavorable weather conditions and customer choice initiatives, partially offset by volume growth and transmission costs paid to PJM. See further discussion of purchased power and fuel expense by segment below.
Impairment of the Long-Lived Assets of Boston Generating. Generation recorded a $945 million charge (before income taxes) during 2003 to impair the long-lived assets of Boston Generating.
Operating and Maintenance Expense. Operating and maintenance expense decreased primarily as a result of decreased expenses at Enterprises due to the sale of the majority of its businesses since the third quarter of 2003 and decreased severance and severance-related expenses, partially offset by increased expenses at Generation due to the acquisition of the remaining 50% of AmerGen and the consolidation of Sithe. Operating and maintenance expense increased $65 million due to investments in synthetic fuel-producing facilities made in the fourth quarter of 2003 and the third quarter of 2004. See further discussion of operating and maintenance expenses by segment below.
Depreciation and Amortization Expense. The increase in depreciation and amortization expense was primarily due to additional plant placed in service at Energy Delivery and Generation, the acquisition of the remaining 50% in AmerGen in December 2003, the consolidation of Sithe and the recording and subsequent impairment of an asset retirement cost (ARC) at Generation in 2004. See Note 14 of Exelon’s Notes to Consolidated Financial Statements for additional information. The increase also resulted from increased amortization expense due to investments made in the fourth quarter of 2003 and the third quarter of 2004 in synthetic fuel-producing facilities and increased competitive transition charge amortization at PECO. These increases were partially offset by reduced depreciation and amortization expense at Enterprises due to the sale of a majority of its businesses since the third quarter of 2003.
Operating Income. Exclusive of the changes in operating revenues, purchased power and fuel expense, the impairment of Boston Generating’s long-lived assets, operating and maintenance expense and depreciation and amortization expense discussed above, the change in operating income was primarily the result of increased taxes other than income in 2004 as compared to 2003, primarily due to the reduction of certain real estate tax accruals at PECO and Generation during 2003.
Other Income and Deductions. Other income and deductions reflects interest expense of $905 million, equity in losses of unconsolidated affiliates of $153 million, debt retirement charges of $130 million (before income taxes) recorded at ComEd in 2004 associated with an accelerated liability management plan, impairment charges of $255 million (before income taxes) recorded during 2003 related to Generation’s investment in Sithe, an $85 million gain (before income taxes) on the 2004 sale of Boston Generating and a $35 million aggregate net gain on the sale of investments and assets of Thermal in 2004 (before income taxes and net of debt prepayment penalties). Equity in earnings of unconsolidated affiliates decreased by $186 million due to the acquisition of the remaining 50% of AmerGen in December 2003, the deconsolidation of certain financing trusts during 2003 and investments in synthetic fuel-producing facilities made in the fourth quarter of 2003 and the third quarter of 2004.
Effective Income Tax Rate. The effective income tax rate was 27.5% for 2004 compared to 29.3% for 2003. The decrease in the effective rate was primarily attributable to investments in synthetic fuel-producing facilities made in the fourth quarter of 2003 and the third quarter of 2004.
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Results of Operations by Business Segment
The comparisons of 2004 and 2003 operating results and other statistical information set forth below include intercompany transactions, which are eliminated in Exelon’s consolidated financial statements.
Transfer of Exelon Energy Company from Enterprises to Generation. Effective January 1, 2004, Enterprises’ competitive retail sales business, Exelon Energy Company, was transferred to Generation. The 2003 information related to the Enterprises and Generation segments discussed below has been adjusted to reflect the transfer of Exelon Energy Company from the Enterprises segment to the Generation segment. Exelon Energy Company’s 2003 results were as follows:
| Total revenues |
$ | 834 | ||
| Intersegment revenues |
4 | |||
| Operating revenue and purchased power from affiliates |
209 | |||
| Depreciation and amortization |
2 | |||
| Operating expenses |
857 | |||
| Interest expense |
1 | |||
| Loss before income taxes |
(29 | ) | ||
| Income taxes |
(11 | ) | ||
| Net loss |
(18 | ) |
Income (Loss) Before Cumulative Effect of Changes in Accounting Principles by Business Segment
| 2004 |
2003 |
Favorable (unfavorable) variance |
||||||||||
| Energy Delivery |
$ | 1,128 | $ | 1,170 | $ | (42 | ) | |||||
| Generation |
641 | (259 | ) | 900 | ||||||||
| Enterprises |
(13 | ) | (117 | ) | 104 | |||||||
| Corporate |
85 | (1 | ) | 86 | ||||||||
| Total |
$ | 1,841 | $ | 793 | $ | 1,048 | ||||||
Net Income (Loss) by Business Segment
| 2004 |
2003 |
Favorable (unfavorable) variance |
||||||||||
| Energy Delivery |
$ | 1,128 | $ | 1,175 | $ | (47 | ) | |||||
| Generation |
673 | (151 | ) | 824 | ||||||||
| Enterprises |
(22 | ) | (118 | ) | 96 | |||||||
| Corporate |
85 | (1 | ) | 86 | ||||||||
| Total |
$ | 1,864 | $ | 905 | $ | 959 | ||||||
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Results of Operations—Energy Delivery
| 2004 |
2003 |
Favorable (Unfavorable) variance |
||||||||||
| OPERATING REVENUES |
$ | 10,290 | $ | 10,202 | $ | 88 | ||||||
| OPERATING EXPENSES |
||||||||||||
| Purchased power and fuel expense |
4,760 | 4,597 | (163 | ) | ||||||||
| Operating and maintenance |
1,444 | 1,669 | 225 | |||||||||
| Depreciation and amortization |
928 | 873 | (55 | ) | ||||||||
| Taxes other than income |
527 | 440 | (87 | ) | ||||||||
| Total operating expense |
7,659 | 7,579 | (80 | ) | ||||||||
| OPERATING INCOME |
2,631 | 2,623 | 8 | |||||||||
| OTHER INCOME AND DEDUCTIONS |
||||||||||||
| Interest expense |
(672 | ) | (747 | ) | 75 | |||||||
| Distributions on mandatorily redeemable preferred securities |
(3 | ) | (39 | ) | 36 | |||||||
| Equity in losses of unconsolidated affiliates |
(44 | ) | — | (44 | ) | |||||||
| Other, net |
(78 | ) | 51 | (129 | ) | |||||||
| Total other income and deductions |
(797 | ) | (735 | ) | (62 | ) | ||||||
| INCOME BEFORE INCOME TAXES AND CUMULATIVE EFFECT OF A CHANGE IN ACCOUNTING PRINCIPLE |
1,834 | 1,888 | (54 | ) | ||||||||
| INCOME TAXES |
706 | 718 | 12 | |||||||||
| INCOME BEFORE INCOME TAXES AND CUMULATIVE EFFECT OF A CHANGE IN ACCOUNTING PRINCIPLE |
1,128 | 1,170 | (42 | ) | ||||||||
| CUMULATIVE EFFECT OF A CHANGE IN ACCOUNTING PRINCIPLE |
— | 5 | (5 | ) | ||||||||
| NET INCOME |
$ | 1,128 | $ | 1,175 | $ | (47 | ) | |||||
Net Income. Energy Delivery’s net income in 2004 decreased primarily due to costs associated with ComEd’s accelerated retirement of long-term debt, reflected in other income and deductions—other, net, offset in part by lower interest expense. Operating income, while reflecting various changes in operating revenues and expenses, was relatively unchanged between periods.
Operating Revenues. The changes in Energy Delivery’s operating revenues for 2004 compared to 2003 consisted of the following:
| Electric |
Gas |
Total increase (decrease) |
||||||||||
| Volume |
$ | 326 | $ | 3 | $ | 329 | ||||||
| PJM transmission |
149 | — | 149 | |||||||||
| Rate changes and mix |
(74 | ) | 111 | 37 | ||||||||
| Weather |
(176 | ) | (21 | ) | (197 | ) | ||||||
| Customer Choice |
(182 | ) | — | (182 | ) | |||||||
| T&O Charges |
(41 | ) | — | (41 | ) | |||||||
| Other |
(17 | ) | 10 | (7 | ) | |||||||
| (Decrease) increase in operating revenues |
$ | (15 | ) | $ | 103 | $ | 88 | |||||
Volume. Both ComEd’s and PECO’s electric revenues increased as a result of higher delivery volume, exclusive of the effects of weather and customer choice, due to an increased number of customers and increased usage per customer, generally across all customer classes.
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PJM Transmission. Energy Delivery’s transmission revenues and purchased power expense each increased by $164 million due to ComEd’s May 1, 2004 entry into PJM, partially offset by $15 million of lower transmission revenues and expenses at PECO.
Rate Changes and Mix. Starting in ComEd’s June 2003 billing cycle, the increased wholesale market price of electricity and other adjustments to the energy component decreased the collection of CTCs as compared to the respective prior year period. ComEd’s CTC revenues decreased by $135 million in 2004 as compared to 2003. This decrease was partially offset by increased wholesale market prices which increased energy revenue received under the ComEd PPO and by increased average rates paid by small and large commercial and industrial customers totaling $53 million. For 2004 and 2003, ComEd collected approximately $169 million and $304 million, respectively, of CTC revenue. As a result of increasing mitigation factors, changes in energy prices and the ability of certain customers to establish fixed, multi-year CTC rates beginning in 2003, ComEd anticipates that this revenue source will range from $90 million to $110 million annually in 2005 and 2006. Under the current restructuring statute, no CTCs will be collected after 2006.
Electric revenues increased $1 million at PECO as a result of a $20 million increase related to a scheduled phase-out of merger-related rate reductions, offset by a $19 million decrease reflecting a change in rate mix due to changes in monthly usage patterns in all customer classes during 2004 as compared to 2003.
Energy Delivery’s gas revenues increased due to increases in rates through PUC-approved changes to the purchased gas adjustment clause that became effective March 1, 2003, June 1, 2003, December 1, 2003 and March 1, 2004. The average purchased gas cost rate per million cubic feet for 2004 was 33% higher than the rate in 2003. PECO’s purchased gas cost rates were reduced effective December 1, 2004.
Weather. Energy Delivery’s electric and gas revenues were negatively affected by unfavorable weather conditions. Cooling degree-days in the ComEd and PECO service territories were 12% lower and relatively unchanged, respectively, in 2004 as compared to 2003. Heating degree-days were 6% and 5% lower in both the ComEd and PECO service territories, respectively, in 2004 as compared to 2003.
Customer Choice. For 2004 and 2003, 28% and 25%, respectively, of energy delivered to Energy Delivery’s retail customers was provided by an alternative electric supplier or under the ComEd PPO. The decrease in electric retail revenues attributable to customer choice included a decrease in revenues of $104 million from customers in Illinois electing to purchase energy from an alternative electric supplier or under the ComEd PPO and a decrease in revenues of $78 million from customers in Pennsylvania being assigned to or selecting an alternative electric supplier.
T&O Charges. Prior to FERC orders issued in November 2004, ComEd collected through and out (T&O) charges for energy flowing across ComEd’s transmission system. Charges collected as the transmission owner were recorded in operating revenues. In addition after ComEd joined PJM on May 1, 2004, PJM allocated T&O collections to ComEd as a load serving entity. The collections received as a load serving entity were recorded as a decrease to purchased power expense. See Note 5 of Exelon’s Notes to Consolidated Financial Statements for more information on T&O charges.
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Purchased Power and Fuel Expense. The changes in Energy Delivery’s purchased power and fuel expense for 2004 compared to 2003 consisted of the following:
| Electric |
Gas |
Total increase (decrease) |
||||||||||
| Volume |
$ | 163 | $ | (2 | ) | $ | 161 | |||||
| PJM transmission |
149 | — | 149 | |||||||||
| Prices |
11 | 111 | 122 | |||||||||
| PJM administrative fees |
15 | — | 15 | |||||||||
| Customer choice |
(165 | ) | — | (165 | ) | |||||||
| Weather |
(84 | ) | (15 | ) | (99 | ) | ||||||
| T&O Charges |
(22 | ) | — | (22 | ) | |||||||
| Other |
(13 | ) | 15 | 2 | ||||||||
| Increase in purchased power and fuel expense |
$ | 54 | $ | 109 | $ | 163 | ||||||
Volume. ComEd’s and PECO’s purchased power and fuel expense increased due to increases, exclusive of the effects of weather and customer choice, in the number of customers and average usage per customer, generally across all customer classes.
PJM Transmission. Energy Delivery’s transmission revenues and purchased power expense each increased by $164 million in 2004 relative to 2003 due to ComEd’s May 1, 2004 entry into PJM, partially offset by $15 million of lower transmission revenues and expenses at PECO. See “Operating Revenues” above.
PJM Administrative Fees. ComEd fully integrated into PJM on May 1, 2004.
Prices. Energy Delivery’s purchased power expense increased due to a change in the mix of average pricing related to ComEd’s and PECO’s PPAs with Generation. Fuel expense for gas increased due to higher gas prices. See “Operating Revenues” above.
Customer Choice. An increase in customer switching resulted in a reduction of purchased power expense, primarily due to ComEd’s non-residential customers electing to purchase energy from an alternative electric supplier and PECO’s residential customers selecting or being assigned to purchase energy from an alternative electric supplier.
Weather. Energy Delivery’s purchased power and fuel expense decreased due to unfavorable weather conditions.
T&O Charges. Prior to FERC orders issued in November 2004, ComEd collected through and out (T&O) charges for energy flowing across ComEd’s transmission system. Charges collected as the transmission owner were recorded in operating revenues. In addition after ComEd joined PJM on May 1, 2004, PJM allocated T&O collections to ComEd as a load serving entity. The collections received as a load serving entity were recorded as a decrease to purchased power expense. See Note 5 of Exelon’s Notes to Consolidated Financial Statements for more information on T&O charges.
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Operating and Maintenance Expense. The changes in operating and maintenance expense for 2004 compared to 2003 consisted of the following:
| Increase (decrease) |
||||
| Severance and severance-related expenses |
$ | (132 | ) | |
| Charge recorded at ComEd in 2003 (a) |
(41 | ) | ||
| Payroll expense (b) |
(36 | ) | ||
| Incremental storm costs |
(21 | ) | ||
| Contractors |
(18 | ) | ||
| Automated meter reading system implementation costs at PECO in 2003 |
(16 | ) | ||
| Allowance for uncollectible accounts expense |
(13 | ) | ||
| FERC annual fees (c) |
(11 | ) | ||
| Environmental charges |
(10 | ) | ||
| Corporate allocations (d) |
77 | |||
| Other |
(4 | ) | ||
| Decrease in operating and maintenance expense |
$ | (225 | ) | |
| (a) | In 2003, ComEd reached an agreement with various Illinois retail market participants and other interested parties. |
| (b) | Energy Delivery had fewer employees in 2004 compared to 2003. |
| (c) | After joining PJM on May 1, 2004, ComEd is no longer directly charged annual fees by the FERC. PJM pays the annual FERC fees. |
| (d) | Higher corporate allocations primarily result from centralization of information technology, supply, human resources, communications, and finance functions into BSC from all of the Exelon operating companies, and changes in the corporate governance allocation calculation. Corporate governance allocations increased overall as a result of higher centralized costs distributed out of BSC, the sale of the Enterprises companies resulting in Energy Delivery comprising a greater base percentage of Exelon, and an SEC-mandated change to the methodology used to allocate Exelon’s corporate governance costs. |
Depreciation and Amortization Expense. The increase in depreciation and amortization expense was primarily due to increased competitive transition charge amortization of $31 million at PECO and increased depreciation of $22 million due to capital additions across Energy Delivery. In January 2005, PECO’s Board of Directors approved the implementation of a new customer information and billing system as part of a broader Energy Delivery systems strategy. The approval of this new system will result in the accelerated depreciation of PECO’s current system, which is expected to result in additional annual depreciation expense in 2005 and 2006 of $15 million and $8 million, respectively, relative to 2004 levels. If additional system changes are approved, additional accelerated depreciation may be required.
Taxes Other Than Income. The increase in taxes other than income reflects increases at PECO and ComEd of $63 million and $24 million, respectively. The increase at PECO was primarily attributable to a $58 million reduction of real estate tax accruals during 2003 and $12 million related to the reversal of a use tax accrual in 2003 resulting from an audit settlement, partially offset by $4 million of lower payroll taxes in 2004. The increase at ComEd was primarily attributable to a $25 million credit in 2003 for use tax payments for periods prior to the PECO / Unicom Merger and a refund of $5 million for Illinois Electricity Distribution taxes in 2003 partially offset by a refund of $8 million for Illinois Electricity Distribution taxes in 2004.
Interest Expense. The reduction in interest expense was primarily due to scheduled principal payments, debt retirements and prepayments, and refinancings at lower rates.
Distributions on Preferred Securities of Subsidiaries. Effective July 1, 2003, upon the adoption of FIN 46 and effective December 31, 2003, upon the adoption of FIN 46-R, ComEd and
65
PECO deconsolidated their financing trusts (see Note 1 of Exelon’s Notes to Consolidated Financial Statements). ComEd and PECO no longer record distributions on mandatorily redeemable preferred securities, but record interest expense to affiliates related to their obligations to the financing trusts.
Equity in Losses of Unconsolidated Affiliates. During 2004, ComEd and PECO recorded $19 million and $25 million, respectively, of equity in net losses of subsidiaries as a result of ComEd and PECO deconsolidating their financing trusts.
Other, net. The change in other, net is primarily due to Exelon’s initiation in 2004 of an accelerated liability management plan at ComEd that resulted in the retirement of approximately $1.2 billion of long-term debt, including $1.0 billion prior to its maturity and $206 million at maturity. ComEd recorded charges of $130 million associated with the retirement of debt under the plan. The components of these charges included the following: $86 million related to prepayment premiums; $12 million related to net unamortized premiums, discounts and debt issuance costs; $24 million of losses on reacquired debt previously deferred as regulatory assets; and $12 million related to settled cash-flow interest-rate swaps previously deferred as regulatory assets partially offset by $4 million of unamortized gain on settled fair value interest-rate swaps.
Energy Delivery Operating Statistics and Revenue Detail
Energy Delivery’s electric sales statistics and revenue detail were as follows:
| Retail Deliveries – (in GWhs) (a) |
2004 |
2003 |
Variance |
% Change | |||||
| Full service (b) |
|||||||||
| Residential |
36,812 | 37,564 | (752 | ) | (2.0%) | ||||
| Small commercial & industrial |
26,914 | 28,165 | (1,251 | ) | (4.4%) | ||||
| Large commercial & industrial |
20,969 | 20,660 | 309 | 1.5% | |||||
| Public authorities & electric railroads |
5,135 | 6,022 | (887 | ) | (14.7%) | ||||
| Total full service |
89,830 | 92,411 | (2,581 | ) | (2.8%) | ||||
| Delivery only (c) |
|||||||||
| Residential |
2,158 | 900 | 1,258 | 139.8% | |||||
| Small commercial & industrial |
8,794 | 7,461 | 1,333 | 17.9% | |||||
| Large commercial & industrial |
13,182 | 10,689 | 2,493 | 23.3% | |||||
| Public authorities & electric railroads |
1,410 | 1,402 | 8 | 0.6% | |||||
| 25,544 | 20,452 | 5,092 | 24.9% | ||||||
| PPO (ComEd only) |
|||||||||
| Small commercial & industrial |
3,594 | 3,318 | 276 | 8.3% | |||||
| Large commercial & industrial |
4,223 | 4,348 | (125 | ) | (2.9%) | ||||
| Public authorities & electric railroads |
1,670 | 1,925 | (255 | ) | (13.2%) | ||||
| 9,487 | 9,591 | (104 | ) | (1.1%) | |||||
| Total delivery only and PPO |
35,031 | 30,043 | 4,988 | 16.6% | |||||
| Total retail deliveries |
124,861 | 122,454 | 2,407 | 2.0% | |||||
| (a) | One gigawatthour is the equivalent of one million kilowatthours (kWh). |
| (b) | Full service reflects deliveries to customers taking electric service under tariffed rates. |
| (c) | Delivery only service reflects customers electing to receive electric generation service from an alternative electric supplier, which rates include a distribution charge and a CTC. |
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| Electric Revenue |
2004 |
2003 |
Variance |
% Change | |||||||
| Full service (a) |
|||||||||||
| Residential |
$ | 3,612 | $ | 3,715 | $ | (103) | (2.8%) | ||||
| Small commercial & industrial |
2,360 | 2,421 | (61) | (2.5%) | |||||||
| Large commercial & industrial |
1,403 | 1,394 | 9 | 0.6% | |||||||
| Public authorities & electric railroads |
341 | 396 | (55) | (13.9%) | |||||||
| Total full service |
7,716 | 7,926 | (210) | (2.6%) | |||||||
| Delivery only (b) |
|||||||||||
| Residential |
164 | 65 | 99 | 152.3% | |||||||
| Small commercial & industrial |
220 | 214 | 6 | 2.8% | |||||||
| Large commercial & industrial |
190 | 196 | (6) | (3.1%) | |||||||
| Public authorities & electric railroads |
28 | 33 | (5) | (15.2%) | |||||||
| 602 | 508 | 94 | 18.5% | ||||||||
| PPO (ComEd only) (c) |
|||||||||||
| Small commercial & industrial |
246 | 225 | 21 | 9.3% | |||||||
| Large commercial & industrial |
240 | 240 | — | — | |||||||
| Public authorities & electric railroads |
92 | 103 | (11) | (10.7%) | |||||||
| 578 | 568 | 10 | 1.8% | ||||||||
| Total delivery only and PPO |
1,180 | 1,076 | 104 | 9.7% | |||||||
| Total electric retail revenues |
8,896 | 9,002 | (106) | (1.2%) | |||||||
| Wholesale and miscellaneous revenue (d) |
646 | 555 | 91 | 16.4% | |||||||
| Total electric revenue |
$ | 9,542 | $ | 9,557 | $ | (15) | (0.2%) | ||||
| (a) | Full service revenue reflects deliveries to customers taking electric service under tariffed rates, which include the cost of energy and the delivery cost of the transmission and the distribution of the energy. PECO’s tariffed rates also include a CTC. See Note 5 of Exelon’s Notes to Consolidated Financial Statements for a discussion of CTC. |
| (b) | Delivery only revenue reflects revenue under tariffed rates from customers electing to receive electric generation service from an alternative electric supplier, which rates include a distribution charge and a CTC. Prior to ComEd’s full integration into PJM on May 1, 2004, ComEd’s transmission charges received from alternative electric suppliers are included in wholesale and miscellaneous revenue. |
| (c) | Revenues from customers choosing ComEd’s PPO include an energy charge at market rates, transmission and distribution charges, and a CTC. |
| (d) | Wholesale and miscellaneous revenues include transmission revenue (including revenue from PJM), sales to municipalities and other wholesale energy sales. |
Energy Delivery’s gas sales statistics and revenue detail were as follows:
| Deliveries to customers in million cubic feet (mmcf) |
2004 |
2003 |
Variance |
% Change | |||||||
| Retail sales |
59,949 | 61,858 | (1,909) | (3.1%) | |||||||
| Transportation |
27,148 | 26,404 | 744 | 2.8% | |||||||
| Total |
87,097 | 88,262 | (1,165) | (1.3%) | |||||||
| Revenue |
2004 |
2003 |
Variance |
% Change | |||||||
| Retail sales |
$ | 702 | $ | 609 | $ | 93 | 15.3% | ||||
| Transportation |
18 | 18 | — | — | |||||||
| Resales and other |
28 | 18 | 10 | 55.6% | |||||||
| Total |
$ | 748 | $ | 645 | $ | 103 | 16.0% | ||||
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Results of Operations—Generation
As previously described, effective January 1, 2004, Exelon contributed its interest in Exelon Energy Company to Generation. Exelon Energy Company was previously reported as a part of the Enterprises segment. For comparative discussion and analysis, Exelon Energy Company’s results of operations have been included within Generation’s results of operations as if this transfer had occurred on January 1, 2003.
| 2004 |
2003 |
Favorable (Unfavorable) |
||||||||||
| OPERATING REVENUES |
$ | 7,938 | $ | 8,760 | $ | (822 | ) | |||||
| OPERATING EXPENSES |
||||||||||||
| Purchased power |
2,325 | 3,630 | 1,305 | |||||||||
| Fuel |
1,845 | 2,115 | 270 | |||||||||
| Operating and maintenance |
2,273 | 1,886 | (387 | ) | ||||||||
| Impairment of Boston Generating, LLC long-lived assets |
— | 945 | 945 | |||||||||
| Depreciation and amortization |
294 | 201 | (93 | ) | ||||||||
| Taxes other than income |
171 | 121 | (50 | ) | ||||||||
| Total operating expense |
6,908 | 8,898 | 1,990 | |||||||||
| OPERATING INCOME (LOSS) |
1,030 | (138 | ) | 1,168 | ||||||||
| OTHER INCOME AND DEDUCTIONS |
||||||||||||
| Interest expense |
(167 | ) | (89 | ) | (78 | ) | ||||||
| Equity in earnings (losses) of unconsolidated affiliates |
(14 | ) | 49 | (63 | ) | |||||||
| Other, net |
143 | (267 | ) | 410 | ||||||||
| Total other income and deductions |
(38 | ) | (307 | ) | 269 | |||||||
| INCOME (LOSS) BEFORE INCOME TAXES, MINORITY INTEREST, AND CUMULATIVE EFFECT OF CHANGES IN ACCOUNTING PRINCIPLES |
992 | (445 | ) | 1,437 | ||||||||
| INCOME TAXES |
372 | (190 | ) | (562 | ) | |||||||
| INCOME BEFORE MINORITY INTEREST AND CUMULATIVE EFFECT OF CHANGES IN ACCOUNTING PRINCIPLES |
620 | (255 | ) | 875 | ||||||||
| MINORITY INTEREST |
21 | (4 | ) | 25 | ||||||||
| INCOME (LOSS) BEFORE CUMULATIVE EFFECT OF CHANGES IN ACCOUNTING PRINCIPLES |
641 | (259 | ) | 900 | ||||||||
| CUMULATIVE EFFECT OF CHANGES IN ACCOUNTING PRINCIPLES (net of income taxes) |
32 | 108 | (76 | ) | ||||||||
| NET INCOME (LOSS) |
$ | 673 | $ | (151 | ) | $ | 824 | |||||
Net Income (Loss). Generation’s net income in 2004 increased from 2003 due to a number of factors. The increase in Generation’s 2004 net income was driven primarily by charges incurred in 2003 for the impairment of the long-lived assets of Boston Generating of $945 million (before income taxes) and the impairment and other transaction-related charges of $280 million (before income taxes) related to Generation’s investment in Sithe. Also, 2004 results were favorably affected by the acquisition of the remaining 50% of AmerGen and an increase in revenue, net of purchased power and fuel expense, primarily due to the decrease in average realized costs resulting from the increased success in the hedging program of fuel costs in 2004.
Cumulative effect of changes in accounting principles recorded in 2004 included a benefit of $32 million, net of income taxes, related to the adoption of FIN 46-R and in 2003 included income of
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$108 million, net of income taxes related to the of adoption of SFAS No. 143. See Note 1 of Exelon’s Notes to Consolidated Financial Statements for further discussion of these effects.
Operating Revenues. Operating revenues decreased in 2004 as compared to 2003, primarily as a result of the adoption of EITF 03-11. The adoption of EITF 03-11 resulted in a decrease in revenues of $980 million in 2004 as compared with the prior year. Generation’s sales in 2004 and 2003 were as follows:
| Revenue (in millions) |
2004 |
2003 |
Variance |
% Change | ||||||||
| Electric sales to affiliates |
$ | 3,749 | $ | 3,831 | $ | (82 | ) | (2.1%) | ||||
| Wholesale and retail electric sales |
3,227 | 4,107 | (880 | ) | (21.4%) | |||||||
| Total energy sales revenue |
6,976 | 7,938 | (962 | ) | (12.1%) | |||||||
| Retail gas sales |
456 | 588 | (132 | ) | (22.4%) | |||||||
| Trading portfolio |
— | 1 | (1 | ) | (100.0%) | |||||||
| Other revenue (a) |
506 | 233 | 273 | 117.2% | ||||||||
| Total revenue |
$ | 7,938 | $ | 8,760 | $ | (822 | ) | (9.4%) | ||||
| Sales (in GWhs) |
2004 |
2003 |
Variance |
% Change | ||||||||
| Electric sales to affiliates |
110,465 | 112,688 | (2,223 | ) | (2.0%) | |||||||
| Wholesale and retail electric sales |
92,134 | 112,816 | (20,682 | ) | (18.3%) | |||||||
| Total sales |
202,599 | 225,504 | (22,905 | ) | (10.2%) | |||||||
| (a) | Includes sales related to tolling agreements, including Sithe in 2004, and fossil fuel sales. |
Trading volumes of 24,001 GWhs and 32,584 GWhs for the years ended December 31, 2004 and 2003, respectively, are not included in the table above. The decrease in trading volume is a result of reduced volumetric and VAR trading limits in 2004, which are set by the Exelon Risk Management Committee and approved by the Board of Directors.
Electric Sales to Affiliates. Sales to Energy Delivery declined $82 million in 2004 as compared to the prior year. The lower sales to Energy Delivery were primarily driven by cooler than normal summer weather and lower average transfer prices in 2004 compared to the prior year.
Wholesale and Retail Electric Sales. The changes in Generation’s wholesale and retail electric sales for the year ended December 31, 2004 compared to the same period in 2003, consisted of the following:
| Generation |
Increase (decrease) |
|||
| Effects of EITF 03-11 adoption (a) |
$(966 | ) | ||
| Sale of Boston Generating |
(370 | ) | ||
| Addition of AmerGen operations |
189 | |||
| Other operations |
267 | |||
| Decrease in wholesale and retail electric sales |
$ | (880 | ) | |
| (a) | Does not include $14 million of EITF 03-11 reclassifications related to fuel sales that are included in other revenues. |
The adoption of EITF 03-11 on January 1, 2004 resulted in the netting of certain revenues and the associated purchase power and fuel expense in 2004. The sale of Boston Generating in May 2004
69
resulted in less revenues from this entity in 2004 compared to the prior year. The acquisition of AmerGen resulted in increased market and retail electric sales of approximately $189 million in 2004.
The remaining increase in wholesale and retail electric sales was primarily due to higher volumes sold to the market at overall higher prices. The increase in market prices in the Midwest region was primarily driven by higher coal prices throughout the year, and in the Mid-Atlantic region market prices were driven by higher oil and gas prices.
Retail Gas Sales. Retail gas sales decreased $132 million as a result of the wind-down of Exelon Energy’s northeast business.
Other revenue. Other revenues in 2004 include $235 million of revenue related to the results of Sithe Energies, Inc. The remaining increase in other revenue includes sales from tolling agreement, fossil fuel and decommissioning revenue.
Purchased Power and Fuel Expense. Generation’s supply of sales in 2004 and 2003, excluding the trading portfolio, was as follows:
| Supply of Sales (in GWhs) |
2004 |
2003 |
% Change |
||||
| Nuclear generation (a) |
136,621 | 117,502 | 16.3 | % | |||
| Purchases—non-trading portfolio (b) |
48,968 | 83,692 | (41.5 | %) | |||
| Fossil and hydroelectric generation (c, d) |
17,010 | 24,310 | (30.0 | %) | |||
| Total supply |
202,599 | 225,504 | (10.2 | %) | |||
| (a) | Excludes AmerGen for 2003. AmerGen generated 20,135 GWhs during the year ended December 31, 2004. |
| (b) | Sales in 2004 do not include 25,464 GWhs that were netted with purchased power GWhs as a result of the reclassification of certain hedging activities in accordance with EITF 03-11. Includes PPAs with AmerGen, which represented 12,667 GWhs in 2003. |
| (c) | Fossil and hydroelectric supply mix changed as a result of decreased fossil fuel generation due to the sale of Boston Generating in May 2004. |
| (d) | Excludes Sithe and Generation’s investment in TEG and TEP. |
The changes in Generation’s purchased power and fuel expense for the year ended December 31, 2004 compared to the same period in 2003, consisted of the following:
| Generation |
Increase (decrease) |
|||
| Effects of the adoption of EITF 03-11 |
$ | (980 | ) | |
| Addition of AmerGen operations |
(344 | ) | ||
| Sale of Boston Generating |
(290 | ) | ||
| Midwest Generation |
(122 | ) | ||
| Price |
(13 | ) | ||
| Mark-to-market adjustments on hedging activity |
(14 | ) | ||
| Volume |
267 | |||
| Sithe Energies, Inc. |
165 | |||
| Other |
(244 | ) | ||
| Decrease in purchased power and fuel expense |
$ | (1,575 | ) | |
Adoption of EITF 03-11. The adoption of EITF 03-11 resulted in a decrease in purchased power and fuel expense of $980 million.
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Addition of AmerGen Operations. As a result of Generation’s acquisition of the remaining 50% interest in AmerGen in December 2003, purchased power decreased $379 million. In prior periods, Generation reported energy purchased from AmerGen as purchased power expense. The decrease in purchase power was offset by an increase of $35 million related to AmerGen’s nuclear fuel expense.
Sale of Boston Generating. The decrease in fuel and purchased power expense for Boston Generating is due primarily to the sale of the business in May 2004.
Midwest Generation. The volume of purchased power acquired from Midwest Generation declined in 2004 as a result of Generation exercising its option to reduce the capacity purchased from Midwest Generation, as announced in 2003.
Price. The decrease reflects the forward hedging of fuel at lower costs than 2003 realized costs.
Hedging Activity. Mark-to-market losses on hedging activities at Generation were $2 million for the year ended December 31, 2004 compared to losses of $16 million for 2003. Hedging activities in 2004 relating to Boston Generating operations accounted for a gain of $4 million and hedging activities relating to other Generation operations in 2004 accounted for losses of $6 million.
Volume. Generation experienced increases in purchased power and fuel expense due to increased market and retail electric sales throughout its various sales regions.
Sithe Energies, Inc. Under the provisions of FIN 46-R, the operating results of Sithe were included in Generation’s results of operations beginning April 1, 2004. See Note 3 of Exelon’s Notes to Consolidated Financial Statements for further discussion of Sithe.
Other. Other decreases in purchased power and fuel expense were primarily due to $157 million of lower fuel expense due to the wind-down of Exelon Energy’s northeast business and $97 million of lower transmission expense resulting from reduced inter-region transmission charges, primarily associated with ComEd’s integration into PJM.
Generation’s average margins per megawatt hour (MWh) sold for the years ended December 31, 2004 and 2003 were as follows:
| ($/MWh) |
2004 |
2003 |
% Change | |||||
| Average revenue |
||||||||
| Electric sales to affiliates |
$ | 33.94 | $ | 34.00 | (0.2%) | |||
| Wholesale and retail electric sales |
35.03 | 36.40 | (3.8%) | |||||
| Total—excluding the trading portfolio |
34.43 | 35.20 | (2.2%) | |||||
| Average supply cost—excluding the trading portfolio (a) |
20.59 | 25.48 | (19.2%) | |||||
| Average margin—excluding the trading portfolio |
13.84 | 9.72 | 42.4% | |||||
| (a) | Average supply cost includes purchased power, fuel costs and PPAs with AmerGen in 2003. |
Impairment of the Long-Lived Assets of Boston Generating. In connection with the decision to transition out of the ownership of Boston Generating during the third quarter of 2003, Generation recorded a long-lived asset impairment charge of $945 million ($573 million net of income taxes). See Note 2 of Exelon’s Notes to Consolidated Financial Statements for further discussion of the sale of Generation’s ownership interest in Boston Generating.
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Operating and Maintenance Expense. The changes in operating and maintenance expense for 2004 compared to 2003 consisted of the following:
| Generation |
Increase (decrease) |
|||
| Addition of AmerGen operations |
$ | 331 | ||
| Sithe Energies, Inc. |
71 | |||
| Decommissioning related costs (a) |
50 | |||
| Refueling outage costs (b) |
50 | |||
| Pension, payroll and benefit costs, primarily associated with The Exelon Way |
(84 | ) | ||
| DOE Settlement (c) |
(52 | ) | ||
| Sale of Boston Generating |
(12 | ) | ||
| Other |
33 | |||
| Increase in operating and maintenance expense |
$ | 387 | ||
| (a) | Includes $40 million due to AmerGen asset retirement obligation accretion. |
| (b) | Includes refueling outage cost of $43 million at AmerGen. |
| (c) | See Note 14 of Exelon’s Notes to Consolidated Financial Statements for further discussion of the spent nuclear fuel storage settlement agreement with the DOE. |
The increase in operating and maintenance expense is primarily due to the inclusion of AmerGen and Sithe Energies, Inc. in Generation’s consolidated results for 2004. Decommissioning related costs increased primarily due to the inclusion of AmerGen in 2004 compared to the prior year. Accretion expense includes accretion of the asset retirement obligation and adjustments to offset the earnings impacts of certain decommissioning related activities revenues earned from ComEd and PECO, income taxes, and depreciation of the ARC asset to zero. The increase in operating and maintenance expense was partially offset by a reductions in payroll-related costs due to the implementation of the programs associated with The Exelon Way, the sale of Boston Generating in May 2004 and the settlement with the DOE to reimburse Generation for costs associated with storage of spent nuclear fuel.
Nuclear fleet operating data and purchased power costs data for the year ended December 31, 2004 and 2003 were as follows:
| Generation |
2004 |
2003 | ||||
| Nuclear fleet capacity factor (a) |
93.5% | 93.4% | ||||
| Nuclear fleet production cost per MWh (a) |
$ | 12.43 | $ | 12.53 | ||
| Average purchased power cost for wholesale operations per MWh (b) |
$ | 47.48 | $ | 43.17 | ||
| (a) | Includes AmerGen and excludes Salem, which is operated PSEG Nuclear. |
| (b) | Includes PPAs with AmerGen in 2003. |
The higher nuclear capacity factor and lower nuclear production costs are primarily due to ten fewer unplanned outages which offset the impact of one additional planned refuel outage. The lower production cost in 2004 as compared to 2003 is primarily due to the lower fuel costs and the impact of the spent fuel storage cost settlement agreement with the DOE which offset the added cost for one additional planned refuel outage and costs associated with the Dresden generator repairs during outages in the fourth quarter of 2004.
In 2004 as compared to 2003, the Quad Cities units intermittently operated at pre-Extended Power Uprate (EPU) generation levels due to performance issues with their steam dryers. Generation plans additional expenditures to ensure safe and reliable operations at the EPU output levels by mid-2005.
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Depreciation and Amortization. The increase in depreciation and amortization expense in 2004 as compared to 2003 was primarily due to the immediate expensing of an ARC, totaling $49 million, recorded in 2004 for which no useful life remains. The ARC was originally recorded in accordance with SFAS No. 143, which requires the establishment of an asset to offset the impact of an increased asset retirement obligation (ARO). See Note 14 of Exelon’s Notes to Consolidated Financial Statements for more information on the 2004 update to the ARO and ARC. The remaining increase is due to capital additions and the consolidation of Sithe and AmerGen. These increase were partially offset by a decrease in depreciation expense related to Boston Generating facilities, which were sold in May 2004.
Effective Income Tax Rate. The effective income tax rate was 37.5% for 2004 compared to 42.7% for 2003. The decrease in the effective rate was primarily attributable to income taxes associated with nuclear decommissioning trust activity, income tax deductions related to non-taxable employee benefits and the dilution of the permanent income tax benefits due to the increase in pre-tax income in 2004.
Results of Operations—Enterprises
As previously described, effective January 1, 2004, Enterprises contributed its interest in Exelon Energy Company to Generation. Exelon Energy Company was previously reported as a part of the Enterprises segment. For comparative discussion and analysis, the results of Exelon Energy Company have been excluded from Enterprises’ 2003 results of operations discussed below.
| 2004 |
2003 |
Favorable (unfavorable) variance |
||||||||||
| Operating revenues |
$ | 155 | $ | 923 | $ | (768 | ) | |||||
| Operating and maintenance expense |
211 | 1,027 | 816 | |||||||||
| Operating loss |
(62 | ) | (139 | ) | 77 | |||||||
| Loss before income taxes, minority interest and cumulative effect of changes in accounting principles |
(7 | ) | (187 | ) | 180 | |||||||
| Loss before cumulative effect of changes in accounting principles |
(13 | ) | (117 | ) | 104 | |||||||
| Net loss |
(22 | ) | (118 | ) | 96 | |||||||
Divestiture of Businesses and Investments. In 2004, Exelon continued to execute its divestiture strategy for Enterprises by selling or winding down substantially all components of Enterprises. Enterprises expects to receive aggregate proceeds of $268 million and recorded a net pre-tax gain on the disposition of assets and investments of $41 million in 2004.
Enterprises’ results for 2004 compared to 2003 were significantly affected by the following transactions:
InfraSource, Inc. On September 24, 2003, Enterprises sold the electric construction and services, underground and telecom businesses of InfraSource. Cash proceeds to Enterprises from the sale were approximately $175 million, net of transaction costs and cash transferred to the buyer upon sale, plus a $30 million subordinated note receivable maturing in 2011. At the time of closing, the present value of the note receivable was approximately $12 million. The note was collected in full during the second quarter of 2004, resulting in income of $18 million.
Exelon Services, Inc. During 2004, Enterprises disposed of or wound down all of the operating businesses of Exelon Services, Inc. (Exelon Services), including Exelon Solutions, all mechanical services businesses and the Integrated Technology Group. Total expected proceeds and the net gain
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on sale recorded during 2004 related to the disposition of these businesses were $61 million and $9 million, respectively. The gain was recorded in other income and deductions on Exelon’s Consolidated Statements of Income. As of December 31, 2004, Exelon Services had assets and liabilities of $74 million and $22 million, respectively, which primarily consist of tax assets, affiliate receivables and payables, and sales proceeds to be collected.
Exelon Thermal Holdings Inc. On June 30, 2004, Enterprises sold its Chicago business of Thermal for proceeds of $134 million, subject to working capital adjustments. Enterprises repaid $37 million of debt outstanding of the Chicago thermal operations prior to closing, which resulted in prepayment penalties of $9 million, recorded as interest expense. A pre-tax gain of $45 million was recorded in other income and deductions on Exelon’s Consolidated Statements of Income.
On September 29, 2004, Enterprises sold ETT Nevada, Inc., the holding company for its investment in Northwind Aladdin, LLC, for a net cash outflow of $1 million, subject to working capital adjustments. A pre-tax loss of $3 million was recorded in other income and deductions within Exelon’s Consolidated Statements of Income inclusive of the acquisition and sale of Northwind Aladdin’s third-party debt associated with the transaction.
On October 28, 2004, Northwind Windsor, of which Enterprises owns a 50% interest, sold substantially all of its assets, providing Enterprises with cash proceeds of $8 million. A pre-tax gain of $2 million was recorded in other income and deductions on Exelon’s Consolidated Statements of Income.
PECO Telcove. On June 30, 2004, Enterprises sold its investment in PECO TelCove, a communications joint venture, along with certain telecommunications assets, for proceeds of $49 million. A pre-tax gain of $9 million was recorded in other income and deductions on Exelon’s Consolidated Statements of Income.
At December 1, 2004, the remaining assets of Enterprises totaled approximately $274 million in comparison to $697 million at December 31, 2003.
Net Loss. The decrease in Enterprises’ net loss before cumulative effect of changes in accounting principles in 2004 was primarily due to a decrease in operating and maintenance expense, partially offset by a decrease in operating revenues. Depreciation and amortization expense decreased $23 million before income taxes from 2003 to 2004 primarily as a result of the sale of the majority of property, plant and equipment since September 2003. In 2004, Enterprises recorded impairment charges of investments of $15 million before income taxes due to other-than-temporary declines in value, partially offset by 2003 charges for impairment of investments of $46 million before income taxes and a net impairment of other assets of $8 million before income taxes. The adoption of EITF 03-16 increased the 2004 net loss by $9 million. The adoption of SFAS No. 143 increased the 2003 net loss by $1 million, net of income taxes. See Note 1 of Exelon’s Notes to Consolidated Financial Statements for further discussion of the adoption of EITF 03-16 and SFAS No. 142.
Operating Revenues. The changes in Enterprises’ operating revenues for 2004 compared to 2003 consisted of the following:
| Variance |
||||
| F & M Holdings, LLC / InfraSource businesses (a) |
$ | (493 | ) | |
| Exelon Services (a) |
(259 | ) | ||
| Exelon Thermal (a) |
(17 | ) | ||
| Other |
1 | |||
| Decrease in operating revenues |
$ | (768 | ) | |
| (a) | Operating revenues decreased as a result of the sale of certain businesses and wind-down efforts. |
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Operating and Maintenance Expense. The changes in Enterprises’ operating and maintenance expense for 2004 compared to 2003 consisted of the following:
| Variance |
||||
| F & M Holdings, LLC / InfraSource businesses (a) |
$ | (503 | ) | |
| Exelon Services (a) |
(276 | ) | ||
| Exelon Thermal (a) |
(10 | ) | ||
| Other |
(27 | ) | ||
| Decrease in operating and maintenance expense |
$ | (816 | ) | |
| (a) | Operating and maintenance expense decreased as a result of the sale of certain businesses and wind-down efforts. |
Effective Income Tax Rate. The effective income tax rate was (85.7%) for 2004 compared to 37.4% for 2003. This change in the effective tax rate was primarily attributable to the reversal of a large income tax receivable at F&M Holdings, LLC in the fourth quarter of 2004, the state tax impact on the gains on the sales of Exelon Thermal’s Chicago businesses and certain investments, and various other income tax adjustments primarily associated with the sale of Enterprise businesses.
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Results of Operations—Exelon Corporation
Year Ended December 31, 2003 Compared To Year Ended December 31, 2002
Significant Operating Trends—Exelon
| Exelon Corporation |
2003 |
2002 |
Favorable (unfavorable) variance |
|||||||||
| Operating revenues |
$ | 15,812 | $ | 14,955 | $ | 857 | ||||||
| Purchased power and fuel expense |
6,375 | 5,262 | (1,113 | ) | ||||||||
| Impairment of Boston Generating, LLC long-lived assets |
945 | — | (945 | ) | ||||||||
| Operating and maintenance expense |
4,508 | 4,345 | (163 | ) | ||||||||
| Operating income |
2,277 | 3,299 | (1,022 | ) | ||||||||
| Other income and deductions |
(1,148 | ) | (627 | ) | (521 | ) | ||||||
| Income before income taxes, minority interest and cumulative effect of changes in accounting principles |
1,129 | 2,672 | (1,543 | ) | ||||||||
| Income before cumulative effect of changes in accounting principles |
793 | 1,674 | (881 | ) | ||||||||
| Income taxes |
331 | 998 | 667 | |||||||||
| Net income |
905 | 1,440 | (535 | ) | ||||||||
| Diluted earnings per share |
1.38 | 2.22 | (0.84 | ) | ||||||||
Net Income. Net income for 2003 reflects income of $112 million, net of income taxes, for the adoption of SFAS No. 143, while net income for 2002 reflects a $230 million charge, net of income taxes, as a result of the adoption of SFAS No. 142. See Note 1 of Exelon’s Notes to Consolidated Financial Statements for further information regarding the adoptions of SFAS No. 143 and SFAS No. 142.
Operating Revenues. Operating revenues increased in 2003 primarily due to increased market sales at Generation due to generating assets acquired in 2002 and higher wholesale market prices in 2003. Total market sales at Generation, excluding the trading portfolio, increased from 88,985 GWhs in 2002 to 112,816 GWhs in 2003, and the average revenue per MWh on Generation’s market sales, excluding the trading portfolio, increased from $32.36 in 2002 to $35.20 in 2003. This increase in operating revenues was partially offset by a decrease in Energy Delivery’s revenues of $255 million primarily due to unfavorable weather impacts and an increase in customers selecting an alternative electric supplier or ComEd’s PPO. Enterprises also experienced a $413 million reduction in operating revenues from 2002 to 2003, primarily due to the sale of InfraSource during the third quarter of 2003. See further discussion of operating revenues by segment below.
Purchased Power and Fuel Expense. Purchased power and fuel expense increased in 2003 primarily due to generating assets acquired in 2002 and higher market prices for purchased power in 2003. The average cost per MWh supplied by Generation, excluding the trading portfolio, increased from $22.51 in 2002 to $25.48 in 2003 due to increased fossil generation and increased purchased power at higher market prices. Fossil and hydroelectric generation represented 11% of Generation’s total supply in 2003 compared to 6% in 2002. See further discussion of purchased power and fuel expense by segment below.
Impairment of the Long-Lived Assets of Boston Generating. Generation recorded a $945 million charge (before income taxes) during 2003 to impair the long-lived assets of Boston Generating.
Operating and Maintenance Expense. Operating and maintenance expense increased in 2003 primarily due to a change in the accounting methodology for nuclear decommissioning, severance and severance-related costs associated with The Exelon Way, and increased costs at Generation
76
associated with generating assets acquired in 2002. Partially offsetting these increases was an overall reduction in operating and maintenance expenses at Enterprises, primarily due to the sale of InfraSource during the third quarter of 2003. See further discussion of operating and maintenance expenses by segment below.
Operating Income. The decrease in operating income, exclusive of the changes in operating revenues, purchased power and fuel expense, Boston Generating long-lived asset impairment charge and operating and maintenance expense discussed above, was primarily due to a decrease of $214 million in depreciation and amortization expense primarily due to the adoption of SFAS No. 143 and lower depreciation and amortization expense in the Energy Delivery segment. In addition, taxes other than income also decreased by $128 million primarily due to a reduction in reserves for real estate taxes within the Energy Delivery and Generation segments.
Other Income and Deductions. Other income and deductions changed primarily due to impairment and other transaction-related charges of $280 million recorded in 2003 related to Generation’s investment in Sithe. Interest expense decreased 9% from $966 million in 2002 to $881 million in 2003 primarily due to less outstanding debt and refinancing of existing debt at lower interest rates at Energy Delivery partially offset by increased interest expense at Generation due to debt related to 2002 acquisitions and reduced capitalized interest in 2003. In 2002, Enterprises recorded a gain on the sale of its investment in AT&T Wireless of $198 million (before income taxes).
Effective Income Tax Rate. The effective income tax rate was 29.3% for 2003 compared to 37.4% for 2002. The decrease in the effective rate was primarily attributable to a decrease in state income taxes, net of Federal income tax benefit, and investments in synthetic fuel-producing facilities made in the fourth quarter of 2003.
Results of Operations by Business Segment
The comparisons of 2003 and 2002 operating results and other statistical information set forth below reflect intercompany transactions, which are eliminated in the consolidated financial statements.
Transfer of Exelon Energy Company from Enterprises to Generation. Effective January 1, 2004, Enterprises’ competitive retail sales business, Exelon Energy Company, became part of Generation. The information for 2003 and 2002 related to the Generation and Enterprises segments discussed below has been adjusted to reflect the transfer of Exelon Energy Company from the Enterprises segment to the Generation segment. Exelon Energy Company’s 2003 and 2002 results were as follows:
| 2003 |
2002 |
|||||||
| Total revenues |
$ | 834 | $ | 697 | ||||
| Intersegment revenues |
4 | 8 | ||||||
| Operating revenue and purchased power from affiliates |
209 | 235 | ||||||
| Depreciation and amortization |
2 | 16 | ||||||
| Operating expenses |
857 | 700 | ||||||
| Interest expense |
1 | 4 | ||||||
| Cumulative effect of changes in accounting principles |
— | (11 | ) | |||||
| Loss before income taxes |
(29 | ) | (6 | ) | ||||
| Income taxes |
(11 | ) | 16 | |||||
| Net loss |
(18 | ) | (33 | ) | ||||
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Income (Loss) Before Cumulative Effect of Changes in Accounting Principles by Business Segment
| 2003 |
2002 |
Favorable (unfavorable) variance |
||||||||||
| Energy Delivery |
$ | 1,170 | $ | 1,268 | $ | (98 | ) | |||||
| Generation |
(259 | ) | 365 | (624 | ) | |||||||
| Enterprises |
(117 | ) | 87 | (204 | ) | |||||||
| Corporate |
(1 | ) | (50 | ) | 49 | |||||||
| Total |
$ | 793 | $ | 1,670 | $ | (877 | ) | |||||
Net Income (Loss) by Business Segment
| 2003 |
2002 |
Favorable (unfavorable) variance |
||||||||||
| Energy Delivery |
$ | 1,175 | $ | 1,268 | $ | (93 | ) | |||||
| Generation |
(151 | ) | 367 | (518 | ) | |||||||
| Enterprises |
(118 | ) | (145 | ) | 27 | |||||||
| Corporate |
(1 | ) | (50 | ) | 49 | |||||||
| Total |
$ | 905 | $ | 1,440 | $ | (535 | ) | |||||
Results of Operations—Energy Delivery
| 2003 |
2002 |
Favorable (unfavorable) variance |
||||||||||
| OPERATING REVENUES |
$ | 10,202 | $ | 10,457 | $ | (255 | ) | |||||
| OPERATING EXPENSES |
||||||||||||
| Purchased power and fuel expense |
4,597 | 4,602 | 5 | |||||||||
| Operating and maintenance |
1,669 | 1,486 | (183 | ) | ||||||||
| Depreciation and amortization |
873 | 978 | 105 | |||||||||
| Taxes other than income |
440 | 531 | 91 | |||||||||
| Total operating expense |
7,579 | 7,597 | 18 | |||||||||
| OPERATING INCOME |
2,623 | 2,860 | (237 | ) | ||||||||
| OTHER INCOME AND DEDUCTIONS |
||||||||||||
| Interest expense |
(747 | ) | (854 | ) | 107 | |||||||
| Distributions on mandatorily redeemable preferred securities |
(39 | ) | (45 | ) | 6 | |||||||
| Equity in income of unconsolidated affiliates |
— | 1 | (1 | ) | ||||||||
| Other, net |
51 | 71 | (20 | ) | ||||||||
| Total other income and deductions |
(735 | ) | (827 | ) | 92 | |||||||
| INCOME BEFORE INCOME TAXES AND CUMULATIVE EFFECT OF A CHANGE IN ACCOUNTING PRINCIPLE |
1,888 | 2,033 | (145 | ) | ||||||||
| INCOME TAXES |
718 | 765 | 47 | |||||||||
| INCOME BEFORE CUMULATIVE EFFECT OF A CHANGE IN ACCOUNTING PRINCIPLE |
1,170 | 1,268 | (98 | ) | ||||||||
| CUMULATIVE EFFECT OF A CHANGE IN ACCOUNTING PRINCIPLE |
5 | — | 5 | |||||||||
| NET INCOME |
$ | 1,175 | $ | 1,268 | $ | (93 | ) | |||||
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Net Income. Energy Delivery’s net income in 2003 decreased primarily due to increased operating and maintenance expense resulting from severance and curtailment charges associated with The Exelon Way, a charge at ComEd associated with a regulatory settlement, lower revenues, net of purchased power primarily attributable to weather and higher purchased power prices, partially offset by reductions in depreciation and amortization expense, taxes other than income, and interest expense.
Operating Revenues. The changes in Energy Delivery’s operating revenues for 2003 compared to 2002 consisted of the following:
| Energy Delivery |
Electric |
Gas |
Total increase |
|||||||||
| Customer choice |
$ | (167 | ) | $ | — | $ | (167 | ) | ||||
| Weather |
(229 | ) | 71 | (158 | ) | |||||||
| Resales and other |
— | (22 | ) | (22 | ) | |||||||
| Rate changes and mix |
(58 | ) | 51 | (7 | ) | |||||||
| Volume |
118 | (3 | ) | 115 | ||||||||
| Other effects |
(15 | ) | (1 | ) | (16 | ) | ||||||
| (Decrease) increase in operating revenues |
$ | (351 | ) | $ | 96 | $ | (255 | ) | ||||
Customer Choice. For 2003 and 2002, 25% and 21%, respectively, of energy delivered to Energy Delivery’s retail customers was provided by an alternative electric supplier or under the ComEd PPO. The decrease in electric retail revenues attributable to customer choice included a decrease in revenues of $155 million from customers in Illinois electing to purchase energy from an alternative electric supplier and a decrease in revenues of $12 million from customers in Pennsylvania selecting or being assigned to an alternative electric generation supplier.
Weather. Energy Delivery’s electric revenues were affected by cooler summer weather in 2003, partially offset by colder winter weather in the first quarter of 2003. Cooling degree-days in the ComEd and PECO service territories were 36% lower and 21% lower, respectively, in 2003 as compared to 2002. Heating degree-days in the ComEd and PECO service territories were 5% higher and 16% higher, respectively, in 2003 as compared to 2002.
Energy Delivery’s gas revenues were affected by colder winter weather in the first quarter of 2003.
Resales and Other. Energy Delivery’s gas revenues decreased as a result of a decrease in off-system sales, exchanges and capacity releases.
Rate Changes and Mix. Energy Delivery’s electric revenues decreased $33 million at ComEd primarily due to decreased average energy rates under ComEd’s PPO as a result of lower wholesale market prices. Electric revenues decreased $25 million at PECO as a result of rate mix due to changes in monthly usage patterns in all customer classes during 2003 as compared to 2002.
Energy Delivery’s gas revenues increased due to increases in rates through the purchased gas adjustment clause that became effective March 1, 2003, June 1, 2003 and December 1, 2003. The average purchased gas cost rate per million cubic feet for 2003 was 11% higher than the rate in 2002. PECO’s purchased gas cost rates are subject to periodic adjustments by the PUC and are designed to recover from or refund to customers the difference between the actual cost of purchased gas and the amount included in rates.
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Volume. Energy Delivery’s electric revenues increased as a result of higher delivery volume, exclusive of the effects of weather and customer choice, due to an increased number of customers and increased usage per customer, primarily in the large and small commercial and industrial customer classes.
Other. The decrease was attributable to a reduction in wholesale revenue. This reduction reflects a $12 million reimbursement from Generation in 2002.
Purchased Power and Fuel Expense. The changes in Energy Delivery’s purchased power and fuel expense for 2003 compared to 2002 consisted of the following:
| Energy Delivery |
Electric |
Gas |
Total increase (decrease) |
|||||||||
| Customer choice |
$ | (143 | ) | $ | — | $ | (143 | ) | ||||
| Weather |
(119 | ) | 49 | (70 | ) | |||||||
| Resales and other |
— | (28 | ) | (28 | ) | |||||||
| Prices |
74 | 39 | 113 | |||||||||
| Volume |
73 | 6 | 79 | |||||||||
| Decommissioning |
62 | — | 62 | |||||||||
| Other |
(23 | ) | 5 | (18 | ) | |||||||
| (Decrease) increase in purchased power and fuel expense |
$ | (76 | ) | $ | 71 | $ | (5 | ) | ||||
Customer Choice. An increase in customer switching resulted in a reduction of purchased power expense, primarily due to ComEd’s non-residential customers electing to purchase energy from an alternative electric supplier or ComEd’s PPO and PECO’s non-residential customers electing or being assigned to purchase energy from alternative energy suppliers.
Weather. Energy Delivery’s purchased power and fuel expense decreased due to the impacts of cooler summer weather in 2003, partially offset by colder winter weather in the first quarter of 2003.
Resales and other. Energy Delivery’s fuel expense decreased as a result of reduced resale transactions.
Prices. Energy Delivery’s purchased power increased for electric due to an increase in the weighted average on-peak/off-peak cost of electricity at ComEd, and fuel expense for gas increased due to PECO’s higher gas prices.
Volume. Energy Delivery’s purchased power and fuel expense increased due to increases, exclusive of the effect of weather, in the number of customers and average usage per customer, primarily large and small commercial and industrial customers at ComEd and PECO.
Decommissioning. ComEd changed its presentation for accounting for decommissioning collections upon the adoption of SFAS No. 143 (see Note 14 of Exelon’s Notes to Consolidated Financial Statements). Decommissioning collections, which are remitted to Generation, were previously recorded as amortization expense and are recorded as purchased power expense in 2003.
Other. Energy Delivery’s purchased power decreased due to additional energy billed in 2002 under the purchase power agreement (PPA) with Generation discussed in other operating revenues above.
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Operating and Maintenance Expense. The changes in operating and maintenance expense for 2003 compared to 2002 consisted of the following:
| Energy Delivery |
Increase (decrease) |
|||
| Severance, pension and postretirement benefit costs associated with The Exelon Way |
$ | 167 | ||
| Charge recorded at ComEd in 2003 associated with a regulatory settlement (a) |
41 | |||
| Increased storm costs |
36 | |||
| Increased employee fringe benefits primarily due to increased health care costs |
23 | |||
| Decreased payroll expense due to fewer employees |
(93 | ) | ||
| Decreased costs associated with the initial implementation of automated meter reading services at PECO in 2002 |
(13 | ) | ||
| Other |
22 | |||
| Increase in operating and maintenance expense |
$ | 183 | ||
| (a) | For more information regarding the settlement, see Note 5 of Exelon’s Notes to Consolidated Financial Statements. |
Depreciation and Amortization Expense. The reduction in depreciation and amortization expense was primarily due to a change in the accounting for nuclear decommissioning at ComEd, lower amortization of ComEd’s recoverable transition costs of $58 million and a $48 million reduction due to changes in ComEd’s depreciation rates in 2002, partially offset by increased depreciation of $30 million due to capital additions across Energy Delivery and increased competitive transition charge amortization of $28 million at PECO.
Taxes Other Than Income. The reduction in taxes other than income was primarily due to a reduction of real estate tax accruals recorded by PECO of $58 million during the third quarter of 2003 and a favorable settlement of coal use tax at ComEd of $25 million. See Note 20 of Exelon’s Notes to Consolidated Financial Statements for further information regarding the reduction of real estate tax accruals recorded by PECO.
Interest Expense. The reduction in interest expense was primarily due to refinancing existing debt at lower rates and the pay down of transitional trust notes.
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Energy Delivery Operating Statistics and Revenue Detail
Energy Delivery’s electric sales statistics and revenue detail were as follows:
| Retail Deliveries—(in GWhs) (a) |
2003 |
2002 |
Variance |
% Change |
||||||
| Full service (b) |
||||||||||
| Residential |
37,564 | 37,839 | (275 | ) | (0.7 | %) | ||||
| Small commercial & industrial |
28,165 | 29,971 | (1,806 | ) | (6.0 | %) | ||||
| Large commercial & industrial |
20,660 | 22,652 | (1,992 | ) | (8.8 | %) | ||||
| Public authorities & electric railroads |
6,022 | 7,332 | (1,310 | ) | (17.9 | %) | ||||
| Total full service |
92,411 | 97,794 | (5,383 | ) | (5.5 | %) | ||||
| Delivery only (c) |
||||||||||
| Residential |
900 | 1,971 | (1,071 | ) | (54.3 | %) | ||||
| Small commercial & industrial |
7,461 | 5,634 | 1,827 | 32.4 | % | |||||
| Large commercial & industrial |
10,689 | 7,652 | 3,037 | 39.7 | % | |||||
| Public authorities & electric railroads |
1,402 | 913 | 489 | 53.6 | % | |||||
| 20,452 | 16,170 | 4,282 | 26.5 | % | ||||||
| PPO (ComEd only) |
||||||||||
| Small commercial & industrial |
3,318 | 3,152 | 166 | 5.3 | % | |||||
| Large commercial & industrial |
4,348 | 5,131 | (783 | ) | (15.3 | %) | ||||
| Public authorities & electric railroads |
1,925 | 1,346 | 579 | 43.0 | % | |||||
| 9,591 | 9,629 | (38 | ) | (0.4 | %) | |||||
| Total delivery only and PPO deliveries |
30,043 | 25,799 | 4,244 | 16.5 | % | |||||
| Total retail deliveries |
122,454 | 123,593 | (1,139 | ) | (0.9 | %) | ||||
| (a) | One gigawatthour is the equivalent of one million kilowatthours (kWh). |
| (b) | Full service reflects deliveries to customers taking electric service under tariffed rates. |
| (c) | Delivery only reflects service from customers electing to receive electric generation service from an alternative electric supplier, which rates include a distribution charge and a CTC. |
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| Electric Revenue |
2003 |
2002 |
Variance |
% Change |
|||||||||
| Full service (a) |
|||||||||||||
| Residential |
$ | 3,715 | $ | 3,719 | $ | (4 | ) | (0.1% | ) | ||||
| Small commercial & industrial |
2,421 | 2,601 | (180 | ) | (6.9% | ) | |||||||
| Large commercial & industrial |
1,394 | 1,496 | (102 | ) | (6.8% | ) | |||||||
| Public authorities & electric railroads |
396 | 456 | (60 | ) | (13.2% | ) | |||||||
| Total full service |
7,926 | 8,272 | (346 | ) | (4.2% | ) | |||||||
| Delivery only (b) |
|||||||||||||
| Residential |
65 | 145 | (80 | ) | (55.2% | ) | |||||||
| Small commercial & industrial |
214 | 159 | 55 | 34.6% | |||||||||
| Large commercial & industrial |
196 | 170 | 26 | 15.3% | |||||||||
| Public authorities & electric railroads |
33 | 28 | 5 | 17.9% | |||||||||
| 508 | 502 | 6 | 1.2% | ||||||||||
| PPO (ComEd only) (c) |
|||||||||||||
| Small commercial & industrial |
225 | 204 | 21 | 10.3% | |||||||||
| Large commercial & industrial |
240 | 278 | (38 | ) | (13.7% | ) | |||||||
| Public authorities & electric railroads |
103 | 71 | 32 | 45.1% | |||||||||
| 568 | 553 | 15 | 2.7% | ||||||||||
| Total delivery only and PPO |
1,076 | 1,055 | 21 | 2.0% | |||||||||
| Total electric retail revenues |
9,002 | 9,327 | (325 | ) | (3.5% | ) | |||||||
| Wholesale and miscellaneous revenue (d) |
555 | 581 | (26 | ) | (4.5% | ) | |||||||
| Total electric revenue |
$ | 9,557 | $ | 9,908 | $ | (351 | ) | (3.5% | ) | ||||
| (a) | Full service revenue reflects deliveries to customers taking electric service under tariffed rates, which include the cost of energy and the delivery cost of the transmission and the distribution of the energy. PECO’s tariffed rates also include a CTC. See Note 5 of Exelon’s Notes to Consolidated Financial Statements for a discussion of CTC. |
| (b) | Delivery only revenue reflects revenue under tariffed rates from customers electing to receive electric generation service from an alternative electric supplier, which rates include a distribution charge and a CTC. |
| (c) | Revenues from customers choosing ComEd’s PPO include an energy charge at market rates, transmission and distribution charges, and a CTC. Prior to ComEd’s full integration into PJM on May 1, 2004, ComEd’s transmission charges received from alternative electric suppliers were included in wholesale and miscellaneous revenue. |
| (d) | Wholesale and miscellaneous revenues include transmission revenue, sales to municipalities and other wholesale energy sales. |
Energy Delivery’s gas sales statistics and revenue detail were as follows:
| Deliveries to customers in million cubic feet (mmcf) |
2003 |
2002 |
Variance |
% Change |
|||||||||
| Retail sales |
61,858 | 54,782 | 7,076 | 12.9 | % | ||||||||
| Transportation |
26,404 | 30,763 | (4,359 | ) | (14.2 | %) | |||||||
| Total |
88,262 | 85,545 | 2,717 | 3.2 | % | ||||||||
| Revenue |
2003 |
2002 |
Variance |
% Change |
|||||||||
| Retail sales |
$ | 609 | $ | 490 | $ | 119 | 24.3 | % | |||||
| Transportation |
18 | 19 | (1 | ) | (5.3 | %) | |||||||
| Resales and other |
18 | 40 | (22 | ) | (55.0 | %) | |||||||
| Total |
$ | 645 | $ | 549 | $ | 96 | 17.5 | % | |||||
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Results of Operations—Generation
As previously described, effective January 1, 2004, Exelon contributed its interest in Exelon Energy Company to Generation. Exelon Energy Company was previously reported as a part of the Enterprises segment. For comparative discussion and analysis, Exelon Energy Company’s results of operations have been included within Generation’s results of operations as if this transfer had occurred on January 1, 2002.
| 2003 |
2002 |
Favorable (unfavorable) variance |
||||||||||
| OPERATING REVENUES |
$ | 8,760 | $ | 7,320 | $ | 1,440 | ||||||
| OPERATING EXPENSES |
||||||||||||
| Purchased power |
3,630 | 3,298 | (332 | ) | ||||||||
| Fuel |
2,115 | 1,372 | (743 | ) | ||||||||
| Operating and maintenance |
1,886 | 1,686 | (200 | ) | ||||||||
| Impairment of Boston Generating, LLC long-lived assets |
945 | — | (945 | ) | ||||||||
| Depreciation and amortization |
201 | 292 | 91 | |||||||||
| Taxes other than income |
121 | 166 | 45 | |||||||||
| Total operating expense |
8,898 | 6,814 | (2,084 | ) | ||||||||
| OPERATING INCOME (LOSS) |
(138 | ) | 506 | (644 | ) | |||||||
| OTHER INCOME AND DEDUCTIONS |
||||||||||||
| Interest expense |
(89 | ) | (79 | ) | (10 | ) | ||||||
| Equity in earnings of unconsolidated affiliates |
49 | 87 | (38 | ) | ||||||||
| Other, net |
(267 | ) | 87 | (354 | ) | |||||||
| Total other income and deductions |
(307 | ) | 95 | (402 | ) | |||||||
| INCOME (LOSS) BEFORE INCOME TAXES, MINORITY INTEREST, AND CUMULATIVE EFFECT OF CHANGES IN ACCOUNTING PRINCIPLES |
(445 | ) | 601 | (1,046 | ) | |||||||
| INCOME TAXES |
(190 | ) | 233 | 423 | ||||||||
| INCOME (LOSS) BEFORE MINORITY INTEREST AND CUMULATIVE EFFECT OF CHANGES IN ACCOUNTING PRINCIPLES |
(255 | ) | 368 | (623 | ) | |||||||
| MINORITY INTEREST |
(4 | ) | (3 | ) | (1 | ) | ||||||
| INCOME (LOSS) BEFORE CUMULATIVE EFFECT OF CHANGES IN ACCOUNTING PRINCIPLES |
(259 | ) | 365 | (624 | ) | |||||||
| CUMULATIVE EFFECT OF CHANGES IN ACCOUNTING PRINCIPLES (net of income taxes) |
108 | 2 | 106 | |||||||||
| NET INCOME (LOSS) |
$ | (151 | ) | $ | 367 | $ | (518 | ) | ||||
Net Income (Loss). The decrease in Generation’s net income in 2003 as compared to 2002 was primarily due to an impairment charge of $945 million before income taxes recorded in 2003 related to the long-lived assets of Boston Generating, impairment and other transaction-related charges of $280 million before income taxes recorded in 2003 related to Generation’s investment in Sithe, and increased operating and maintenance expenses, partially offset by an increase in operating revenues net of purchased power and fuel expense. Generation also experienced an increase in its effective tax rate.
Cumulative effect of changes in accounting principles recorded in 2003 and 2002 included income of $108 million, net of income taxes, recorded in 2003 related to the of adoption of SFAS No. 143 and
84
income of $2 million, net of income taxes, recorded in 2002 related to the adoption of SFAS No. 142. See Note 1 of Exelon’s Notes to Consolidated Financial Statements for further discussion of these effects.
Operating Revenues. Operating revenues increased in 2003 as compared to 2002. Generation’s sales in 2003 and 2002 were as follows:
| Revenue (in millions) |
2003 |
2002 |
Variance |
% Change |
||||||||||
| Electric sales to affiliates |
$ | 3,831 | $ | 3,978 | $ | (147 | ) | (3.7 | %) | |||||
| Wholesale and retail electric sales |
4,107 | 2,736 | 1,371 | 50.1 | % | |||||||||
| Total energy sales revenue |
7,938 | 6,714 | 1,224 | 18.2 | % | |||||||||
| Retail gas sales |
588 | 451 | 137 | 30.4 | % | |||||||||
| Trading portfolio |
1 | (29 | ) | 30 | (103.4 | %) | ||||||||
| Other revenue (a) |
233 | 184 | 49 | 26.6 | % | |||||||||
| Total revenue |
$ | 8,760 | $ | 7,320 | $ | 1,440 | 19.7 | % | ||||||
| Sales (in GWhs) |
2003 |
2002 |
Variance |
% Change |
||||||||||
| Electric sales to affiliates |
112,688 | 118,473 | (5,785 | ) | (4.9 | %) | ||||||||
| Wholesale and retail electric sales |
112,816 | 88,985 | 23,831 | 26.8 | % | |||||||||
| Total sales |
225,504 | 207,458 | 18,046 | 8.7 | % | |||||||||
| (a) | Includes sales related to tolling agreements and fossil fuel sales. |
Trading volumes of 32,584 GWhs and 69,933 GWhs for the years ended December 31, 2003 and 2002, respectively, are not included in the table above. The decrease in trading volume is a result of reduced volumetric and VAR trading limits in 2003, which are set by the Exelon Risk Management Committee and approved by the Board of Directors.
Electric Sales to Affiliates. Sales to affiliates decreased primarily due to lower volume sales to ComEd, offset by slightly higher realized prices. Sales to PECO were lower, primarily due to lower realized prices, partially offset by slightly higher volumes.
Wholesale and Retail Electric Sales. Sales volume in the wholesale spot and bilateral markets increased primarily due to the acquisition of Exelon New England in November 2002 and the commencement of commercial operations in 2003 of the Boston Generating facilities, Mystic 8 and 9 and Fore River. In addition, average market prices were $5/MWh higher than 2002.
Retail Gas Sales. Retail gas sales at Exelon Energy increased $97 million due to higher gas prices in 2003. In addition, customer growth in the gas and electric markets increased revenues by $69 million and $40 million, respectively. These increases were partially offset by the discontinuance of retail sales in the PJM region of $40 million and the wind-down of the Northeast operations of $29 million.
Trading Revenues. Trading activity increased revenue by $1 million in 2003 compared to a reduction in revenue of $29 million in 2002 due to an increase in gas prices in April 2002, which negatively affected Generation’s trading positions.
Other. Revenues also increased in 2003 as compared to 2002, as a result of a $76 million increase in sales of excess fossil fuel. The increased excess fossil fuel is a result of generating plants in the Texas and New England regions operating at less than projected levels. Also, revenue increased by $62 million due to higher decommissioning revenue received from ComEd in 2003 compared to 2002.
85
Purchased Power and Fuel Expense. Generation’s supply of sales in 2003 and 2002, excluding the trading portfolio, was as follows:
| Supply of Sales (in GWhs) |
2003 |
2002 |
% Change |
||||
| Nuclear generation (a) |
117,502 | 115,854 | 1.4 | % | |||
| Purchases—non-trading portfolio (b) |
83,692 | 78,628 | 6.4 | % | |||
| Fossil and hydroelectric generation |
24,310 | 12,976 | 87.3 | % | |||
| Total supply |
225,504 | 207,458 | 8.7 | % | |||
| (a) | Excluding AmerGen. |
| (b) | Including purchase power agreements with AmerGen. |
Generation’s supply mix changed as a result of increased nuclear generation due to a lower number of refueling and unplanned outages during 2003 as compared to 2002, increased fossil generation due to the Exelon New England plants acquired in November 2002, including plants under construction which became operational in the second and third quarters of 2003 and account for an increase of 8,426 GWhs. Additionally, the change included additional purchased power of 3,320 GWhs from Exelon New England, a new PPA with AmerGen which increased purchased power by 3,049 GWhs in the second quarter of 2003 and 11,989 GWhs of other miscellaneous power purchases, which more than offset a 14,208 GWhs reduction in purchased power from Midwest Generation.
The changes in Generation’s purchased power and fuel expense for 2003 compared to 2002 consisted of the following:
| Generation |
Increase | ||
| Exelon New England |
$ | 429 | |
| Prices |
350 | ||
| Volume |
46 | ||
| Hedging activity |
22 | ||
| Other |
228 | ||
| Increase in purchased power and fuel expense |
$ | 1,075 | |
Exelon New England. Generation acquired Exelon New England in November 2002 and Mystic Units 8 and 9 began commercial operations during the second quarter of 2003, while Fore River began commercial operations during the third quarter of 2003.
Prices. The increase reflects higher market prices in 2003.
Volume. Purchased power increased in 2003 due to an increase in purchased power from AmerGen under a June 2003 PPA to purchase 100% of the output of Oyster Creek. Prior to the June 2003 PPA, Generation did not purchase power from Oyster Creek. Fuel expense increased due to increases in fossil fuel generation required to meet the increased market demand for energy and the acquisition of generating plants in Texas in April 2002.
Hedging Activity. Mark-to-market losses on hedging activities were $16 million in 2003 compared to a gain of $6 million in 2002.
Other. Other increases in purchased power and fuel were primarily due to $171 million of higher purchased power and fuel expense at Exelon Energy, additional nuclear fuel amortization of $16 million in 2003 resulting from under-performing fuel, which was completely replaced in May 2003 at the Quad Cities Unit 1, and $10 million due to the write-down of coal inventory in 2003 as a result of a fuel burn analysis.
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Generation’s average margins per MWh sold for the years ended December 31, 2003 and 2002 were as follows:
| ($/MWh) |
2003 |
2002 |
% Change |
||||||
| Average revenue |
|||||||||
| Electric sales to affiliates |
$ | 34.00 | $ | 33.58 | 1.3 | % | |||
| Wholesale electric sales |
36.40 | 30.75 | 18.4 | % | |||||
| Total—excluding the trading portfolio |
35.20 | 32.36 | 8.8 | % | |||||
| Average supply cost—excluding the trading portfolio (a) |
25.48 | 22.51 | 13.2 | % | |||||
| Average margin—excluding the trading portfolio |
9.72 | 9.85 | (1.3 | %) | |||||
| (a) | Average supply cost includes purchased power, fuel costs and PPAs with AmerGen in 2003. |
Operating and Maintenance Expense. The changes in operating and maintenance expense for 2003 compared to 2002 consisted of the following:
| Generation |
Increase (decrease) |
|||
| 2003 asset impairment charge related to long-lived assets of Boston Generating |
$ | 945 | ||
| Adoption of SFAS No. 143 (a) |
118 | |||
| Increased costs due to generating asset acquisitions in 2002 |
78 | |||
| Severance, pension and postretirement benefit costs associated with The Exelon Way |
60 | |||
| Increased employee fringe benefits primarily due to increased health care costs |
54 | |||
| Decreased refueling outage costs (b) |
(49 | ) | ||
| 2002 executive severance |
(19 | ) | ||
| Other |
(42 | ) | ||
| Increase in operating and maintenance expense |
$ | 1,145 | ||
| (a) | Due to a reclassification of decommissioning-related expenses upon the adoption of SFAS No. 143. |
| (b) | Includes cost savings of $19 million related to one of Generation’s co-owned facilities. Refueling outage days, not including Generation’s co-owned facilities, decreased from 202 in 2002 to 157 in 2003. |
The increase in operating and maintenance expense is primarily due to the decision to transition out of the ownership of Boston Generating during the third quarter of 2003. Generation recorded a long-lived asset impairment charge of $945 million ($573 million net of income taxes) in the third quarter of 2003. The remaining increase is due to payroll-related costs due to implementation of the programs associated with The Exelon Way, costs incurred due to generating asset acquisitions made in 2002, partially offset by lower refueling outage costs.
Nuclear fleet operating data and purchased power costs data for the year ended December 31, 2003 and 2002 were as follows:
| Generation |
2003 |
2002 | ||||
| Nuclear fleet capacity factor (a) |
93.4% | 92.7% | ||||
| Nuclear fleet production cost per MWh (a) |
$ | 12.53 | $ | 13.00 | ||
| Average purchased power cost for wholesale operations per MWh (b) |
$ | 43.17 | $ | 41.94 | ||
| (a) | Including AmerGen and excluding Salem, which is operated by PSEG Nuclear. |
| (b) | Including PPAs with AmerGen. |
The higher nuclear capacity factor and decreased production costs are primarily due to 56 fewer planned refueling outage days in 2003 as compared to 2002, resulting in a $36 million decrease in refueling outage costs, including a $6 million decrease related to AmerGen. The years ended December 31, 2003 and 2002 included 30 and 26 unplanned outages, respectively, resulting in a $2 million increase in non-refueling outage costs in 2003 as compared to 2002.
87
Depreciation and Amortization. The decrease in depreciation and amortization expense in 2003 as compared to 2002 was primarily attributable to a $130 million reduction in decommissioning expense net of ARC depreciation, as these costs are included in operating and maintenance expense after the adoption of SFAS No. 143, and a $12 million decrease due to life extensions of assets acquired in 2002. The decrease was partially offset by $65 million of additional depreciation expense on capital additions placed in service in 2002, of which $18 million of expense is related to plant acquisitions made after the third quarter of 2002.
Effective Income Tax Rate. The effective income tax rate was 42.7% for 2003 compared to 38.8% for 2002. This increase was primarily attributable to the impairment charges recorded in 2003 related to the long-lived assets of Boston Generating and Generation’s investment in Sithe that resulted in a pre-tax loss. Other adjustments that affected income taxes include a decrease in tax-exempt interest in 2003 and an increase in nuclear decommissioning investment income for 2003.
Results of Operations—Enterprises
| Enterprises |
2003 |
2002 |
Favorable (unfavorable) variance |
|||||||||
| Operating revenues |
$ | 923 | $ | 1,336 | $ | (413 | ) | |||||
| Purchased power and fuel expense |
— | 6 | 6 | |||||||||
| Operating and maintenance expense |
1,027 | 1,297 | 270 | |||||||||
| Operating loss |
(139 | ) | (11 | ) | (128 | ) | ||||||
| Income (loss) before income taxes and cumulative effect of changes in accounting principles |
(187 | ) | 140 | (327 | ) | |||||||
| Income (loss) before cumulative effect of changes in accounting principles |
(117 | ) | 87 | (204 | ) | |||||||
| Net loss |
(118 | ) | (145 | ) | 27 | |||||||
Net Loss. The decrease in Enterprises’ net loss before cumulative effect of changes in accounting principles in 2003 was primarily due to a decrease in operating revenues, partially offset by a decrease in operating and maintenance expense. Depreciation and amortization expense decreased $15 million before income taxes from 2002 to 2003 primarily as a result of property, plant and equipment classified as held for sale in 2003. In 2003, Enterprises recorded charges for impairments of $46 million before income taxes due to other-than-temporary declines in value and an impairment charge of $8 million before income taxes for its equity method investment in a district cooling business joint venture, partially offset by 2002 charges for impairment of investments of $41 million before income taxes and a net impairment of other assets of $4 million before income taxes. In 2002, Enterprises recorded a pre-tax gain of $198 million on the sale of its investment in AT&T Wireless. The adoption of SFAS No. 143 reduced 2003 net income by $1 million, net of income taxes. The adoption of SFAS No. 142 reduced 2002 net income by $243 million, net of income taxes. See Note 1 of Exelon’s Notes to Consolidated Financial Statements for further discussion of the adoptions of SFAS No. 143 and SFAS No. 142.
Operating Revenues. The changes in Enterprises’ operating revenues for 2003 compared to 2002 consisted of the following:
| Enterprises |
Increase (decrease) |
|||
| InfraSource |
$ | (359 | ) | |
| Exelon Services |
(60 | ) | ||
| Other |
6 | |||
| Decrease in operating revenues |
$ | (413 | ) | |
88
InfraSource. Operating revenues decreased $256 million at InfraSource due to the sale of the majority of the InfraSource businesses in the third quarter of 2003. For the remaining InfraSource businesses, operating revenues decreased $103 million as a result of the closing of certain businesses and the reduction of new business as a result of wind-down efforts.
Exelon Services. Operating revenues decreased $79 million at Exelon Services due to poor economic conditions in the construction market. This decrease was partially offset by improved performance contracting activities of $19 million.
Operating and Maintenance Expense. The changes in Enterprises’ operating and maintenance expense for 2003 compared to 2002 consisted of the following:
| Enterprises |
Increase (decrease) |
|||
| InfraSource |
$ | (267 | ) | |
| Exelon Services |
(6 | ) | ||
| Other |
3 | |||
| Decrease in operating and maintenance expense |
$ | (270 | ) | |
InfraSource. Operating and maintenance expense decreased $222 million due to the sale of the majority of InfraSource businesses in the third quarter of 2003. In addition, operating and maintenance expense decreased $80 million as a result of wind-down efforts of the remaining InfraSource businesses. These decreases were partially offset by increased expense of approximately $30 million due to margin deterioration on various construction projects.
During 2003, Enterprises recorded a net charge to operating and maintenance expense of $4 million (before income taxes and minority interest) associated with the sale of the majority of the InfraSource businesses.
Exelon Services. Operating and maintenance expense decreased $56 million at Exelon Services due primarily to delays on mechanical construction projects resulting from poor economic conditions in the construction market. This decrease was partially offset by additional costs from increased performance contracting activities of $13 million, a goodwill impairment charge of $24 million and other asset impairments of $15 million.
Effective Income Tax Rate. The effective income tax rate was 37.4% for 2003 compared to 37.9% for 2002. The decrease in the effective tax rate was primarily attributable to the AT&T wireless sale.
Liquidity and Capital Resources
Exelon’s businesses are capital intensive and require considerable capital resources. These capital resources are primarily provided by internally generated cash flows from Energy Delivery’s and Generation’s operations. When necessary, Exelon obtains funds from external sources in the capital markets and through bank borrowings. Exelon’s access to external financing at reasonable terms depends on Exelon and its subsidiaries’ credit ratings and general business conditions, as well as that of the utility industry in general. If these conditions deteriorate to the extent that Exelon no longer has access to the capital markets at reasonable terms, Exelon has access to revolving credit facilities with aggregate bank commitments of $1.5 billion that it currently utilizes to support its commercial paper programs. See the “Credit Issues” section of “Liquidity and Capital Resources” for further discussion. Exelon primarily uses its capital resources, including cash, to fund capital requirements, including construction expenditures, retire debt, pay common stock dividends, fund its pension obligations and
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invest in new and existing ventures. Exelon’s construction expenditures utilize a significant amount of cash on projects that have a long-term return on investment. Additionally, Energy Delivery operates in a rate-regulated environment in which recovery of current cash expenditures takes place over an extended period of time. As a result of these factors, Exelon has historically operated with a working capital deficit. However, Exelon expects operating cash flows to be sufficient to meet operating and capital expenditure requirements. Future acquisitions that Exelon may undertake, such as the proposed merger with PSEG, may require external debt financing or the issuance of Exelon common stock.
Cash Flows from Operating Activities
Energy Delivery’s cash flows from operating activities primarily result from sales of electricity and gas to a stable and diverse base of retail customers at fixed prices and are weighted toward the third quarter of each fiscal year. Energy Delivery’s future cash flows will be affected by the impact of the economy, weather, customer choice and future regulatory proceedings on its revenues and its ability to achieve operating cost reductions. Generation’s cash flows from operating activities primarily result from the sale of electric energy to wholesale customers, including Energy Delivery. Generation’s future cash flows from operating activities will be affected by future demand for and market prices of energy and its ability to continue to produce and supply power at competitive costs.
Cash flows from operations have been, and are expected to continue to provide, a reliable, steady source of cash flow, sufficient to meet operating and capital expenditures requirements for the foreseeable future. Operating cash flows after 2006 could be negatively affected by changes in the rate regulatory environments of ComEd and PECO, although any effects are not expected to hinder the ability to fund their business requirements. See “Business Outlook and the Challenges in Managing the Business” for further information regarding the regulatory transition periods. Additionally, Exelon, through its ComEd subsidiary, has taken certain tax positions, which have been disclosed to the Internal Revenue Service (IRS), to defer the tax gain on the 1999 sale of its fossil generating assets. See Note 13 of Exelon’s Notes to Consolidated Financial Statements for additional information regarding these tax positions.
The following table provides a summary of the major items impacting cash flows from operations:
| 2004 |
2003 |
Variance |
||||||||||
| Net income |
$ | 1,864 | $ | 905 | $ | 959 | ||||||
| Non-cash operating activities (a) |
2,274 | 2,989 | (715 | ) | ||||||||
| Changes in working capital and other noncurrent assets and liabilities (b) |
530 | (366 | ) | 896 | ||||||||
| Pension and post-retirement healthcare benefit payments |
(270 | ) | (144 | ) | (126 | ) | ||||||
| Net cash flow from operations |
$ | 4,398 | $ | 3,384 | $ | 1,014 | ||||||
| (a) | Represents depreciation, amortization and accretion, deferred income taxes, cumulative effect of changes in accounting principle, impairment of investments and long-lived assets and other non-cash charges. |
| (b) | Changes in working capital and other noncurrent assets and liabilities exclude the changes in commercial paper and the current portion of long-term debt. |
Cash flows provided by operations in 2004 and 2003 were $4,398 million and $3,384 million, respectively. Changes in Exelon’s cash flows provided by operations were generally consistent with changes in its results of operations, as adjusted by changes in working capital in the normal course of business. The $1,014 million increase in cash flows provided by operations from 2003 to 2004 was due primarily to an increase in operating income of $1,156 million during 2004 over 2003 and changes in working capital and other asset and liability accounts, including income taxes. The timing of the working capital and other noncurrent asset and liability account changes resulted in an increase to cash flows provided by operations of approximately $896 million in 2004 over 2003, approximately
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$564 million of which is the result of the timing of Federal income tax activity. The operating cash flows resulting from Federal income tax activity were primarily the result of the following:
| • | Exelon reduced its Federal income tax obligation by approximately $315 million and $140 million in 2004 and 2003, respectively, for tax-deductible pension plan contributions of approximately $900 million to be contributed prior to September 15, 2005 and $400 million contributed prior to September 15, 2004, respectively. |
| • | Exelon realized Federal income tax credits from its investments in synthetic fuel producing facilities, which reduced its 2004 and 2003 Federal income taxes payable by approximately $216 million and $23 million, respectively. |
| • | Exelon recorded approximately $631 million and $1,057 million of special depreciation allowances in 2004 and 2003, respectively, that resulted in the reduction of Federal income taxes payable of approximately $220 million and $370 million, respectively. Approximately $150 million of the 2003 special depreciation allowance was recorded as a Federal income tax receivable at December 31, 2003 and filed and collected as a corporate application for quick refund in March 2004. This activity resulted in a $300 million year over year increase in cash flows from 2003 to 2004. |
| • | In November 2003, Exelon recorded a Federal income tax receivable of approximately $120 million for capital losses generated in 2003 related to its investment in Sithe, which were carried back to prior periods. The transaction was presented as a use of cash in Exelon’s December 31, 2003 statement of cash flows. |
The combination of the income tax activities described above and other income tax activities reduced the amount of cash paid for income taxes from approximately $730 million in 2003 to approximately $200 million in 2004, a decrease of $530 million.
Additionally, the following non-recurring operating cash flows occurred during 2004:
| • | In December 2004, TXU and Generation terminated a tolling agreement and entered into a new agreement. Upon termination of the original agreement, Generation received a cash payment of $172 million. The resulting gain was deferred and will be recognized as income over the contractual term of the new agreement. See Note 2 of Exelon’s Notes to Consolidated Financial Statements for further information regarding the transaction with TXU. |
| • | Net cash received for collateral for 2004 was $73 million, compared to $68 million paid in 2003. The year over year increase in cash flows of $141 million was primarily due to the reduction of cash collateral requirements for certain trading counterparties as a result of Generation negotiating the acceptance of letters of credit during 2004 to satisfy current and future collateral obligations. |
| • | During 2004, Exelon paid $86 million for prepayment premiums on the retirement of ComEd debt. See “Cash Flows from Financing Activities” for further information regarding debt retirements pursuant to the accelerated liability management plan. |
Exelon management does not expect the changes in working capital associated with income taxes and other non-recurring events, as described above, that contributed to the increase in cash flows provided by operations in 2004 to recur.
Pension and other non-pension postretirement payments. Discretionary tax-deductible pension plan payments were $439 million in 2004 compared to $367 million in 2003. Exelon also contributed $11 million during 2004 to the pension plans needed to satisfy minimum funding requirements of the Employee Retirement Income Security Act. Additionally, $132 million and $135 million were contributed to the postretirement welfare benefit plans for 2004 and 2003, respectively. See Note 15 of Exelon’s
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Notes to Consolidated Financial Statements for further information regarding pension and postretirement benefits.
Exelon expects to contribute approximately $2 billion to its pension plans in 2005, which will be funded primarily through the issuance of debt in 2005. These contributions exclude benefit payments expected to be made directly from corporate assets. Of the $2 billion expected to be contributed to the pension plans during 2005, $13 million is estimated to be needed to satisfy Employee Retirement Income Security Act (ERISA) minimum funding requirements.
Cash Flows from Investing Activities
Cash flows used in investing activities for 2004 and 2003 were $1,736 million and $2,109 million, respectively. In addition to the recurring investing activities presented on the face of the Consolidated Statement of Cash Flows, significant investing activities by business segment during 2004 and 2003 are as follows:
Exelon
| • | Exelon received cash proceeds of $76 million, net of $2 million held in escrow at December 31, 2004, from the sale of its investments in affordable housing in 2004. |
| • | Exelon contributed $56 million to investments in synthetic fuel-producing facilities in 2004. |
Generation
| • | Exelon Generation received cash proceeds of $42 million from the January 2004 sale of three gas turbines that were classified as assets held for sale at December 31, 2003. |
| • | On March 31, 2004, Exelon consolidated the assets and liabilities of Sithe under the provisions of FIN 46-R, which resulted in an increase in cash of $19 million. See Note 1 and Note 3 of Exelon’s Notes to Consolidated Financial Statements for further information regarding the FIN 46-R consolidation of Sithe. |
| • | Sithe collected a $20 million note receivable during 2004 related to the sale of certain businesses of Sithe during the fourth quarter of 2003 and the first quarter of 2004. |
| • | On November 25, 2003, Generation, Reservoir, and Sithe completed a series of transactions resulting in Generation and Reservoir each indirectly owning a 50% interest in Sithe. Net cash proceeds from the series of transactions were $44 million. In addition, a note was received from EXRES SHC, Inc. for $92 million. See Note 3 and Note 25 of Exelon’s Notes to Consolidated Financial Statements for further information regarding this transaction and Generation’s sale of Sithe. |
| • | In December 2003, Generation purchased the 50% interest in AmerGen held by British Energy for $240 million, net of cash acquired of $36 million. The acquisition was funded with cash provided by operations. |
Enterprises
| • | Cash proceeds of $227 million, net of transaction costs and contingency payments on prior year dispositions, were received during 2004 from the sales of Exelon Thermal Holdings, Inc., substantially all of the operating businesses of Exelon Services, Inc., and Enterprises’ investments in PECO TelCove and other equity method and cost basis investments of Enterprises. |
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| • | Early settlement on an acquisition note receivable from the 2003 disposition of InfraSource resulted in cash proceeds of $30 million during 2004. |
| • | In September 2003, Enterprises sold the electric construction and services, underground and telecom businesses of InfraSource for cash of $175 million, net of transaction costs and cash transferred to the buyer upon sale. |
Investing activities in 2004 and 2003 exclude the non-cash issuance of $22 million and $238 million of notes payable, respectively, for Exelon’s investments in synthetic fuel-producing facilities. Exelon expects these investments to provide more than $200 million of net cash benefits from 2005 through 2008, with peak net cash of approximately $100 million in 2008.
Capital expenditures by business segment for 2004 and projected amounts for 2005 are as follows:
| 2004 |
2005 | |||||
| Energy Delivery |
$ | 946 | $ | 1,023 | ||
| Generation |
960 | 1,073 | ||||
| Corporate and other |
15 | 56 | ||||
| Total capital expenditures |
$ | 1,921 | $ | 2,152 | ||
Excluding acquisitions, capital requirements during 2005 are expected to be met through internally generated cash or external borrowings. Exelon’s proposed capital expenditures and other investments are subject to periodic review and revision to reflect changes in economic conditions and other factors.
Energy Delivery. Energy Delivery’s projected capital expenditures for 2005 reflect continuing efforts to improve the reliability of its transmission and distribution systems and capital additions to support new business and customer growth. Exelon anticipates that Energy Delivery’s capital expenditures will be funded by internally generated funds, borrowings or capital contributions from Exelon.
Generation. Exelon projects that Generation’s capital expenditures for 2005 will be higher than they were in 2004. The majority of these expenditures will be for additions and upgrades to existing facilities, nuclear fuel and increases in capacity at existing plants. Generation is planning on eleven nuclear refueling outages in 2005, compared to ten during 2004; however, the projected total non-fuel capital expenditures for the nuclear plants are expected to decrease in 2005 from 2004 by $40 million. Exelon anticipates that Generation’s capital expenditures will be funded by internally generated funds, borrowings or capital contributions from Exelon.
Cash Flows from Financing Activities
Cash flows used in financing activities for 2004 were $2,627 million compared to $1,240 million for the same period in 2003. The increase in cash used in financing activities was primarily attributable to an increase in the net retirement of long-term debt and preferred securities during 2004 of $2,221 million. Exelon retired $1.2 billion of long-term debt, including $1.0 billion prior to its maturity and $206 million at maturity, during 2004 in accordance with an accelerated liability management plan and retired $728 million of long-term debt due to financing affiliates. During 2003, Exelon issued debt (net of retirements during the period) and preferred stock of approximately $96 million. See Note 12 of Exelon’s Notes to Consolidated Financial Statements for further information regarding debt issuances and retirements during 2004. During 2004, Exelon issued $164 million of commercial paper, net of payments, and received cash proceeds of $33 million from the settlement of interest-rate swaps.
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During 2003, Exelon repaid $355 million of commercial paper and paid $43 million to settle interest- rate swaps. Additionally, Exelon repurchased common shares totaling $82 million during 2004 and received proceeds from employee stock plans of $240 million and $181 million during 2004 and 2003, respectively.
In 2004, Generation paid $27 million of a note payable to Sithe, compared to $446 million paid in 2003. At December 31, 2004, Generation had repaid $473 million of the note payable, resulting in a remaining balance of $63 million, which was paid upon the completion of a series of transactions that resulted in Generation’s exit from its investment in Sithe on January 31, 2005. See Note 25 of Exelon’s Notes to Consolidated Financial Statements for further information regarding the sale of Sithe.
The 2004 cash dividend payments on common stock increased $211 million over 2003, reflecting a 10% increase in the first quarter of 2004 and an 11% increase in the third quarter of 2004. See further discussion of Exelon’s dividend policy within the “Dividends” section of ITEM 5 of this Form 10-K.
From time to time and as market conditions warrant, Exelon may engage in long-term debt retirements via tender offers, open market repurchases or other viable options to strengthen its balance sheet. In the third quarter of 2004, Exelon initiated an accelerated liability management plan. Through December 31, 2004, ComEd had retired approximately $1.2 billion of debt under the plan, including $1.0 billion prior to its maturity and $206 million at maturity.
Credit Issues
Exelon Credit Facility
Exelon meets its short-term liquidity requirements primarily through the issuance of commercial paper by Exelon, ComEd, PECO and Generation. At December 31, 2004, Exelon, along with ComEd, PECO and Generation, participated with a group of banks in a $1 billion unsecured revolving facility maturing on July 16, 2009 and a $500 million unsecured revolving credit facility maturing on October 31, 2006. Both revolving credit agreements are used principally to support the commercial paper programs at Exelon, ComEd, PECO and Generation and to issue letters of credit.
At December 31, 2004, Exelon, ComEd, PECO and Generation had the following sublimits and available capacity under the credit agreements and the indicated amounts of outstanding commercial paper:
| Borrower |
Bank Sublimit (a) |
Available Capacity (b) |
Outstanding Commercial Paper | ||||||
| Exelon |
$ | 700 | $ | 685 | $ | 490 | |||
| ComEd |
100 | 74 | — | ||||||
| PECO |
100 | 100 | — | ||||||
| Generation |
600 | 444 | — | ||||||
| (a) | Sublimits under the credit agreements can change upon written notification to the bank group. |
| (b) | Available capacity represents the bank sublimit net of outstanding letters of credit. The amount of commercial paper outstanding does not reduce the available capacity under the credit facilities. |
Interest rates on advances under the credit facilities are based on either prime or the London Interbank Offering Rate (LIBOR) plus an adder based on the credit rating of the borrower as well as the total outstanding amounts under the agreement at the time of borrowing. The maximum LIBOR adder is 170 basis points.
The average interest rates on commercial paper in 2004 for Exelon, ComEd, PECO and Generation were approximately 1.51%, 2.11%, 1.08% and 1.14%, respectively.
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The credit agreements require Exelon, ComEd, PECO and Generation to maintain a minimum cash from operations to interest expense ratio for the twelve-month period ended on the last day of any quarter. The ratios exclude revenues and interest expenses attributable to securitization debt, certain changes in working capital, distributions on preferred securities of subsidiaries and, in the case of Exelon and Generation, revenues from Sithe and interest on the debt of its project subsidiaries. The following table summarizes the minimum thresholds reflected in the credit agreements for the twelve-month period ended December 31, 2004:
| Exelon |
ComEd |
PECO |
Generation | |||||
| Credit agreement threshold |
2.65 to 1 | 2.25 to 1 | 2.25 to 1 | 3.25 to 1 |
At December 31, 2004, Exelon, ComEd, PECO and Generation were in compliance with the foregoing thresholds.
At December 31, 2004, Exelon’s capital structure consisted of 56% of long-term debt, including long-term debt to financing trusts, 41% common equity, 2% notes payable and less than 1% preferred securities of subsidiaries. Total debt included $5.3 billion owed to unconsolidated affiliates of ComEd and PECO that qualify as special purpose entities under FIN 46-R. These special purpose entities were created for the sole purpose of issuing debt obligations to securitize intangible transition property and CTCs of Energy Delivery or mandatorily redeemable preferred securities. See Note 1 of Exelon’s Notes to Consolidated Financial Statements for further information regarding FIN 46-R.
Intercompany Money Pool
To provide an additional short-term borrowing option that will generally be more favorable to the borrowing participants than the cost of external financing, Exelon operates an intercompany money pool. Participation in the money pool is subject to authorization by the corporate treasurer. ComEd and its subsidiary, Commonwealth Edison Company of Indiana, Inc. (ComEd of Indiana), PECO, Generation and BSC may participate in the money pool as lenders and borrowers, and Exelon and UII, LLC, a wholly owned subsidiary of Exelon, may participate as lenders. Funding of, and borrowings from, the money pool are predicated on whether the contributions and borrowings result in economic benefits. Interest on borrowings is based on short-term market rates of interest or, if from an external source, specific borrowing rates. Maximum amounts contributed to and borrowed from the money pool by participant during 2004 are described in the following table in addition to the net contribution or borrowing as of December 31, 2004:
| Maximum Contributed |
Maximum Borrowed |
December 31, 2004 Contributed (Borrowed) |
||||||||
| ComEd |
$ | 487 | $ | 43 | $ | 308 | ||||
| ComEd of Indiana (a) |
21 | — | — | |||||||
| PECO |
162 | 70 | 34 | |||||||
| Generation |
53 | 546 | (283 | ) | ||||||
| BSC |
— | 197 | (59 | ) | ||||||
| UII, LLC |
160 | — | — | |||||||
| (a) | The activity at ComEd of Indiana was eliminated in the consolidation of ComEd. |
Security Ratings
Exelon’s, ComEd’s, PECO’s and Generation’s access to the capital markets, including the commercial paper market, and its financing costs in those markets depend on the securities ratings of the entity that is accessing the capital markets. On December 20, 2004, Standard and Poor’s Rating Services placed the ratings of Exelon and its subsidiaries on credit watch with negative implications in
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response to the announced Merger between Exelon and PSEG. None of Exelon’s borrowings is subject to default or prepayment as a result of a downgrading of securities although such a downgrading could increase fees and interest charges under Exelon’s credit facilities.
The following table shows the Registrants’ securities ratings at December 31, 2004:
| Securities |
Moody’s Investors Service |
Standard & Poors Corporation |
Fitch Investors Service, Inc. | |||||
| Exelon |
Senior unsecured debt | Baa2 | BBB+ | BBB+ | ||||
| Commercial paper | P2 | A2 | F2 | |||||
| ComEd |
Senior secured debt | A3 | A- | A- | ||||
| Commercial paper | P2 | A2 | F2 | |||||
| Transition bonds (a) | Aaa | AAA | AAA | |||||
| PECO |
Senior secured debt | A2 | A- | A | ||||
| Commercial paper | P1 | A2 | F1 | |||||
| Transition bonds (b) | Aaa | AAA | AAA | |||||
| Generation |
Senior unsecured debt | Baa1 | A- | BBB+ | ||||
| Commercial paper | P2 | A2 | F2 |
| (a) | Issued by ComEd Transitional Funding Trust, an unconsolidated affiliate of ComEd. |
| (b) | Issued by PETT, an unconsolidated affiliate of PECO. |
A security rating is not a recommendation to buy, sell or hold securities and may be subject to revision or withdrawal at any time by the assigning rating agency.
As part of the normal course of business, Exelon routinely enters into physical or financially settled contracts for the purchase and sale of capacity, energy, fuels and emissions allowances. These contracts either contain express provisions or otherwise permit its counterparties and Exelon to demand adequate assurance of future performance when there are reasonable grounds for doing so. In accordance with the contracts and applicable contracts law, if Exelon or Generation is downgraded by a credit rating agency, especially if such downgrade is to a level below investment grade, it is possible that a counterparty would attempt to rely on such a downgrade as a basis for making a demand for adequate assurance of future performance. Depending on its net position with a counterparty, the demand could be for the posting of collateral. In the absence of expressly agreed to provisions that specify the collateral that must be provided, the obligation to supply the collateral requested will be a function of the facts and circumstances of Exelon or Generation’s situation at the time of the demand. If Exelon can reasonably claim that it is willing and financially able to perform its obligations, it may be possible to successfully argue that no collateral should be posted or that only an amount equal to two or three months of future payments should be sufficient.
See the PUHCA Restrictions section below for discussion of investment grade ratings under PUHCA.
Shelf Registration
As of December 31, 2004, Exelon, ComEd and PECO had current shelf registration statements for the sale of $2.0 billion, $555 million and $550 million, respectively, of securities that were effective with the SEC. The ability of Exelon, ComEd or PECO to sell securities off its shelf registration statement or to access the private placement markets will depend on a number of factors at the time of the proposed sale, including other required regulatory approvals, the current financial condition of the company, its securities ratings and market conditions.
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PUHCA Restrictions
On April 1, 2004, Exelon obtained an order from the SEC under the Public Utilities Holding Company Act of 1935 (PUHCA) authorizing, through April 15, 2007, financing transactions, including the issuance of common stock, preferred securities, equity-linked securities, long-term debt and short-term debt in an aggregate amount not to exceed $8.0 billion above the amount outstanding for Exelon Corporate and Generation at December 31, 2003. No securities have been issued under the above-described limit. Exelon is also authorized to issue guarantees, letters of credit, or otherwise provide credit support with respect to the obligations of its subsidiaries and non-affiliated third parties in the normal course of business of up to $6.0 billion outstanding at any one time. At December 31, 2004, Exelon had provided $2.0 billion of guarantees and letters of credit under the SEC order. See “Contractual Obligations and Off-Balance Sheet Arrangements” in this section for further discussion of guarantees. The SEC order requires Exelon to maintain a ratio of common equity to total capitalization (including securitization debt) of not less than 30%. At December 31, 2004, Exelon’s common equity ratio was 42%. Exelon expects that it will maintain a common equity ratio of at least 30%.
Exelon is also limited by the April 1, 2004 order to an aggregate investment of $4.0 billion in exempt wholesale generators (EWGs) and foreign utility companies (FUCOs). At December 31, 2004, Exelon had invested $2.2 billion in EWGs, leaving $1.8 billion of investment authority under the order. In that order, the SEC reserved jurisdiction over an additional $3.0 billion in investments in EWGs.
The loss of investment grade ratings for any outstanding security of ComEd, PECO or Generation would suspend the financing authority of the issuer to issue certain other securities and guarantees. The loss of investment grade ratings for any outstanding security of Exelon would suspend financing authority for ComEd, PECO, Generation and Exelon to issue certain other securities and guarantees. Exceptions include long-term debt issuances by ComEd and PECO (authorization for such security issuances are granted by the ICC and the PUC, respectively), common stock and the issuance of securities for the purpose of funding money pool operations. For purposes of investment grade ratings, a security will be deemed to be rated investment grade if it is rated investment grade by at least one nationally recognized statistical rating organization.
In cases where the financing authority of Exelon or a subsidiary is suspended in the circumstances as described above, Exelon would nevertheless be able to seek specific further authority from the SEC for it or its subsidiaries to continue to issue securities upon receipt of further SEC authorization.
Under applicable law, Exelon, ComEd, PECO and Generation can pay dividends only from retained, undistributed or current earnings. A significant loss recorded at ComEd, PECO or Generation may limit the dividends that these companies can distribute to Exelon. At December 31, 2004, Exelon had retained earnings of $3.4 billion, including ComEd’s retained earnings of $1,102 million (all of which had been appropriated for future dividend payments), PECO’s retained earnings of $607 million and Generation’s undistributed earnings of $761 million.
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Contractual Obligations and Off-Balance Sheet Arrangements
The following table summarizes Exelon’s future estimated cash payments under existing contractual obligations, including payments due by period.
| Payment due within |
Due 2010 and beyond | ||||||||||||||
| Total |
2005 |
2006-2007 |
2008-2009 |
||||||||||||
| Long-term debt |
$ | 7,774 | $ | 424 | $ | 712 | $ | 1,023 | $ | 5,615 | |||||
| Long-term debt to financing trusts |
5,342 | 486 | 1,840 | 1,665 | 1,351 | ||||||||||
| Interest payments on long-term debt (a)(b) |
4,031 | 429 | 790 | 644 | 2,168 | ||||||||||
| Interest payments on long-term debt to financing trusts (a) |
1,938 | 329 | 515 | 285 | 809 | ||||||||||
| Commercial paper |
490 | 490 | — | — | — | ||||||||||
| Capital leases |
50 | 3 | 5 | 4 | 38 | ||||||||||
| Operating leases |
909 | 73 | 134 | 114 | 588 | ||||||||||
| Power purchase obligations |
9,497 | 2,024 | 1,973 | 1,288 | 4,212 | ||||||||||
| Fuel purchase agreements |
3,639 | 639 | 985 | 616 | 1,399 | ||||||||||
| Other purchase obligations (c) |
463 | 241 | 134 | 57 | 31 | ||||||||||
| Chicago agreement (d) |
48 | 6 | 12 | 12 | 18 | ||||||||||
| Regulatory commitments |
20 | 10 | 10 | — | — | ||||||||||
| Spent nuclear fuel obligation |
878 | — | — | — | 878 | ||||||||||
| Obligation to minority shareholders |
49 | 3 | 5 | 5 | 36 | ||||||||||
| Pension ERISA minimum funding requirement |
13 | 13 | — | — | — | ||||||||||
| Decommissioning (e) |
3,981 | — | — | — | 3,981 | ||||||||||
| Total contractual obligations |
$ | 39,122 | $ | 5,170 | $ | 7,115 | $ | 5,713 | $ | 21,124 | |||||
| (a) | Interest payments are estimated based on final maturity dates of debt securities outstanding at December 31, 2004 and do not reflect anticipated future refinancing, early redemptions or debt issuances. Variable rate interest obligations are estimated based on rates as of December 31, 2004. In 2004, Exelon’s Board of Directors approved contributions of approximately $2 billion in 2005 to Exelon’s defined benefit pension plans. The contributions will be funded in part by additional debt anticipated to be issued in 2005. Estimated future payments associated with the anticipated debt issuance have not been included in the table above. |
| (b) | Includes Sithe-related interest payments of $71 million, $132 million, $115 million and $849 million for payments due in 2005, 2006-2007, 2008-2009 and 2010 and beyond, respectively. See Note 25 of Exelon’s Notes to Consolidated Financial Statements for information regarding the sale of Generation’s investment in Sithe. |
| (c) | Commitments for services and materials, minimum spend requirements related to the sale of InfraSource (see Note 2 of Exelon’s Consolidated Financial Statements) and amounts committed for information technology services. |
| (d) | On February 20, 2003, ComEd entered into separate agreements with Chicago and with Midwest Generation (Midwest Agreement). Under the terms of the agreement with Chicago, ComEd will pay Chicago $60 million over ten years to be relieved of a requirement, originally transferred to Midwest Generation upon the sale of ComEd’s fossil stations in 1999, to build a 500-MW generation facility. |
| (e) | Represents the present value of Generation’s obligation to decommission nuclear plants. |
For additional information about:
| • | regulatory commitments, see Note 5 of Exelon’s Notes to Consolidated Financial Statements. |
| • | commercial paper, see Note 11 of Exelon’s Notes to Consolidated Financial Statements. |
| • | long-term debt, see Note 12 of Exelon’s Notes to Consolidated Financial Statements. |
| • | capital lease obligations, see Note 12 of Exelon’s Notes to Consolidated Financial Statements. |
| • | the spent nuclear fuel and decommissioning obligations, see Note 14 of Exelon’s Notes to Consolidated Financial Statements. |
| • | the contribution required to Exelon’s pension plans to satisfy ERISA minimum funding requirements, see Note 15 of Exelon’s Notes to Consolidated Financial Statements. |
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| • | operating leases, energy commitments, fuel purchase agreements and other purchase obligations, see Note 20 of Exelon’s Notes to Consolidated Financial Statements. |
| • | the obligation to minority shareholders, see Note 20 of Exelon’s Notes to Consolidated Financial Statements. |
Mystic Development LLC (Mystic) a former affiliate of Exelon New England has a long-term agreement through January 2020 with Distrigas of Massachusetts Corporation (Distrigas) for gas supply, primarily for the Boston Generating units. Under the agreement, gas purchase prices from Distrigas are indexed to the New England gas markets. Exelon New England has guaranteed Mystic’s financial obligations to Distrigas under the long-term supply agreement. Exelon New England’s guarantee to Distrigas remained in effect following the transfer of ownership interest in Boston Generating in May 2004. Under FIN 45, “Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness to Others” (FIN 45), approximately $16 million was included as a liability within the Consolidated Balance Sheet of Exelon as of December 31, 2004 related to this guarantee. The terms of the guarantee do not limit the potential future payments that Exelon New England could be required to make under the guarantee.
Exelon paid down $27 million of the Exelon New England note during 2004 to fund Sithe’s acquisition of the 40% of Sithe/Independence Power Partners, L.P. that it did not own. Sithe is now the owner of 100% of the Independence generating plant.
Generation has an obligation to decommission its nuclear power plants. NRC regulations require that licensees of nuclear generating facilities demonstrate reasonable assurance that funds will be available in certain minimum amounts at the end of the life of the facility to decommission the facility. Based on estimates of decommissioning costs for each of the nuclear facilities in which Generation has an ownership interest, the ICC permits ComEd, and the PUC permits PECO, to collect from their customers and deposit in nuclear decommissioning trust funds maintained by Generation amounts which, together with earnings thereon, will be used to decommission such nuclear facilities. Generation also maintains nuclear decommissioning trust funds for each of the AmerGen units. Upon adoption of SFAS No. 143, Generation was required to re-measure its decommissioning liabilities at fair value and recorded an asset retirement obligation of $2.4 billion on January 1, 2003. Increases in the asset retirement obligation to decommission nuclear generating facilities resulting from the passage of time are recorded as operating and maintenance expense. Increases in the asset retirement obligation resulting from a remeasurement are recorded with a corresponding ARC, which is a component of property, plant and equipment. At December 31, 2004, the asset retirement obligation recorded within Generation’s Consolidated Balance Sheet was approximately $4.0 billion. Decommissioning expenditures are expected to occur primarily after the plants are retired. Based on current licenses and anticipated renewals, decommissioning expenditures for plants in operation are currently estimated to begin in 2029. To fund future decommissioning costs, Generation held $5.3 billion of investments in trust funds, including net unrealized gains and losses, at December 31, 2004. See Note 14 of Exelon’s Notes to Consolidated Financial Statements for further discussion of Generation’s decommissioning obligation.
See Note 20 of Exelon’s Notes to Consolidated Financial Statements for discussion of Exelon’s commercial commitments as of December 31, 2004.
IRS Refund Claims
ComEd and PECO have entered into several agreements with a tax consultant related to the filing of refund claims with the IRS. ComEd and PECO previously made refundable prepayments to the tax consultant of $11 million and $5 million, respectively. The fees for these agreements are contingent upon a successful outcome of the claims and are based upon a percentage of the refunds to be recovered from the IRS, if any. The ultimate net cash outflow from ComEd and PECO related to all the agreements will either be positive or neutral depending upon the outcome of the refund claims with the
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IRS. These potential tax benefits and associated fees could be material to the financial position, results of operations and cash flows of ComEd and PECO. A portion of ComEd’s tax benefits, including any associated interest for periods prior to the PECO / Unicom Merger, would be recorded as a reduction of goodwill pursuant to a reallocation of the PECO / Unicom Merger purchase price. See below for discussion of the final approval of ComEd’s income tax refund claim. PECO cannot predict the timing of the final resolution of its refund claims.
During 2004, the IRS granted preliminary approval for one of ComEd’s refund claims. As such, ComEd believes that it is probable that a fee will ultimately be paid to the tax consultant. Therefore, ComEd recorded an expense of $5 million (pre-tax), which resulted in a decrease to the prepayment from $11 million to $6 million. The charge represents an estimate of the fee to the tax consultant which may be adjusted upward or downward depending on the IRS’ final calculation of the tax and interest benefit. As of December 31, 2004, ComEd had not reflected the tax benefit associated with the refund claim pending final approval of the IRS; however, as described above, the net income statement impact for ComEd is anticipated to be neutral or positive.
In the first quarter of 2005, ComEd received final approval for the income tax refund described above; however the calculation of the claim, including interest has not been finalized. As a portion of the refund will be recorded against goodwill under the provisions of EITF Issue No. 93-7, “Uncertainties Related to Income Taxes in a Purchase Business Combination,” the net result is not anticipated to have a material impact on Exelon’s results of operations.
Variable Interest Entities
Sithe. As of December 31, 2004, Generation was a 50% owner of Sithe. In accordance with FIN 46-R, Generation consolidated Sithe within its financial statements as of March 31, 2004. The determination that Sithe qualified as a variable interest entity and that Generation was the primary beneficiary under FIN 46-R required analysis of the economic benefits accruing to all parties pursuant to their ownership interests supplemented by management’s judgment. See Note 3 and Note 25 of Exelon’s Notes to Consolidated Financial Statements for a discussion of Generation’s ownership in Sithe and the ultimate sale of Generation’s entire interest in Sithe, which was completed on January 31, 2005.
Financing Trusts of ComEd and PECO. During June 2003, PECO issued $103 million of subordinated debentures to PECO Trust IV in connection with the issuance by PECO Trust IV of $100 million of preferred securities. Effective July 1, 2003, PECO Trust IV was deconsolidated from the financial statements of PECO in conjunction with FIN 46. The $103 million of subordinated debentures issued by PECO to PECO Trust IV was recorded as long-term debt to financing trusts within the Consolidated Balance Sheets.
Effective December 31, 2003, ComEd Financing II, ComEd Financing III, ComEd Funding, LLC, ComEd Transitional Funding Trust, PECO Trust III and PETT were deconsolidated from the financial statements of Exelon in conjunction with the adoption of FIN 46-R. Amounts of $5.3 billion owed by ComEd and PECO to these financing trusts were recorded as long-term debt to ComEd Transitional Funding Trust and PETT and long-term debt to financing trusts within the Consolidated Balance Sheets as of December 31, 2004. See Other Subsidiaries of ComEd and PECO with Publicly Held Securities in Part I, Item 1 for further discussion of the nature, purpose and history of Exelon’s involvement with these financing trusts.
PECO Accounts Receivable Agreement
PECO is party to an agreement with a financial institution under which it can sell or finance with limited recourse an undivided interest, adjusted daily, in up to $225 million of designated accounts receivable until November 2005. PECO entered into this agreement to diversify its funding sources at
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favorable floating interest rates. At December 31, 2004, PECO had sold a $225 million interest in accounts receivable, consisting of a $179 million interest in accounts receivable, which PECO accounted for as a sale under SFAS No. 140, “Accounting for Transfers and Servicing of Financial Assets and Extinguishment of Liabilities—a Replacement of FASB Statement No. 125,” and a $46 million interest in special agreement accounts receivable, which PECO accounted for as a long-term note payable and reflected on the consolidated balance sheet as long-term debt due within one year. At December 31, 2003, PECO had sold a $225 million interest in accounts receivable, consisting of a $176 million interest in accounts receivable which PECO accounted for as a sale under SFAS No. 140 and a $49 million interest in special-agreement accounts receivable which was accounted for as a long-term note payable. PECO must continue to service these receivables and must maintain the level of the accounts receivable at $225 million. If PECO fails to maintain that level, the cash that would otherwise be received by PECO under this program must be held in escrow until the level is met. At December 31, 2004 and 2003, PECO met this requirement and was not required to make any cash deposit.
Nuclear Insurance Coverage
Generation carries property damage, decontamination and premature decommissioning insurance for each station loss resulting from damage to Generation’s nuclear plants, subject to certain exceptions. Additionally, Generation carries business interruption insurance in the event of a major accidental outage at a nuclear station. Finally, Generation participates in the American Nuclear Insurers Master Worker Program, which provides coverage for worker tort claims filed for bodily injury caused by a nuclear energy accident. See Note 20 of Exelon’s Notes to Consolidated Financial Statements for further discussion of nuclear insurance. For its types of insured losses, Generation is self-insured to the extent that losses are within the policy deductible or exceed the amount of insurance maintained. Such losses could have a material adverse effect on Exelon and Generation’s financial condition and their results of operations and cash flows.
Business Outlook and the Challenges in Managing the Business
Substantially all of Exelon’s businesses are in the electric generation, transmission and distribution industry in the United States. That industry is in the midst of a fundamental and, at this point, uncertain transition from a fully regulated industry offering bundled service to an industry with unbundled services, some of which are regulated and others of which are priced in competitive markets. Exelon’s Energy Delivery business remains highly regulated while Exelon’s Generation and Enterprises businesses operate in competitive environments. All of Exelon’s businesses are capital intensive.
The challenges affecting Exelon’s businesses are discussed below. There are several factors, such as weather, economic activity and regulatory actions that affect its businesses in different ways. Also, there are several factors that affect its business as a whole, such as environmental compliance and the ability to access capital on a cost-effective basis. Further discussion of its liquidity and capital resources and related challenges is included in the Liquidity and Capital Resources section.
Energy Delivery
The Energy Delivery business is comprised of two utility transmission and distribution companies, ComEd and PECO, which provide electricity and, in the case of PECO, natural gas to customers in Illinois and Pennsylvania, respectively. Energy Delivery focuses on providing safe and reliable services to customers. Energy Delivery continues to make improvements to its delivery systems to minimize the frequency and duration of service interruptions, while working more efficiently to lower costs. Exelon believes that Energy Delivery will continue to provide a significant and steady source of earnings and cash flows over the next several years.
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Both Illinois and Pennsylvania have adopted restructuring legislation designed to foster competition in the retail sale of electricity. As a result of these restructuring initiatives, both ComEd and PECO are subject to rate freezes or caps through mandated restructuring transition periods. During these periods, the results of operations of ComEd and PECO will depend on their ability to deliver energy in a cost-efficient manner and to offset infrastructure investments and inflation with cost savings. ComEd and PECO each have long-term, full-requirements supply contracts with Generation, helping to mitigate the risk of changing energy supply costs during their respective transition periods. Energy Delivery is also managing operating and maintenance costs, while maintaining a strong focus on both reliability and safety in operating its business.
Exelon cannot currently predict the frameworks that will be used by the Illinois and Pennsylvania state regulators to establish rates after the transition periods. Exelon also cannot predict the outcome of any new laws that may impact its business. Nevertheless, Exelon expects that ComEd and PECO will continue to be obligated to deliver electric power and energy to customers in their respective service territories and will also retain significant POLR obligations, whereby each utility is required to provide electric power and energy service to customers in its service area. ComEd and PECO therefore must continue to ensure that adequate supplies of electricity and gas are available at reasonable costs.
More detailed explanations for each of these and other challenges in managing the Energy Delivery business are as follows:
Exelon must comply with numerous regulatory requirements in managing the Energy Delivery business, which affect their costs and responsiveness to changing events and opportunities.
The Energy Delivery business is subject to regulation at the state and Federal levels. State commissions regulate the rates, terms and conditions of service; various business practices and transactions; financings; and transactions between the utilities and affiliates. The FERC regulates the utilities’ transmission rates, certain other aspects of their businesses and, for PECO, gas pipelines. The regulations adopted by these state and Federal agencies affect the manner in which Energy Delivery does business, its ability to undertake specified actions, the costs of its operations, and the level of rates Energy Delivery may charge to recover such costs.
Energy Delivery must manage its costs due to the rate and equity return limitations imposed on its revenues.
Rate freezes or caps in effect at ComEd and PECO currently limit their ability to recover increased expenses and the costs of investments in new transmission and distribution facilities. As a result, Energy Delivery’s future results of operations will depend on the ability of ComEd and PECO to deliver electricity and, in the case of PECO, natural gas in a cost-efficient manner.
Rate limitations. ComEd is subject to a legislatively mandated rate freeze on bundled retail rates that will remain in effect until January 1, 2007. Pursuant to a PECO / Unicom Merger-related settlement agreement with the PUC, PECO is subject to agreed-upon electric service rate reductions of $200 million, in aggregate, for the period January 1, 2002 through December 31, 2005, including $40 million in each of 2004 and 2005, and caps (subject to limited exceptions for significant increases in Federal or state income taxes or other significant changes in law or regulation that do not allow PECO to earn a fair rate of return) on its transmission and distribution rates through December 31, 2006, and on its generation rates through December 31, 2010.
Equity return limitation. ComEd is subject to a legislatively mandated cap on its return on common equity through the end of 2006. The cap is based on a two-year average of the U.S. Treasury long-term rates (20 years and above) plus 8.5% and is compared to a two-year average return on
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ComEd’s common equity. The legislation requires customer refunds equal to one-half of any earnings above the cap. ComEd is allowed to include regulatory asset amortization in the calculation of earnings. Under Illinois statute, any impairment of goodwill has no impact on the determination of the cap on ComEd’s allowed equity return during the transition period. ComEd has not triggered the earnings sharing provision in 2004 or previous years and does not expect to trigger that provision in 2005 or 2006.
Energy Delivery’s long-term purchase power agreements provide a hedge to its customers’ demand.
To effectively manage its obligation to provide power to meet its customers’ demand, Energy Delivery has established full-requirements, power supply agreements with Generation which reduce exposure to the volatility of customer demand and market prices through 2006 for ComEd and through 2010 for PECO. Market prices relative to Energy Delivery’s regulated rates still influence whether retail customers purchase energy from Energy Delivery or from an alternative electric supplier.
Effective management of capital projects is important to Energy Delivery’s business.
Energy Delivery’s business is capital intensive and requires significant investments in energy transmission and distribution facilities and in other internal infrastructure projects.
Energy Delivery expects to continue to make significant capital expenditures to improve the reliability of its transmission and distribution systems and for capital additions to support new business and customer growth. It is anticipated that Energy Delivery’s capital expenditures will exceed depreciation on its plant assets. Energy Delivery’s base rate freeze and caps will generally preclude rate recovery on any of these incremental investments prior to January 1, 2007.
Energy Delivery’s business may be significantly affected by the end of the Illinois and Pennsylvania regulatory transition periods.
Illinois. Illinois electric utilities are allowed to collect competitive transition charges (CTCs) from customers who choose an alternative electric supplier or choose ComEd’s power purchase option (PPO). CTCs were intended to assist electric utilities, such as ComEd, in recovering stranded costs that might not otherwise be recoverable in a fully competitive market. The CTC charge represents the difference between the market value of delivered energy (the sum of generation service at market-based prices and the regulated price of energy delivery) and recoveries under historical bundled rates, reduced by a mitigation factor. The CTCs are updated annually. Over time, to facilitate the transition to a competitive market, the mitigation factor increases, thereby reducing the CTC.
In 2004 and 2003, ComEd collected $169 million and $304 million, respectively, of CTC revenue. As a result of increasing mitigation factors, changes in energy prices and the ability of certain customers to establish fixed, multi-year CTC rates beginning in 2003, it is anticipated that this revenue source will decline to approximately $90 million to $110 million in each of the years 2005 and 2006. Under the current restructuring statute, no CTCs will be collected after 2006.
Through 2006, ComEd will continue to have an obligation to offer bundled service to all customers (except certain large customers with demand of three MWs or more) at frozen price levels, under which a majority of ComEd’s residential and small commercial customers are expected to continue to receive service. ComEd’s current bundled service is generally provided under an all-inclusive rate that does not separately break out charges for energy generation service and energy delivery service, but charges a single set of prices. After the transition ends in 2006, ComEd’s bundled rates may be reset through a regulatory approval process, which may include traditional or innovative pricing, including performance-based incentives to ComEd.
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In order to address post-transition uncertainty, ComEd is continually working with the ICC, consumer advocates and business community leadership to facilitate the development of a competitive electricity market while providing system reliability and safety. ComEd is promoting constructs that will move it towards transparent and liquid markets to allow for power procurement that will be deemed prudent, provide consumers assurance of equitable pricing and ensure cost recoverability. At the same time, ComEd is attempting to establish a regulatory framework for the post-2006 timeframe. Currently, it is difficult to predict the framework for, or the outcome of, a potential regulatory proceeding to establish rates after 2006.
In 2004, the ICC initiated and conducted a workshop process to consider issues related to retail electric service in the post-transition period (i.e., post-2006). Issues addressed included utility wholesale supply procurement methodology, rates, competition and utility service obligations. All interested parties were invited to participate. The end result was a report to the Illinois General Assembly which was generally supportive of continuing under the existing regulatory framework and of utilities procuring supply through a full-requirements, vertical tranche, descending clock auction process with full recovery of the supply costs from retail customers. In 2005, utilities including ComEd, are expected to begin to seek regulatory approval of structures that implement the methodologies supported by the report or such other proposals as they may choose to make. ComEd intends to make various filings during 2005 to begin the process to establish rates for the post-transition period. ComEd currently expects that these filings will include a proposal consistent with the auction process described above. All such methodologies and proposals will be subject to regulatory approval. ComEd cannot predict which particular proposal or proposals will be approved.
Pennsylvania. In Pennsylvania, the Pennsylvania Electricity Generation Customer Choice and Competition Act (Competition Act) provides for the imposition and collection of non-bypassable CTCs on customers’ bills as a mechanism for utilities to recover their allowed stranded costs. CTCs are assessed to and collected from virtually all retail customers who access PECO’s transmission and distribution systems. These CTCs are assessed regardless of whether the customer purchases electricity from PECO or an alternative electric supplier. The Competition Act provides, however, that PECO’s right to collect CTCs is contingent on the continued operation, at reasonable availability levels, of the assets for which the stranded costs were awarded, except where continued operation is no longer cost efficient because of the transition to a competitive market.
PECO has been authorized by the PUC to recover stranded costs of $5.3 billion over a twelve-year period ending December 31, 2010, with a return on the unamortized balance of 10.75%. At December 31, 2004, approximately $3.9 billion had yet to be recovered. Recovery of transition charges for stranded costs and PECO’s allowed return on its recovery of stranded costs are included in revenues. Amortization of PECO’s stranded cost recovery, which is a regulatory asset, is included in depreciation and amortization expense. PECO’s results will be adversely affected over the remaining transition period ending December 31, 2010 by the steadily increasing amortization of stranded costs. The following table (amounts in millions) indicates the estimated revenues and amortization expense associated with CTC collection and stranded cost recovery through 2010.
| Year |
Estimated CTC Revenue |
Estimated Stranded Cost Amortization | ||||
| 2005 |
$ | 808 | $ | 404 | ||
| 2006 |
903 | 550 | ||||
| 2007 |
910 | 619 | ||||
| 2008 |
917 | 697 | ||||
| 2009 |
924 | 783 | ||||
| 2010 |
932 | 880 | ||||
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By the end of 2010, PECO will have fully recovered all of the stranded costs authorized by the PUC. As a result, PECO expects that both its revenues and expenses will decrease in 2011.
PECO’s transmission and distribution rates are capped through 2006, while PECO’s generation rates are capped through 2010. The end of these transition periods involves uncertainties, including the nature of PECO’s POLR obligations and the source and pricing of generation services to be provided by PECO. PECO will continue to work with Federal and state regulators, state and local governments, customer representatives and other interested parties to develop appropriate processes for establishing future rates in restructured electricity markets. PECO will strive to ensure that future rate structures recognize the substantial improvements PECO has made, and will continue to make, in its transmission and distribution systems. PECO will also work to ensure that its rates are adequate to cover its costs of obtaining electric power and energy from its suppliers, which could include Generation, for the costs associated with procuring full requirements power given PECO’s POLR obligations. As in the past, by working together with all interested parties, PECO believes it can successfully meet these objectives and obtain fair recovery of its costs for providing service to its customers; however, if PECO is unsuccessful, its results of operations and cash flows could be negatively affected after the transition periods.
Energy Delivery’s ability to successfully manage the end of the transition period may affect its capital structure.
Exelon and ComEd had approximately $4.7 billion of goodwill recorded at December 31, 2004. This goodwill was recognized and recorded in connection with the PECO / Unicom Merger. Under GAAP, the goodwill will remain at its recorded amount unless it is determined to be impaired, which is based upon an annual analysis prescribed by SFAS No. 142, “Goodwill and Other Intangible Assets” (SFAS No. 142) that compares the implied fair value of the goodwill to its carrying value. If an impairment occurs, the amount of the impaired goodwill will be written off and expensed, reducing equity. Under Illinois law, any impairment of goodwill has no impact on the determination of ComEd’s rate cap through the transition period.
Goodwill was not impaired at Exelon or ComEd during 2004. Exelon’s goodwill impairment test considers the cash flows of the entire Energy Delivery business segment, including both ComEd and PECO, and not just of ComEd; accordingly, a goodwill impairment charge at ComEd may not affect Exelon’s results of operations.
However, based on certain anticipated reductions to cash flows (primarily reductions in CTCs) subsequent to ComEd’s regulatory transition period, there is a reasonable possibility that goodwill will be impaired at ComEd, and possibly at Exelon, in 2005 or later periods. The actual timing and amounts of any goodwill impairments in future years will depend on many sensitive, interrelated and uncertain variables, including changing interest rates, utility sector market performance, ComEd’s capital structure, market prices for power, post-2006 rate regulatory structures, operating and capital expenditure requirements and other factors, some not yet known.
See Critical Accounting Policies and Estimates for further discussion on goodwill impairments.
Energy Delivery is and will continue to be involved in regulatory proceedings as a part of the process of establishing the terms and rates for its services.
These regulatory proceedings typically involve multiple parties, including governmental bodies, consumer advocacy groups and various consumers of energy, who have differing concerns but who have the common objective of limiting rate increases or even reducing rates. The proceedings also involve various contested issues of law and fact and have a bearing upon the recovery of Energy Delivery’s costs through regulated rates. During the course of the proceedings, Energy Delivery looks
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for opportunities to resolve contested issues in a manner that grants some certainty to all parties to the proceedings as to rates and energy costs.
Energy Delivery’s business is affected by the restructuring of the energy industry.
The electric utility industry in the United States is in transition. As a result of both legislative initiatives as well as competitive pressures, the industry has been moving from a fully regulated industry, consisting primarily of vertically integrated companies that combine generation, transmission and distribution, to a partially restructured industry, consisting of competitive wholesale generation markets and continued regulation of transmission and distribution. Due to a number of factors, these developments have been somewhat uneven across the states. Both Illinois and Pennsylvania have adopted restructuring legislation designed to foster competition in the retail sale of electricity, but a large number of other states have not changed their regulatory structures.
Regional Transmission Organizations and Standard Market Platform. The FERC required jurisdictional utilities to provide open access to their transmission systems as early as the late 1980’s. Subsequently, the FERC encouraged the voluntary development of RTOs and the elimination of trade barriers between regions. RTOs provide transmission service. Transmission owners remain responsible for maintaining and operating their transmission facilities, under the direction of RTOs, and recover their revenue requirements through the RTOs. ComEd and PECO are members of PJM, a FERC-approved RTO operating in the Mid-Atlantic and Midwest regions. RTOs direct the dispatch of generation units as a means of centrally managing congestion on transmission systems without curtailing service. RTOs also manage transparent and competitive short-term energy markets.
The FERC’s efforts to promote RTOs throughout the states has generated substantial opposition by some state regulators and other governmental bodies. In addition, efforts to develop an RTO have been abandoned in certain regions. Notwithstanding these difficulties, MISO has been certified as a RTO by the FERC. MISO is attempting to develop central generation dispatch and transmission operations across the Midwestern United States, contiguous to PJM’s footprint. The FERC has ordered the elimination of rate barriers and protocol differences between MISO and PJM. Energy Delivery supports the development of RTOs and implementation of standard market protocols for these regions, and others, but cannot predict their success or whether they will lead to the development of the envisioned large, successful wholesale markets. The development of large competitive wholesale electricity markets would facilitate an auction to meet ComEd’s and PECO’s POLR load obligations with reliable wholesale electricity supply when their long-term supply contracts with Generation expire. In the meantime, Energy Delivery’s transmission facilities are being operated by PJM successfully with little impact on ComEd’s or PECO’s transmission rates and revenues.
Proposed Federal Energy Legislation. Attempts have been made to adopt comprehensive Federal energy legislation that, among other things, would repeal PUHCA, create incentives for the construction of transmission infrastructure, encourage but not mandate standardized competitive markets and expand the authority of the FERC to include overseeing the reliability of the bulk power system. Exelon cannot predict whether comprehensive energy legislation will be adopted and, if adopted, the final form of that legislation. Exelon would expect that comprehensive energy legislation would, if adopted, significantly affect the electric utility industry and its businesses. Such legislation did not pass Congress during 2004 but is expected to be reintroduced in Congress in early 2005.
Energy Delivery must maintain the availability and reliability of its delivery systems to meet customer expectations.
Increases in both customers and the demand for energy require expansion and reinforcement of Energy Delivery’s delivery systems to increase capacity and maintain reliability. Failures of the
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equipment or facilities used in its delivery systems could potentially interrupt energy delivery services and related revenues and increase repair expenses and capital expenditures. Such failures of Energy Delivery’s systems or those of other utilities, including prolonged or repeated failures, could affect customer satisfaction, the level of regulatory oversight and Energy Delivery’s maintenance and capital expenditures, and expose Energy Delivery to claims by customers and others.
Regulated utilities that are required to provide service to all customers and others within their service territory have generally been afforded liability protections against claims by customers relating to failure of service. Under Illinois law, ComEd can be required to pay damages to its customers in the event of extended outages affecting large numbers of its customers.
Energy Delivery has lost and may continue to lose energy customers and related revenue to other generation suppliers, although Energy Delivery continues to provide delivery services.
Energy Delivery’s retail electric customers may purchase their generation supply from alternative electric suppliers, although Energy Delivery remains obligated to provide transmission and distribution service to customers in its service territories regardless of their generation supplier. As of December 31, 2004, no alternative electric supplier had approval from the ICC, and no electric utilities had chosen to enter the ComEd residential market for the supply of electricity. ComEd and PECO are each generally obligated to provide generation and delivery service to customers in their service territories at fixed rates or, in some instances, market-derived rates. In addition, customers who take service from an alternative electric supplier may later return to ComEd or PECO. The number of customers taking service from alternative electric suppliers depends in part on the prices being offered by those suppliers relative to the fixed prices that ComEd and PECO are authorized to charge by their state regulatory commissions. To the extent that customers leave traditional bundled tariffs and select a different electric supplier, Energy Delivery’s revenues are likely to decline, and revenues and gross margins could vary from period to period.
Energy Delivery’s post-transition period and provider of last resort obligations add uncertainty to planning its electricity supply needs and its ability to manage the related costs of that supply.
In 2004, the ICC initiated and conducted a workshop process to consider issues related to retail electric service in the post-transition period (i.e., post-2006). Issues addressed included utility wholesale supply procurement methodology, rates, competition and utility service obligations. All interested parties were invited to participate. The end result was a report to the Illinois General Assembly which was generally supportive of continuing under the existing regulatory framework and of utilities procuring supply through a full-requirements, vertical tranche, descending clock auction process with full recovery of the supply costs from retail customers. In 2005, utilities, including ComEd, are expected to begin to seek regulatory approval of structures that implement the methodologies supported by the report or such other proposals as they may choose to make. ComEd intends to make various filings during 2005 to begin the process to establish rates for the post transition period. These filings will include a proposal consistent with the auction process described above. All such methodologies and proposals will be subject to regulatory approval. ComEd cannot predict which particular proposals will be approved.
Because ComEd and PECO customers can “switch,” that is, within limits they can choose an alternative electric supplier and then return to either ComEd or PECO and then go back to an alternative electric supplier, and so on, planning for Energy Delivery has a higher level of uncertainty than that traditionally experienced due to weather and the economy. Energy Delivery has no obligation to purchase power reserves to cover the load served by others. Energy Delivery manages its POLR obligation through full-requirements contracts with Generation, under which Generation supplies the
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power requirements of ComEd and PECO. Also, Energy Delivery has sought through the regulatory process, as permitted by law, to retain the POLR obligation to customers who do not have competitive supply options and limit the POLR obligation for those customers that do have competitive supply options. In 2003, ComEd received ICC approval to phase out over several years its obligation to provide fixed-price energy under bundled rates to approximately 370 of its largest energy customers, which have demands of at least three MWs and represent an aggregate of approximately 2,500 MWs of load. To date, ComEd has not requested to phase out its obligation to provide fixed-price energy under bundled rates for other customers but continues to evaluate its options, particularly with respect to customers having energy demands of one to three MWs.
A mandatory renewable portfolio standard (RPS) could affect the cost of electricity purchased and sold by Energy Delivery.
Renewable and alternative fuel sources such as wind, solar, biomass and geothermal are anticipated to have an increasingly important role in creating fuel diversity in the generation of electricity. Federal or state legislation mandating a RPS could result in significant changes in Energy Delivery’s business, including fuel cost and capital expenditures. Energy Delivery continues to monitor discussions related to RPSs at the Federal and state levels.
For additional information, see “Environmental Regulation—Renewable and Alternative Energy Portfolio Standards” in Item 1 of this Form 10-K.
Weather affects electricity and gas usage and, consequently, Energy Delivery’s results of operations.
Temperatures above normal levels in the summer tend to increase summer cooling electricity demand and revenues, and temperatures below moderate levels in the winter tend to increase winter heating electricity and gas demand and revenues. As a corollary, moderate temperatures adversely affect the usage of energy and resulting revenues. Because of seasonal pricing differentials, coupled with higher consumption levels, Energy Delivery typically reports higher revenues in the third quarter of the fiscal year. However, extreme summer conditions or storms may stress Energy Delivery’s transmission and distribution systems, resulting in increased maintenance costs and limiting its ability to meet peak customer demand. These extreme conditions may have detrimental effects on Energy Delivery’s operations.
Economic conditions and activity in Energy Delivery’s service territories directly affect the demand for electricity and gas.
Higher levels of development and business activity generally increase the number of Energy Delivery’s customers and their average use of energy. Periods of recessionary economic conditions may adversely affect Energy Delivery’s results of operations. Retail electric and gas sales growth on an annual basis is expected to be between 1% and 2% in the service territories of ComEd and PECO.
Generation
Generation is focused on efficiently providing reliable power through a generation portfolio with fuel and dispatch diversity. Generation’s directive is to continue to increase fleet output and to improve fleet efficiency while sustaining operational safety. Generation’s Power Team manages the output of Generation’s assets and energy sales to optimize value and reduce the volatility of Generation’s earnings and cash flows. Exelon believes that Generation will provide a steady source of earnings through its low-cost operations and will take advantage of higher wholesale prices when they can be
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realized. More detailed explanations for each of these and other challenges in managing the Generation business are as follows:
Generation must effectively manage its power portfolio to meet its contractual commitments and to handle changes in the wholesale power markets.
The majority of Generation’s portfolio is used to provide power under long-term purchase power agreements with ComEd and PECO. To the extent portions of the portfolio are not needed for that purpose, Generation’s output is sold on the wholesale market. To the extent that its portfolio is not sufficient to meet the requirements of ComEd and PECO, Generation must purchase power in the wholesale power markets. Generation’s financial results are dependent upon its ability to cost-effectively meet the load requirements of ComEd and PECO, to manage its power portfolio and to effectively handle the changes in the wholesale power markets.
Generation must effectively plan for the elimination of significant purchase power arrangements post 2006.
Generation sells a significant portion of its output to ComEd and PECO under long-term purchase power agreements. As a result of the continuing transition from a regulated environment, the agreement with ComEd, which expires at the end of 2006, is unlikely to be replaced with a similar arrangement. If the agreement is not replaced, Generation may need to sell more power at market-based prices. Illinois has considered both regulated and competitive models for the post-transition periods, including an auction-based model and new contractual arrangements with third parties, which may have shorter durations and lower volume sales. A regulated model may not adequately compensate Generation for its investment in its generating facilities. Increased market sales and new contractual arrangements under a competitive model may adversely affect Generation’s credit risk due to an increase in the number of customers and the loss of a highly predictable revenue source.
The scope and scale of Generation’s nuclear generating resources provide a cost advantage in meeting contractual commitments and enable Generation to sell power in the wholesale markets.
Generation’s resources include interests in 11 nuclear generation stations, consisting of 19 units. Generation’s nuclear fleet generated 136,621 GWhs, or more than half of Generation’s total output, for the year ended December 31, 2004. As the largest generator of nuclear power in the United States, Generation can negotiate favorable terms for the materials and services that its business requires. Generation’s nuclear plants benefit from stable fuel costs, minimal environmental impact from operations and a safe operating history.
Generation’s financial performance may be affected by liabilities arising from its ownership and operation of nuclear facilities.
The ownership and operation of nuclear facilities involve risks as further described below.
Nuclear capacity factors. Capacity factors, particularly nuclear capacity factors, significantly affect Generation’s results of operations. Nuclear plant operations involve substantial fixed operating costs but produce electricity at low variable costs due to low fuel costs. Consequently, to be successful, Generation must consistently operate its nuclear generating facilities at high capacity factors. Lower capacity factors increase Generation’s operating costs by requiring Generation to generate additional energy from its fossil or hydroelectric facilities or purchase additional energy in the spot or forward markets in order to satisfy Generation’s obligations to ComEd and PECO and other committed third-party sales. These sources generally have a higher operating cost than Generation incurs to generate energy from its nuclear stations.
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Refueling outages. Outages at nuclear stations to replenish fuel require the station to be “turned off.” Refueling outages are planned to occur once every 18 to 24 months and currently average approximately 25 days in duration. Generation has significantly decreased the length of refueling outages in recent years; however, when refueling outages at wholly and co-owned plants last longer than anticipated or Generation experiences unplanned outages, capacity factors decrease and Generation faces lower margins due to higher energy replacement costs and/or lower energy sales. Each 25-day outage, depending on the capacity of the station, will decrease the total nuclear annual capacity factor between 0.3% and 0.5%. The number of refueling outages, including the AmerGen plants and the co-owned Salem plant operated by PSEG, will increase from ten in 2004 to eleven in 2005; however, the projected total non-fuel capital expenditures for the nuclear plants will decrease in 2005 from 2004 by approximately $40 million. Maintenance expenditures are expected to increase by approximately $15 million in 2005 compared to 2004 as a result of the increased number of planned nuclear outages.
Nuclear fuel quality. The quality of nuclear fuel utilized by Generation can affect the efficiency and costs of Generation’s operations. Certain of Generation’s nuclear units have been identified as having a limited number of fuel performance issues. Remediation actions, including those required to address performance issues, could result in increased costs due to accelerated fuel amortization and/or increased outage costs. It is difficult to predict the total cost of these remediation procedures.
Spent nuclear fuel storage. Generation incurs costs on an annual basis for the storage of spent nuclear fuel. Under the terms of the settlement reached with the DOE in 2004, Generation will be reimbursed for costs of spent fuel storage. The approval of a national repository for the storage of spent nuclear fuel, such as the one proposed for Yucca Mountain, Nevada, and the timing of such facility opening, will significantly affect the costs associated with storage of spent nuclear fuel, and the ultimate amounts received from the DOE under the settlement. Also, the availability of a repository for spent nuclear fuel may affect the ability to fully decommission the nuclear units.
License Renewals. Generation’s nuclear facilities are currently operating under 40-year Nuclear Regulatory Commission (NRC) licenses. Generation has applied for and received 20-year renewals for the licenses that will be expiring in the next ten years, excluding licenses for the AmerGen facilities. Generation has received 20-year renewals of the operating licenses for the Peach Bottom 2 and 3, Dresden 2 and 3 and Quad Cities 1 and 2 Units. In December 2004, the NRC issued an order that will permit Oyster Creek to operate beyond its license expiration in April 2009 if the NRC has not completed reviewing the application for renewal. The application for Oyster Creek’s license renewal is anticipated to be filed by August 2005 in order to comply with this agreement. Generation intends to evaluate opportunities, as permitted by the NRC, to apply for license renewals for some or all of the remaining licenses. If the renewals are granted, Generation cannot assure that economics will support the continued operation of the facilities for all or any portion of the renewed license. If the NRC does not renew the operating licenses for Generation’s nuclear stations, Generation’s results of operations could be adversely affected by increased depreciation rates and accelerated future decommissioning payments.
Management believes the current status of Yucca Mountain will not impact Generation’s ability to renew the licenses for its nuclear plants. However, should a national policy for the disposal of spent nuclear fuel not be developed, the unavailability of a repository for spent nuclear fuel could become a consideration by the NRC during future nuclear license renewal proceedings, including applications for new licenses, and may affect Generation’s ability to fully decommission its nuclear units.
Regulatory risk. The NRC may modify, suspend or revoke licenses, shut down a nuclear facility and impose civil penalties for failure to comply with the Atomic Energy Act, related regulations or the terms of the licenses for nuclear facilities. A change in the Atomic Energy Act or the applicable regulations or licenses may require a substantial increase in capital expenditures or may result in
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increased operating or decommissioning costs and significantly affect Generation’s results of operations or financial position. Events at nuclear plants owned by others, as well as those owned by Generation, may cause the NRC to initiate such actions.
Operational risk. Operations at any of Generation’s nuclear generation plants could degrade to the point where Generation has to shut down the plant or operate at less than full capacity. If this were to happen, identifying and correcting the causes may require significant time and expense. Generation may choose to close a plant rather than incur the expense of restarting it or returning the plant to full capacity. In either event, Generation may lose revenue and incur increased fuel and purchased power expense to meet supply commitments. For plants operated but not wholly owned by Generation, Generation may also incur liability to the co-owners.
On January 28, 2004, the NRC issued a letter requesting PSEG to conduct a review of its Salem facility, of which Generation owns 42.59%, to assess the workplace environment for raising and addressing safety issues. PSEG responded to the letter on February 28, 2004, and had independent assessments of the work environment at the facility performed. Assessment results were provided to the NRC in May 2004. The assessments concluded that Salem was safe for continued operation, but also identified issues that needed to be addressed. At an NRC public meeting on June 16, 2004, PSEG outlined its action plans to address these issues, which focus on safety conscious work environment, the corrective action program and work management. A letter documenting these plans and commitments was sent to the NRC on June 25, 2004. On July 30, 2004, the NRC provided a letter to PSEG indicating that it had completed its review. The letter indicated that the NRC has not identified any safety violations and that it appears that the PSEG action plan will address the key findings of both the NRC and PSEG assessments. On August 30, 2004, the NRC provided PSEG with its mid-cycle performance reviews of Salem, which detailed the NRC’s plan for enhanced oversight related to the work environment. The letter indicated the NRC plans to continue with this heightened oversight until PSEG has concluded that substantial, sustainable progress has been made, and the NRC has completed a review that confirms PSEG’s conclusions. Under the NRC oversight program, among other things, PSEG provided the NRC with a report of its progress at a public meeting in December 2004, and began publishing quarterly metrics to demonstrate performance in the fourth quarter of 2004. The next public meeting is scheduled for spring 2005.
The spent fuel pool at each Salem unit has an installed leakage collection system. This normal leakage path was found to be obstructed, causing concern about the extent of leakage contact with the fuel handling building’s concrete structure. PSEG is developing a solution to maintain the design function of the leakage collection system and is investigating the extent of any structural degradation caused by the leakage. The investigation should take approximately one year. If any significant degradation is identified, the repair costs to the owners of the facility could be material. The NRC issued Information Notice 2004-05 in March 2004 concerning this emerging industry issue and Generation cannot predict what further actions the NRC may take on this matter.
Nuclear accident risk. Although the safety record of nuclear reactors, including Generation’s, generally has been very good, accidents and other unforeseen problems have occurred both in the United States and elsewhere. The consequences of an accident can be severe and include loss of life and property damage. Any resulting liability from a nuclear accident may exceed Generation’s resources, including insurance coverages, and significantly affect Generation’s results of operations or financial position.
Nuclear insurance. The Price-Anderson Act limits the liability of nuclear reactor owners for claims that could arise from a single incident. The limit as of December 31, 2004 is $10.76 billion and is subject to change to account for the effects of inflation and changes in the number of licensed reactors. As required by the Price-Anderson Act, Generation carries the maximum available amount of nuclear
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liability insurance (currently $300 million for each operating site). Claims exceeding that amount are covered through mandatory participation in a financial protection pool. Although the Price-Anderson Act has expired, only facilities applying for NRC licenses subsequent to its expiration are affected. Existing commercial generating facilities, such as those owned and operated by Generation, remain subject to the provisions of the Price-Anderson Act.
Nuclear Electric Insurance Limited (NEIL), a mutual insurance company to which Generation belongs, provides property and business interruption insurance for Generation’s nuclear operations. In recent years, NEIL has made distributions to its members. Generation’s distribution for 2004 was $40 million, which was recorded as a reduction to operating and maintenance expenses in its Consolidated Statement of Income. Generation cannot predict the level of future distributions or if they will continue at all.
Decommissioning. Generation has an obligation to decommission its nuclear power plants. Based on estimates of decommissioning costs for each of the nuclear facilities in which Generation has an ownership interest, other than AmerGen facilities, the ICC permits ComEd and the PUC permits PECO to collect funds from their customers, which are deposited in nuclear decommissioning trust funds maintained by Generation. These funds, together with earnings thereon, will be used to decommission such nuclear facilities. The ICC permitted ComEd to recover $73 million per year from retail customers for decommissioning for the years 2001 through 2004 and, depending upon the portion of the output of certain generating stations taken by ComEd, up to $73 million annually in 2005 and 2006. Because ComEd is not expected to take all of the output of these stations, actual collections are expected to be less than $73 million annually in 2005 and 2006. Subsequent to 2006, there will be no further recoveries of decommissioning costs from ComEd’s customers. PECO is currently recovering $33 million annually for nuclear decommissioning. Generation expects that these collections will continue through the operating license life of each of the former PECO units, with adjustments every five years to reflect changes in cost estimates and decommissioning trust fund performance. Decommissioning expenditures are expected to occur primarily after the plants are retired. Based on current licenses and anticipated renewals, decommissioning expenditures for plants in operation are currently estimated to begin in 2029. To fund future decommissioning costs, Generation held $5.3 billion of investments in trust funds, including net unrealized gains and losses, at December 31, 2004.
NRC regulations require that licensees of nuclear generating facilities demonstrate reasonable assurance that funds will be available in certain minimum amounts at the end of the life of the facility to decommission the facility. Generation is required to provide to the NRC a biennial report by unit (annually for Generation’s four retired units) addressing Generation’s ability to meet the NRC-estimated funding levels (NRC Funding Levels) with scheduled contributions to and earnings on the decommissioning trust funds. As of December 31, 2004, Generation’s 23 units met the NRC’s Funding Levels. Generation will submit its next biennial report to the NRC in March 2005.
In 2003, the General Accounting Office (GAO) published a study on the NRC’s need for more effective analyses to ensure the adequate accumulation of funds to decommission nuclear power plants in the United States. As it has in the past, the GAO concluded that accumulated and future proposed funding was inadequate to achieve NRC Funding Levels at a number of U.S. nuclear plants, including a number of Generation’s plants. Generation has reviewed the GAO’s report and believes that, in reaching its conclusions, the GAO did not consider all aspects of Generation’s decommissioning strategy, such as fund growth during the decommissioning period. The inclusion of estimated earnings growth on Generation’s nuclear trust funds during the decommissioning period virtually eliminates any funding shortfalls identified in the GAO report.
Generation currently believes that the amounts in nuclear decommissioning trust funds and future collections from ratepayers, together with earnings thereon, will provide adequate funding to
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decommission its nuclear facilities in accordance with regulatory requirements. Forecasting investment earnings and costs to decommission nuclear generating stations requires significant judgment, and actual results may differ significantly from current estimates. Ultimately, when decommissioning activities are initiated, if the investments held by Generation’s nuclear decommissioning trusts are not sufficient to fund the decommissioning of Generation’s nuclear plants, Generation may be required to identify other means of funding its decommissioning obligations.
Generation relies on the availability of electric transmission facilities that it does not own or control to deliver its wholesale electric power to the purchasers of the power.
Generation depends on transmission facilities owned and operated by other companies, including ComEd and PECO, to deliver the power that it sells at wholesale. If transmission at these facilities is disrupted or transmission capacity is inadequate, Generation may not be able to sell and deliver its wholesale power. While Generation was not significantly affected by the failure in the transmission grid that served a large portion of the Northeastern United States and Canada during the August 2003 blackout, the North American transmission grid is highly interconnected and, in extraordinary circumstances, disruptions at a point within the grid can cause a systemic response that results in an extensive power outage. If a region’s power transmission infrastructure is inadequate, Generation’s recovery of wholesale costs and profits may be limited. In addition, if restrictive transmission price regulation is imposed, the transmission companies may not have sufficient incentive to invest in expansion of transmission infrastructure.
The FERC has issued electric transmission initiatives that require electric transmission services to be offered unbundled from commodity sales. Although these initiatives are designed to encourage wholesale market transactions for electricity, access to transmission systems may in fact not be available if transmission capacity is insufficient because of physical constraints or because it is contractually unavailable. Generation also cannot predict whether transmission facilities will be expanded in specific markets to accommodate competitive access to those markets.
Generation is directly affected by price fluctuations and other risks of the wholesale power market.
Generation fulfills its energy commitments from the output of the generating facilities that it owns as well as through buying electricity in both the wholesale bilateral and spot markets. The excess or deficiency of energy owned or controlled by Generation compared to its obligations exposes Generation to the risks of rising and falling prices in those markets, and Generation’s cash flows may vary accordingly. Generation’s cash flows from generation that is not used to meet its commitments to ComEd and PECO are largely dependent on wholesale prices of electricity and Generation’s ability to successfully market energy, capacity and ancillary services. In the event that lower wholesale prices of electricity reduce Generation’s current or forecasted cash flows, the carrying value of Generation’s generating units may be determined to be impaired and Generation would be required to incur an impairment loss.
The wholesale spot market price of electricity for each hour is generally determined by the cost of supplying the next unit of electricity to the market during that hour. Many times, the next unit of electricity supplied would be supplied from generating stations fueled by fossil fuels, primarily natural gas. Consequently, the open-market wholesale price of electricity may reflect the cost of natural gas plus the cost to convert natural gas to electricity. Therefore, changes in the supply and cost of natural gas generally affect the open market wholesale price of electricity.
Credit Risk. In the bilateral markets, Generation is exposed to the risk that counterparties that owe Generation money or energy will not perform their obligations for operational or financial reasons.
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In the event the counterparties to these arrangements fail to perform, Generation might be forced to purchase or sell power in the wholesale markets at less favorable prices and incur additional losses, to the extent of amounts, if any, already paid to the counterparties. In the spot markets, Generation is exposed to the risks of whatever default mechanisms exist in that market, some of which attempt to spread the risk across all participants, which may or may not be an effective way of lessening the severity of the risk and the amounts at stake. Generation is also a party to agreements with entities in the energy sector that have experienced rating downgrades or other financial difficulties.
In order to evaluate the viability of Generation’s counterparties, Generation has implemented credit risk management procedures designed to mitigate the risks associated with these transactions. These policies include counterparty credit limits and, in some cases, require deposits or letters of credit to be posted by certain counterparties. Generation’s counterparty credit limits are based on a scoring model that considers a variety of factors, including leverage, liquidity, profitability, credit ratings and risk management capabilities. Generation has entered into payment netting agreements or enabling agreements that allow for netting of payables and receivables with the majority of its large counterparties. The credit department monitors current and forward credit exposure to counterparties and their affiliates, both on an individual and an aggregate basis.
The integration of the retail businesses of Exelon Energy subjects Generation to credit risk resulting from a new customer base.
Immature Markets. Certain wholesale spot markets are new and evolving markets that vary from region to region and are still developing practices and procedures. While the FERC has proposed initiatives to standardize wholesale spot markets, Generation cannot predict whether that effort will be successful, what form any of these markets will eventually take or what roles Generation will play in them. Problems in or the failure of any of these markets, as was experienced in California in 2000, could adversely affect Generation’s business.
Hedging. The Power Team buys and sells energy and other products in the wholesale markets and enters into financial contracts to manage risk and hedge various positions in Generation’s power generation portfolio. This activity, along with the effects of any specialized accounting for trading contracts, may cause volatility in Generation’s future results of operations.
Weather. Generation’s operations are affected by weather, which affects demand for electricity as well as operating conditions. Generation plans its business based upon normal weather assumptions. To the extent that weather is warmer in the summer or colder in the winter than assumed, Generation may require greater resources to meet its contractual requirements to ComEd and PECO. Extreme weather conditions or storms may affect the availability of generation capacity and transmission, limiting Generation’s ability to source or send power to where it is sold. These conditions, which may not have been fully anticipated, may have an adverse effect by causing Generation to seek additional capacity at a time when wholesale markets are tight or to seek to sell excess capacity at a time when those markets are weak. Generation incorporates contingencies into its planning for extreme weather conditions, including potentially reserving capacity to meet summer loads at levels representative of warmer-than-normal weather conditions.
Excess capacity. Energy prices are also affected by the amount of supply available in a region. In the markets where Generation sells power, there has been a significant increase in the number of new power plants commencing commercial operations in recent years. An excess supply situation can lead to conditions with reduced wholesale market prices.
Generation’s business is also affected by the restructuring of the energy industry.
Regional Transmission Organizations and Standard Market Platform. Generation is dependent on wholesale energy markets and open transmission access and rights by which
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Generation delivers power to its wholesale customers, including ComEd and PECO. Generation uses the wholesale regional energy markets to sell power that Generation does not need to satisfy its long-term contractual obligations, to meet long-term obligations not provided by its own resources and to take advantage of price opportunities.
Wholesale markets have only been implemented in certain areas of the country and each market has unique features which may create trading barriers among the markets. The FERC has proposed initiatives, including RTOs, to encourage the development of large regional, uniform markets and to eliminate trade barriers. The FERC’s effort to promote RTOs throughout the states has generated substantial opposition by some state regulators and other governmental bodies. In addition, efforts to develop a RTO have been abandoned in certain regions. Generation supports the development of RTOs and implementation of standard market protocols for these regions, and others, but cannot predict their success or whether they will lead to the development of the envisioned large, successful wholesale markets.
Approximately 79% of Generation’s generating resources, which include directly owned assets and capacity obtained through long-term contracts, are located in the region encompassed by PJM, following PJM’s expansion to the Midwest markets in 2004. The PJM market has been the most successful and liquid regional market. Generation’s future results of operations may be affected by the successful expansion of that market to the Midwest and the implementation of any market changes mandated by the FERC.
Provider of Last Resort. As discussed above, ComEd and PECO each have POLR obligations that they have effectively transferred to Generation through full-requirements contracts. Because the choice of electricity generation supplier lies with the customer, planning to meet these obligations has a higher level of uncertainty than that traditionally experienced due to weather and the economy. It is difficult for Generation to plan the energy demand of ComEd and PECO customers. The uncertainty regarding the amount of ComEd and PECO load for which Generation must prepare increases Generation’s costs and may limit its sales opportunities. A significant under-estimation of the electric-load requirements of ComEd and PECO could result in Generation not having enough power to cover its supply obligation, in which case Generation would be required to buy power from third parties or in the spot markets at prevailing market prices. Those prices may not be as favorable or as manageable as Generation’s long-term supply expenses and thus could increase Generation’s total costs.
As the demand for energy rises in the future, it may be necessary to increase capacity through the construction of new generating facilities. Both Illinois and Pennsylvania statutes contemplate that future generation will be built at the risk of market participants. Any construction of new generating facilities by Generation would be subject to market concentration tests administered by the FERC.
Effective management of capital projects is important to Generation’s business.
Generation’s business is capital intensive and requires significant investments in energy generation and in other internal infrastructure projects. The inability of Generation to effectively manage its capital projects could adversely affect Generation’s results of operations.
The interaction between the energy delivery and generation businesses provides Exelon a partial hedge of wholesale energy market prices.
The price of power purchased and sold in the open wholesale energy markets can vary significantly in response to market conditions. The amounts of power that Generation provides to ComEd and PECO vary from month to month; however, delivery requirements are generally highest in the summer when wholesale power prices are also generally highest. Therefore, energy committed by
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Generation to serve ComEd and PECO customers is not exposed to the price uncertainty of the open wholesale energy market. Generally, between 60% and 70% of Generation’s supply serves ComEd and PECO customers. Consequently, Generation has limited its earnings exposure from the volatility of the wholesale energy market to the energy generated in excess of the ComEd and PECO requirements, as well as any other contracted longer term obligations.
As its business continues to evolve, Generation is exploring other long-term contracts or arrangements, which arrangements could limit its earnings opportunity if market prices are significantly different than its expectations.
Generation’s financial performance depends on its ability to respond to competition in the energy industry.
As a result of industry restructuring, numerous generation companies created by the disaggregation of vertically integrated utilities have become active in the wholesale power generation business. In addition, independent power producers (IPP) have become prevalent in the wholesale power industry. In recent years, IPPs and the generation companies of disaggregated utilities have installed new generating capacity at a pace greater than the growth of electricity demand. These new generating facilities may be more efficient than Generation’s facilities. The introduction of new technologies could increase competition, which could lower prices and have an adverse effect on Generation’s results of operations or financial condition. Generation’s financial performance depends on its ability to respond to competition in the energy industry.
Power Team’s risk management policies cannot fully eliminate the risk associated with its power trading activities.
Power Team’s power trading (including fuel procurement and power marketing) activities expose Generation to risks of commodity price movements. Generation attempts to manage its exposure through enforcement of established risk limits and risk management procedures. These risk limits and risk management procedures may not always be followed or may not work as planned and cannot eliminate the risks associated with these activities. Even when its policies and procedures are followed, and decisions are made based on projections and estimates of future performance, results of operations may be diminished if the judgments and assumptions underlying those decisions prove to be wrong or inaccurate. Factors, such as future prices and demand for power and other energy-related commodities, become more difficult to predict and the calculations become less reliable the further into the future estimates are made. As a result, Generation cannot predict the impact that its power trading and risk management decisions may have on its business, operating results or financial position.
General Business
The Registrants may make acquisitions that do not achieve the intended financial results.
The Registrants may continue to pursue investments that fit their strategic objectives and improve their financial performance. On December 20, 2004, Exelon announced the execution of the Merger Agreement with PSEG. Exelon and PSEG entered into the Merger Agreement with the expectation that the Merger would result in various benefits, including, among other things, cost savings and operating efficiencies. Achieving the anticipated benefits of the Merger is subject to a number of uncertainties, including whether the businesses of Exelon and PSEG are integrated in an efficient and effective manner, as well as general competitive factors in the market place. Failure to achieve these anticipated benefits could result in increased costs, decreases in the amount of expected revenues generated by the combined company and diversion of management’s time and energy and could have an adverse effect on the combined company’s business, financial condition, operating results and prospects.
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Before the Merger may be completed, various approvals or consents must be obtained from FERC, the SEC, the NRC and various utility regulatory, antitrust and other authorities in the United States and in foreign jurisdictions. The governmental authorities from which these approvals are required may impose conditions on completion of the Merger or require changes to the terms of the Merger. These conditions or changes could have the effect of delaying completion of the Merger or imposing additional costs on or limiting the revenues of the combined company and or the individual registrants following the Merger, any of which might have a material adverse effect on the combined company or the individual registrants following completion of the Merger.
Additionally, the Merger Agreement contains certain termination rights for both Exelon and PSEG, and further provides that, upon termination of the Merger Agreement under specified circumstances, (1) Exelon may be required to pay PSEG a termination fee of $400 million plus PSEG’s transaction expenses up to $40 million and (2) PSEG may be required to pay Exelon a termination fee of $400 million plus Exelon’s transaction expenses up to $40 million.
Among the factors considered by the board of directors of Exelon in connection with its approvals of the Merger Agreement were the benefits as well as the risks that could result from the Merger. Exelon cannot give any assurance that these benefits will be realized within the time periods contemplated or even that they will be realized at all.
The Registrants’ results of operations may be affected by the divestiture of businesses and facilities.
The Registrants may decide to divest businesses or facilities that do not fit with their strategic objectives or improve their financial performance, such as the sale of Generation’s interest in Sithe and the divestiture or wind-down of the remaining businesses of Enterprises. The Registrants may be unable to successfully divest or wind down these businesses and facilities for a number of reasons, including an inability to locate appropriate buyers or to negotiate acceptable terms for transactions. In addition, the amount that the Registrants may realize from a divestiture of a business or a facility is subject to fluctuating market conditions that may contribute to pricing and other terms that may be materially different than expected and could result in losses on sales. The Registrants also face risks in managing these businesses prior to their divestitures due to potential turnover of key employees and operating the businesses through their transition. The Registrants may also incur costs related to the wind-down of businesses that will not be sold or unfavorable post-close purchase price adjustments related to divestitures.
Results of operations are affected by increasing costs.
Inflation affects the Registrants through increased operating costs and increased capital costs for plant and equipment. As a result of the rate freezes and caps under which the Energy Delivery business operates and price pressures due to competition, Energy Delivery may not be able to pass the costs of inflation through to its customers. In addition, the Registrants face rising medical benefit costs, which are increasing at a rate that greatly exceeds the rate of general inflation. If the Registrants are unable to successfully manage their medical benefit costs, their results of operations could be negatively affected.
Market performance affects decommissioning trust funds and benefit plan asset values.
The performance of the capital markets affects the values of the assets that are held in trust to satisfy future obligations under pension and postretirement benefit plans and to decommission Generation’s nuclear plants. The Registrants have significant obligations in these areas and hold significant assets in these trusts. A decline in the market value of those assets, as was experienced from 2000 to 2002, may increase the funding requirements of these obligations.
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Regulations imposed by the SEC under PUHCA affect business operations.
Exelon is subject to regulation by the SEC under PUHCA as a result of its ownership of ComEd and PECO. That regulation affects Exelon’s ability to:
| • | diversify, by generally restricting investments to traditional electric and gas utility businesses and related businesses; |
| • | invest in or operate SEC-approved, non-utility companies beyond authorized financial and operating thresholds; |
| • | issue securities, by requiring the prior approval of the SEC or, for ComEd and PECO, requiring the approval of state regulatory commissions; |
| • | engage in transactions among affiliates without the SEC’s prior approval and, then, only at cost, since the PUHCA regulates business between affiliates in a utility holding company system; |
| • | make dividend payments in specified situations; |
| • | make intercompany loans in specified companies; |
| • | restructure capitalization to the extent the equity ratio falls below 30%; and |
| • | operate with a “complex” corporate structure. |
The Registrants may incur substantial costs to fulfill their obligations related to environmental matters.
The businesses in which the Registrants operate are subject to extensive environmental regulation by local, state and Federal authorities. These laws and regulations affect the manner in which they conduct their operations and make capital expenditures. These regulations affect how the Registrants handle air and water emissions and solid waste disposal and are an important aspect of their operations. In addition, the Registrants are subject to liability under these laws for the costs of remediating environmental contamination of property now or formerly owned by the Registrants and of property contaminated by hazardous substances they generate. They believe that they have a responsible environmental management and compliance program; however, they have incurred and expect to incur significant costs related to environmental compliance, site remediation and clean-up. Remediation activities associated with manufactured gas plant operations conducted by predecessor companies will be one component of such costs. Also, they are currently involved in a number of proceedings relating to sites where hazardous substances have been deposited and may be subject to additional proceedings in the future.
As of December 31, 2004, Exelon, ComEd, PECO and Generation had reserves for environmental investigation and remediation costs of $124 million, $61 million, $47 million and $16 million, respectively, exclusive of decommissioning liabilities. The Registrants have accrued and will continue to accrue amounts that are believed prudent to cover these environmental liabilities, but the Registrants cannot predict with any certainty whether these amounts will be sufficient to cover their environmental liabilities. The Registrants cannot predict whether they will incur other significant liabilities for any additional investigation and remediation costs at additional sites not currently identified by them, environmental agencies or others, or whether such costs will be recoverable from third parties.
In July 2004, the EPA issued the final Phase II rule implementing Section 316(b) of the Clean Water Act. This rule establishes national requirements for reducing the adverse environmental impacts from the entrainment and impingement of aquatic organisms at existing power plants. The rule identifies particular standards of performance with respect to entrainment and impingement and requires each facility to monitor and validate this performance in future years. All of Exelon’s power generation facilities with cooling water systems are subject to the regulations. Facilities without closed-cycle recirculating systems are potentially most affected. Those facilities are Clinton, Cromby,
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Dresden, Eddystone, Fairless Hills, Handley, Mountain Creek, New Boston, Oyster Creek, Peach Bottom, Quad Cities, and Salem. Exelon is currently evaluating compliance options at its affected plants. At this time, Exelon cannot estimate the effect that compliance with the Phase II rule requirements will have on the operation of Generation’s generating facilities and its future results of operations, financial condition and cash flows. There are many factors to be considered and evaluated to determine the extent to which there will be financial and operational impacts. The considerations and evaluations include, but are not limited to obtaining clarifying interpretations of the requirements from state regulators, resolving outstanding litigation proceedings concerning the requirements, completing studies to establish biological baselines for each facility, and performing environmental and economic cost benefit evaluation of the potential compliance alternatives in accordance with the requirements.
In June 2001, the New Jersey Department of Environmental Protection (NJDEP) issued a renewed NPDES permit for Salem, expiring in July 2006, allowing for the continued operation of Salem with its existing cooling water system. An application for renewal of that permit, including a demonstration of compliance with the requirements of the recently published Federal Water Pollution Control Act Section 316(b) regulations, must be submitted to NJDEP by February 2, 2006 unless the NJDEP grants additional time to collect information to comply with the new regulations. NJDEP advised PSEG in a letter dated July 12, 2004 that it strongly recommends reducing cooling water intake flow commensurate with closed-cycle cooling as a compliance option for Salem. PSEG has not made a determination regarding how it will demonstrate compliance with the Section 316(b) regulations. If application of the Section 316(b) regulations requires the retrofitting of Salem’s cooling water intake structure to reduce cooling water intake flow commensurate with closed-cycle cooling, the retrofit and any resulting cost of interim replacement power could result in material costs of compliance to the owners of the facility.
For additional information regarding environmental matters, see “Environmental Regulation” in ITEM 1 of this Form 10-K.
The Registrants must actively manage the security of their people and facilities.
As a result of the events of September 11, 2001, the electric industry has developed additional security guidelines. The electric industry, through the North American Electric Reliability Council, developed physical security guidelines, which were accepted by the United States Department of Energy and which may become mandatory through regulation or legislation. The gas industry, through the American Gas Association, developed physical security guidelines that were accepted by the United States Department of Transportation.
Generation has also initiated security measures, including implementation of measures mandated by the NRC for the nuclear facilities, to safeguard its employees and critical operations and is actively participating in industry initiatives to identify methods to maintain the reliability of its energy production and delivery systems. These security measures have resulted in and are expected to continue to result in increased costs. On a continuing basis, Generation evaluates enhanced security measures at certain critical locations, enhanced response and recovery plans and assesses long-term design changes and redundancy measures. Additionally, the energy industry is working with governmental authorities to ensure that emergency plans are in place and critical infrastructure vulnerabilities are addressed in order to maintain the reliability of the country’s energy systems. These measures will involve additional expense to develop and implement.
Changes in the availability and cost of insurance mean that the Registrants have greater exposure to economic loss due to property damage and liability.
The Registrants carry property damage and liability insurance for their properties and operations. As a result of significant changes in the insurance marketplace, due in part to terrorist acts, the
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available coverage and limits may be less than the amount of insurance obtained in the past, the costs of obtaining such insurance may be higher and the recovery for losses due to terrorist acts may be limited. The Registrants are self-insured for deductibles and to the extent that any losses may exceed the amount of insurance maintained. A claim that exceeds the amounts available under their property damage and liability insurance, together with the deductible, would negatively affect their results of operations.
Taxation has a significant impact on results of operations.
Tax reserves and the recoverability of deferred tax assets. The Registrants are required to make judgments regarding the potential tax effects of various financial transactions and their ongoing operations to estimate their obligations to taxing authorities. These tax obligations include income, real estate, use and employment-related taxes and ongoing appeals related to these tax matters. These judgments include reserves for potential adverse outcomes regarding tax positions that have been taken. The Registrants must also assess their ability to generate capital gains in future periods to realize tax benefits associated with capital losses previously generated or expected to be generated in future periods. Capital losses may be deducted only to the extent of capital gains realized during the year of the loss or during the three prior or five succeeding years. The Registrants do not record valuation allowances for deferred tax assets related to capital losses that the Registrants believe will be realized in future periods. Generation has recorded valuation allowances against certain deferred assets associated with capital losses due to the consolidation of Sithe.
Increases in state income taxes. Due to the revenue needs of the states in which the Registrants operate, various state income tax and fee increases have been proposed or are being contemplated. The Registrants cannot predict whether legislation or regulation will be introduced, the form of any legislation or regulation, whether any such legislation or regulation will be passed by the state legislatures or regulatory bodies, or, if enacted, whether any such legislation or regulation would be effective retroactively or prospectively. If enacted, these changes could increase state income tax expense and could have a negative impact on the Registrants’ results of operations and cash flows.
Investments in synthetic fuel-producing facilities. Exelon has purchased interests in three synthetic fuel-producing facilities, which increased Exelon’s net income by $70 million in 2004. Tax credits generated by the production of synthetic fuel are subject to a phase-out provision that gradually reduces tax credits as the annual average wellhead price per barrel of domestic crude oil increases into an inflation-adjusted phase-out range. If domestic crude oil prices remain high in 2005, the tax credits and net income generated by the investments may be reduced substantially. In addition, Exelon has recorded an intangible asset related to its investments in these facilities with a net carrying value of $208 million at December 31, 2004 that could become impaired if domestic crude oil prices continue to increase in the future.
Exelon and its subsidiaries have guaranteed the performance of third parties that may result in substantial cost in the event of non-performance.
Exelon and its subsidiaries have issued certain guarantees of the performance of others, which obligate Exelon to perform in the event that the third parties do not perform. In the event of non-performance by the third parties to these guarantees, Exelon and its subsidiaries could incur substantial cost to fulfill their obligations under these guarantees. Such performance could have a material impact on the financial statements of Exelon and its subsidiaries. See Note 20 of Exelon’s Notes to Consolidated Financial Statements for additional information regarding guarantees.
New Accounting Pronouncements
See Note 1 of Exelon’s Notes to Consolidated Financial Statements for information regarding new accounting pronouncements.
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ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK— Exelon
Exelon, ComEd, PECO and Generation are exposed to market risks associated with credit and interest rates. Exelon and Generation are also exposed to market risks associated with commodity and equity prices. The inherent risk in market-sensitive instruments and positions is the potential loss arising from adverse changes in commodity prices, counterparty credit, interest rates and equity security prices. Exelon’s RMC sets forth risk management policies and objectives and establishes procedures for risk assessment, control and valuation, counterparty credit approval, and the monitoring and reporting of derivative activity and risk exposures. The RMC is chaired by the chief risk officer and includes the chief financial officer, general counsel, treasurer, vice president of corporate planning, vice president of strategy, vice president of audit services and officers from each of Exelon’s business units. The RMC reports to the Exelon Board of Directors on the scope of the derivative and risk management activities.
Commodity Price Risk (Exelon, ComEd and Generation)
Commodity price risk is associated with market price movements resulting from excess or insufficient generation, changes in fuel costs, market liquidity and other factors. Trading activities and non-trading marketing activities include the purchase and sale of electric capacity, energy and fossil fuels, including oil, gas, coal and emission allowances. The availability and prices of energy and energy-related commodities are subject to fluctuations due to factors such as weather, governmental environmental policies, changes in supply and demand, state and Federal regulatory policies and other events. Additionally, ComEd has exposure to commodity price risk in relation to CTC revenues collected from its customers.
Generation
Normal Operations and Hedging Activities. Electricity available from Generation’s owned or contracted generation supply in excess of Generation’s obligations to customers, including Energy Delivery’s retail load, is sold into the wholesale markets. To reduce price risk caused by market fluctuations, Generation enters into physical contracts as well as derivative contracts, including forwards, futures, swaps, and options, with approved counterparties to hedge anticipated exposures. The maximum length of time over which cash flows related to energy commodities are currently being cash-flow hedged is three years. Generation has an estimated 90% hedge ratio in 2005 for its energy marketing portfolio. This hedge ratio represents the percentage of its forecasted aggregate annual economic generation supply that is committed to firm sales, including sales to Energy Delivery’s retail load. Energy Delivery’s retail load assumptions are based on forecasted average demand. The hedge ratio is not fixed and will vary from time to time depending upon market conditions, demand, energy market option volatility and actual loads. During peak periods Generation’s amount hedged declines to meet its commitment to Energy Delivery. Market price risk exposure is the risk of a change in the value of unhedged positions. Absent any efforts to mitigate market price exposure, the estimated market price exposure for Generation’s non-trading portfolio associated with a ten percent reduction in the annual average around-the-clock market price of electricity is approximately a $32 million decrease in net income. This sensitivity assumes a 90% hedge ratio and that price changes occur evenly throughout the year and across all markets. The sensitivity also assumes a static portfolio. Generation expects to actively manage its portfolio to mitigate market price exposure. Actual results could differ depending on the specific timing of, and markets affected by, price changes, as well as future changes in Generation’s portfolio.
Proprietary Trading Activities. Generation began to use financial contracts for proprietary trading purposes in the second quarter of 2001. Proprietary trading includes all contracts entered into
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purely to profit from market price changes as opposed to hedging an exposure. These activities are accounted for on a mark-to-market basis. The proprietary trading activities are a complement to Generation’s energy marketing portfolio but represent a very small portion of Generation’s overall energy marketing activities. For example, the limit on open positions in electricity for any forward month represents less than one percent of Generation’s owned and contracted supply of electricity. Generation expects this level of proprietary trading activity to continue in the future. Trading portfolio activity for the year ended December 31, 2004 resulted in an immaterial impact on earnings that included a $3 million (before income taxes) unrealized mark-to-market gain. The daily Value-at-Risk (VaR) on proprietary trading activity averaged $100,000 of exposure over the last 18 months. Because of the relative size of the proprietary trading portfolio in comparison to Generation’s total gross margin of $3,768 million, Generation has not segregated proprietary trading activity in the following tables. The trading portfolio is subject to a risk management policy that includes stringent risk management limits, including volume, stop-loss and value-at-risk limits to manage exposure to market risk. Additionally, the Exelon risk management group and Exelon’s RMC monitor the financial risks of the power marketing activities.
Generation’s energy contracts are accounted for under SFAS No. 133. Most non-trading contracts qualify for the normal purchases and normal sales exemption to SFAS No. 133 discussed in Critical Accounting Policies and Estimates. Those that do not are recorded as assets or liabilities on the balance sheet at fair value. Changes in the fair value of qualifying hedge contracts are recorded in other comprehensive income (OCI) and gains and losses are recognized in earnings when the underlying transaction occurs. Changes in the fair value of derivative contracts that do not meet hedge criteria under SFAS No. 133 and the ineffective portion of hedge contracts are recognized in current earnings. Changes in the derivatives recorded at fair value are recognized in earnings unless specific hedge accounting criteria are met, in which case those changes are recorded in earnings as an offset to the changes in fair value of the exposure being hedged or deferred in accumulated OCI and recognized in earnings as the hedged transactions occur.
The following detailed presentation of Generation’s trading and non-trading marketing activities at Generation is included to address the recommended disclosures by the energy industry’s Committee of Chief Risk Officers (CCRO).
The following table provides detail on changes in Generation’s mark-to-market net asset or liability balance sheet position from January 1, 2003 to December 31, 2004. It indicates the drivers behind changes in the balance sheet amounts. This table incorporates the mark-to-market activities that are immediately recorded in earnings, as shown in the previous table, as well as the settlements from OCI to earnings and changes in fair value for the hedging activities that are recorded in accumulated OCI on the Consolidated Balance Sheets.
| Total |
||||
| Total mark-to-market energy contract net liabilities at January 1, 2003 |
$ | (163 | ) | |
| Total change in fair value during 2003 of contracts recorded in earnings |
206 | |||
| Reclassification to realized at settlement of contracts recorded in earnings |
(227 | ) | ||
| Reclassification to realized at settlement from OCI |
273 | |||
| Effective portion of changes in fair value—recorded in OCI |
(305 | ) | ||
| Total mark-to-market energy contract net liabilities at December 31, 2003 |
(216 | ) | ||
| Total change in fair value during 2004 of contracts recorded in earnings |
158 | |||
| Reclassification to realized at settlement of contracts recorded in earnings |
(197 | ) | ||
| Reclassification to realized at settlement from OCI |
475 | |||
| Effective portion of changes in fair value—recorded in OCI |
(512 | ) | ||
| Purchase/sale/disposal of existing contracts or portfolios subject to mark-to-market |
147 | |||
| Total mark-to-market energy contract net liabilities at December 31, 2004 |
$ | (145 | ) | |
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The following table details the balance sheet classification of the mark-to-market energy contract net assets (liabilities) recorded as of December 31, 2004 and 2003:
| December 31, |
||||||||
| 2004 |
2003 |
|||||||
| Current assets |
$ | 403 | $ | 322 | ||||
| Noncurrent assets |
373 | 100 | ||||||
| Total mark-to-market energy contract assets |
776 | 422 | ||||||
| Current liabilities (a) |
(598 | ) | (505 | ) | ||||
| Noncurrent liabilities |
(323 | ) | (133 | ) | ||||
| Total mark-to-market energy contract liabilities |
(921 | ) | (638 | ) | ||||
| Total mark-to-market energy contract net liabilities |
$ | (145 | ) | $ | (216 | ) | ||
| (a) | Mark-to-market energy contract liabilities at December 31, 2003 do not reflect a $76 million interest-rate swap that was included in current mark-to-market derivative liabilities within Generation’s Consolidated Balance Sheet. |
The majority of Generation’s contracts are non-exchange-traded contracts valued using prices provided by external sources, primarily price quotations available through brokers or over-the-counter, on-line exchanges. Prices reflect the average of the bid-ask mid-point prices obtained from all sources that Generation believes provide the most liquid market for the commodity. The terms for which such price information is available varies by commodity, region and product. The remainder of the assets represents contracts for which external valuations are not available, primarily option contracts. These contracts are valued using the Black model, an industry standard option valuation model. The fair values in each category reflect the level of forward prices and volatility factors as of December 31, 2004 and may change as a result of changes in these factors. Management uses its best estimates to determine the fair value of commodity and derivative contracts it holds and sells. These estimates consider various factors including closing exchange and over-the-counter price quotations, time value, volatility factors and credit exposure. It is possible, however, that future market prices could vary from those used in recording assets and liabilities from energy marketing and trading activities and such variations could be material.
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The following table, which presents maturity and source of fair value of mark-to-market energy contract net liabilities, provides two fundamental pieces of information. First, the table provides the source of fair value used in determining the carrying amount of Generation’s total mark-to-market asset or liability. Second, this table provides the maturity, by year, of Generation’s net assets/liabilities, giving an indication of when these mark-to-market amounts will settle and either generate or require cash.
| Maturities within |
|||||||||||||||||||||||||
| (in millions) |
2005 |
2006 |
2007 |
2008 |
2009 |
2010 and Beyond |
Total Fair Value |
||||||||||||||||||
| Normal Operations, qualifying cash-flow hedge contracts (a): |
|||||||||||||||||||||||||
| Actively quoted prices |
$ | (4 | ) | $ | 1 | $ | — | $ | — | $ | — | $ | — | $ | (3 | ) | |||||||||
| Prices provided by other external sources |
(190 | ) | (27 | ) | (4 | ) | — | — | — | (221 | ) | ||||||||||||||
| Total |
$ | (194 | ) | $ | (26 | ) | $ | (4 | ) | $ | — | $ | — | $ | — | $ | (224 | ) | |||||||
| Normal Operations, other derivative contracts (b): |
|||||||||||||||||||||||||
| Actively quoted prices |
$ | 11 | $ | (2 | ) | $ | — | $ | — | $ | — | $ | — | $ | 9 | ||||||||||
| Prices provided by other external sources |
(23 | ) | 6 | 1 | — | — | — | (16 | ) | ||||||||||||||||
| Prices based on model or other valuation methods |
7 | 11 | 8 | 11 | 11 | 38 | 86 | ||||||||||||||||||
| Total |
$ | (5 | ) | $ | 15 | $ | 9 | $ | 11 | $ | 11 | $ | 38 | $ | 79 | ||||||||||
| (a) | Mark-to-market gains and losses on contracts that qualify as cash-flow hedges are recorded in other comprehensive income. |
| (b) | Mark-to-market gains and losses on other non-trading and trading derivative contracts that do not qualify as cash-flow hedges are recorded in earnings. |
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The table below provides details of effective cash-flow hedges under SFAS No. 133 included in the balance sheet as of December 31, 2004. The data in the table gives an indication of the magnitude of SFAS No. 133 hedges Generation has in place; however, since under SFAS No. 133 not all hedges are recorded in OCI, the table does not provide an all-encompassing picture of Generation’s hedges. The table also includes a roll-forward of accumulated OCI related to cash-flow hedges for the years ended December 31, 2004 and December 31, 2003, providing insight into the drivers of the changes (new hedges entered into during the period and changes in the value of existing hedges). Information related to energy merchant activities is presented separately from interest-rate hedging activities.
| Total Cash-Flow Hedge OCI Activity, Net of Income Tax |
||||||||||||
| (in millions) |
Power Team Normal Operations and Hedging Activities |
Interest-Rate and Other Hedges |
Total-Cash Flow Hedges |
|||||||||
| Accumulated OCI, January 1, 2003 |
$ | (114 | ) | $ | (14 | ) | $ | (128 | ) | |||
| Changes in fair value |
(186 | ) | (2 | ) | (188 | ) | ||||||
| Reclassifications from OCI to net loss |
167 | — | 167 | |||||||||
| Accumulated OCI derivative loss at December 31, 2003 |
(133 | ) | (16 | ) | (149 | ) | ||||||
| Changes in fair value |
(312 | ) | 17 | (295 | ) | |||||||
| Disposal of existing Boston Generating contracts |
16 | — | 16 | |||||||||
| Reclassifications from OCI to net income |
290 | — | 290 | |||||||||
| Exelon Energy Company opening balance |
2 | — | 2 | |||||||||
| Sithe Energies, Inc. opening balance |
— | (10 | ) | (10 | ) | |||||||
| Accumulated OCI derivative loss at December 31, 2004 |
$ | (137 | ) | $ | (9 | ) | $ | (146 | ) | |||
ComEd
ComEd has exposure to commodity price risk in relation to revenue collected from customers who elect to purchase energy from an alternative electric supplier or the ComEd PPO. Revenues collected from customers electing the PPO include commodity charges at market-based prices and CTC revenues which are calculated to provide the customer with a credit for the market price for electricity. Because the change in revenues from customers electing the PPO is significantly offset by the change in CTC revenues, ComEd does not believe that its exposure to such a market price decrease would be material.
ComEd’s CTC revenues are also collected from customers who elect to purchase energy from an alternative electric supplier. ComEd’s CTC rates are reset once a year in the spring, and customers can elect to lock in their CTC rates for a one or multiple year terms. Based on the current customers who have elected the one-year CTC rates, ComEd has performed a sensitivity analysis to determine the net impact of a 10% increase in the average market price of electricity from June 2005 through December 2005 which would result in a $5 million decrease in CTC revenues in 2005. A 10% decrease from June 2005 through December 2005 in market prices would result in a $5 million increase in CTC revenues in 2005. The result may be significantly affected if additional customers elect to purchase energy from an alternative electric supplier or if customers elect to purchase their energy from ComEd.
Credit Risk (Exelon, ComEd, PECO and Generation)
ComEd and PECO
Credit risk for Energy Delivery is managed by the credit and collection policies of ComEd and PECO, which are consistent with state regulatory requirements. ComEd and PECO are each currently
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obligated to provide service to all electric customers within their respective franchised territories. For the year ended December 31, 2004, ComEd’s ten largest customers represented approximately 2% of its retail electric revenues and PECO’s ten largest customers represented approximately 7% of its retail electric and gas revenues. ComEd and PECO record a provision for uncollectible accounts, based upon historical experience and third-party studies, to provide for the potential loss from nonpayment by these customers.
Under the Competition Act, licensed entities, including alternative electric suppliers, may act as agents to provide a single bill and provide associated billing and collection services to retail customers located in PECO’s retail electric service territory. Currently, there are no third parties providing billing of PECO’s charges to customers or advanced metering; however, if this occurs, PECO would be subject to credit risk related to the ability of the third parties to collect such receivables from the customers.
Generation
Generation has credit risk associated with counterparty performance on energy contracts which includes, but is not limited to, the risk of financial default or slow payment. Generation manages counterparty credit risk through established policies, including counterparty credit limits, and in some cases, requiring deposits and letters of credit to be posted by certain counterparties. Generation’s counterparty credit limits are based on a scoring model that considers a variety of factors, including leverage, liquidity, profitability, credit ratings and risk management capabilities. Generation has entered into payment netting agreements or enabling agreements that allow for payment netting with the majority of its large counterparties, which reduce Generation’s exposure to counterparty risk by providing for the offset of amounts payable to the counterparty against amounts receivable from the counterparty. The credit department monitors current and forward credit exposure to counterparties and their affiliates, both on an individual and an aggregate basis.
The following tables provide information on Generation’s credit exposure, net of collateral, as of December 31, 2004 and 2003. They further delineate that exposure by the credit rating of the counterparties and provide guidance on the concentration of credit risk to individual counterparties and an indication of the maturity of a company’s credit risk by credit rating of the counterparties. The figures in the tables below do not include sales to Generation’s affiliates or exposure through ISOs which are discussed below.
| Rating as of December 31, 2004 (a) |
Total Exposure Before Credit Collateral |
Credit Collateral |
Net Exposure |
Number Of Counterparties Greater than 10% of Net Exposure |
Net Exposure Of Counterparties Greater than 10% of Net Exposure | |||||||||
| Investment grade |
$ | 151 | $ | 33 | $ | 118 | — | $ | — | |||||
| Non-investment grade |
98 | 20 | 78 | 1 | 63 | |||||||||
| No external ratings |
||||||||||||||
| Internally rated—investment grade |
13 | — | 13 | — | — | |||||||||
| Internally rated—non-investment grade |
3 | — | 3 | — | — | |||||||||
| Total |
$ | 265 | $ | 53 | $ | 212 | 1 | $ | 63 | |||||
| (a) | This table does not include accounts receivable exposure. |
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| Rating as of December 31, 2003 (a) |
Total Exposure Before Credit Collateral |
Credit Collateral |
Net Exposure |
Number Of Counterparties Greater than 10% of Net Exposure |
Net Exposure Of Counterparties Greater than 10% of Net Exposure | |||||||||
| Investment grade |
$ | 116 | $ | — | $ | 116 | 1 | $ | 20 | |||||
| Non-investment grade |
22 | 7 | 15 | — | — | |||||||||
| No external ratings |
||||||||||||||
| Internally rated—investment grade |
13 | — | 13 | — | — | |||||||||
| Internally rated—non-investment grade |
1 | — | 1 | — | — | |||||||||
| Total |
$ | 152 | $ | 7 | $ | 145 | 1 | $ | 20 | |||||
| (a) | This table does not include accounts receivable exposure and forward credit exposure related to Exelon Energy. |
| Maturity of Credit Risk Exposure | ||||||||||||
| Rating as of December 31, 2004 (a) |
Less than 2 Years |
2-5 Years |
Exposure Greater than 5 Years |
Total Exposure Before Credit Collateral | ||||||||
| Investment grade |
$ | 149 | $ | 2 | $ | — | $ | 151 | ||||
| Non-investment grade |
91 | 7 | — | 98 | ||||||||
| No external ratings |
||||||||||||
| Internally rated—investment grade |
13 | — | — | 13 | ||||||||
| Internally rated—non-investment grade |
3 | — | — | 3 | ||||||||
| Total |
$ | 256 | $ | 9 | $ | — | $ | 265 | ||||
| (a) | This table does not include accounts receivable exposure. |
Dynegy. As previously disclosed, at December 31, 2004, Generation was counterparty to Dynegy in various energy transactions and had financial and credit risk associated with Dynegy through Generation’s investment in Sithe. On January 31, 2005, Generation sold its investment in Sithe and, accordingly, is no longer subject to potential credit risk associated with Dynegy’s performance under the financial swap arrangement that Dynegy had with Sithe. See Note 25 of Exelon’s Notes to Consolidated Financial Statements for further discussion of Generation’s sale of Sithe.
Generation previously disclosed the future economic value of AmerGen’s purchased power arrangement with Illinois Power Company (Illinois Power), a subsidiary of Dynegy, could be affected by events related to Dynegy’s financial condition. On September 30, 2004, Dynegy sold Illinois Power to a third party with an investment grade rating, which eliminated Generation’s credit risk associated with Illinois Power and Dynegy.
Collateral. As part of the normal course of business, Generation routinely enters into physical or financially settled contracts for the purchase and sale of capacity, energy, fuels and emissions allowances. These contracts either contain express provisions or otherwise permit Generation and its counterparties to demand adequate assurance of future performance when there are reasonable grounds for doing so. In accordance with the contracts and applicable law, if Generation is downgraded by a credit rating agency, especially if such downgrade is to a level below investment grade, it is possible that a counterparty would attempt to rely on such a downgrade as a basis for making a demand for adequate assurance of future performance. Depending on Generation’s net position with a counterparty, the demand could be for the posting of collateral. In the absence of expressly agreed to provisions that specify the collateral that must be provided, the obligation to supply the collateral requested will be a function of the facts and circumstances of the situation at the time of the demand. If Generation can reasonably claim that it is willing and financially able to perform its obligations, it may
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be possible to successfully argue that no collateral should be posted or that only an amount equal to two or three months of future payments should be sufficient.
ISOs. Generation participates in the following established, real-time energy markets, which are administered by ISOs: PJM, ISO New England, New York ISO, California ISO, MISO, Southwest Power Pool, Inc. and the Electric Reliability Council of Texas. In these areas, power is traded through bilateral agreements between buyers and sellers and on the spot markets that are operated by the ISOs. In areas where there is no spot market, electricity is purchased and sold solely through bilateral agreements. For sales into the spot markets administered by the ISOs, the ISO maintains financial assurance policies that are established and enforced by those administrators. The credit policies of the ISOs may under certain circumstances require that losses arising from the default of one member on spot market transactions be shared by the remaining participants. Non-performance or non-payment by a major counterparty could result in a material adverse impact on Generation’s financial condition, results of operations or net cash flows.
Exelon
Exelon’s consolidated balance sheet included a $486 million net investment in direct financing leases as of December 31, 2004. The investment in direct financing leases represents future minimum lease payments due at the end of the thirty-year lives of the leases of $1,492 million, less unearned income of $1,006 million. The future minimum lease payments are supported by collateral and credit enhancement measures including letters of credit, surety bonds and credit swaps issued by high credit quality financial institutions. Management regularly evaluates the credit worthiness of Exelon’s counterparties to these direct financing leases.
Interest-Rate Risk (Exelon, ComEd, PECO and Generation)
Variable Rate Debt. The Registrants use a combination of fixed-rate and variable-rate debt to reduce interest-rate exposure. The Registrants also use interest-rate swaps when deemed appropriate to adjust exposure based upon market conditions. Additionally, the Registrants use forward-starting interest-rate swaps and treasury rate locks to lock in interest-rate levels in anticipation of future financings. These strategies are employed to achieve a lower cost of capital. As of December 31, 2004, a hypothetical 10% increase in the interest rates associated with variable-rate debt would result in a $2 million decrease in Exelon’s pre-tax earnings. A hypothetical 10% increase in the interest rates associated with variable-rate debt would result in a decrease in pre-tax earnings of less than $1 million at ComEd, PECO and Generation.
Cash-Flow Hedges. In September and October 2004, Exelon entered into forward-starting interest-rate swaps in the aggregate notional amount of $240 million to lock in interest-rate levels in anticipation of future financings. At the time of the swap trades, the debt issuance that these swaps were hedging was considered probable; therefore, Exelon accounted for these interest-rate swap transactions as cash-flow hedges. In December 2004, it became apparent that the timing of the debt issuance would be deferred until 2005 and, consequently, Exelon unwound the $240 million forward-starting interest-rate swaps. Exelon recognized an ineffectiveness gain of less than $1 million pursuant to SFAS No. 133. Additionally, Exelon paid approximately $4 million to the counterparties due to the swap unwind. The net loss resulting from the amount paid to the counterparties less the ineffectiveness gain will be amortized over the life of the new debt issuance.
Based upon a revised date of expected debt issuance, Exelon entered into a new series of forward-starting interest-rate swaps in the aggregate notional amount of $200 million. At December 31, 2004, these interest-rate swaps, designated as cash-flow hedges, had an aggregate fair market value of $2 million based on the present value difference between the contract and market rates at
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December 31, 2004. If these derivative instruments had been terminated at December 31, 2004, this estimated fair value represents the amount that would be paid by the counterparties to Exelon.
The aggregate fair value of the interest-rate swaps designated as cash-flow hedges that would have resulted from a hypothetical 50 basis point decrease in the spot yield at December 31, 2004 is estimated to be $6 million in the counterparties’ favor. If these derivative instruments had been terminated at December 31, 2004, this estimated fair value represents the amount Exelon would pay the counterparties.
The aggregate fair value of the interest-rate swaps designated as cash-flow hedges that would have resulted from a hypothetical 50 basis point increase in the spot yield at December 31, 2004 is estimated to be $10 million in Exelon’s favor. If these derivative instruments had been terminated at December 31, 2004, this estimated fair value represents the amount the counterparties would pay Exelon.
In 2004, PECO entered into a forward-starting interest-rate swap in the aggregate notional amount of $75 million to lock in interest-rate levels in anticipation of a future financing. The debt issuance that this swap was hedging was considered probable; therefore, PECO accounted for this interest-rate swap transaction as a hedge. PECO settled this swap designated as a cash flow hedge for net proceeds of approximately $5 million. The proceeds were recorded in other comprehensive income and are being amortized over the life of the debt issuance.
At December 31, 2004, ComEd, PECO and Generation did not have any interest-rate swaps designated as cash-flow hedges.
Fair-Value Hedges. In 2004, ComEd entered into fixed-to-floating interest-rate swaps in order to maintain its targeted percentage of variable-rate debt associated with fixed-rate debt issuances in the aggregate amount of $240 million. At December 31, 2004, these interest-rate swaps, designated as fair-value hedges, had an aggregate fair market value of $9 million based on the present value difference between the contract and market rates at December 31, 2004. If these derivative instruments had been terminated at December 31, 2004, this estimated fair value represents the amount that would be paid by the counterparties to ComEd.
The aggregate fair value of the interest-rate swaps designated as fair-value hedges that would have resulted from a hypothetical 50 basis point decrease in the spot yield at December 31, 2004 is estimated to be $16 million in ComEd’s favor. If these derivative instruments had been terminated at December 31, 2004, this estimated fair value represents the amount the counterparties would pay ComEd.
The aggregate fair value of the interest-rate swaps designated as fair-value hedges that would have resulted from a hypothetical 50 basis point increase in the spot yield at December 31, 2004 is estimated to be $1 million in ComEd’s favor. If these derivative instruments had been terminated at December 31, 2004, this estimated fair value represents the amount the counterparties would pay ComEd.
In 2004, ComEd settled certain interest-rate swaps designated as fair-value hedges in the aggregate amount of $485 million for total proceeds of approximately $32 million, which included a $26 million settlement amount and $6 million of accrued interest. The $26 million settlement amount will be amortized as a reduction to interest expense over the remaining life of the related debt.
Equity Price Risk (Exelon and Generation)
Generation maintains trust funds, as required by the NRC, to fund certain costs of decommissioning Generation’s nuclear plants. As of December 31, 2004, Generation’s
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decommissioning trust funds are reflected at fair value on its Consolidated Balance Sheets. The mix of securities in the trust funds is designed to provide returns to be used to fund decommissioning and to compensate Generation for inflationary increases in decommissioning costs; however, the equity securities in the trust funds are exposed to price fluctuations in equity markets, and the value of fixed-rate, fixed-income securities are exposed to changes in interest rates. Generation actively monitors the investment performance of the trust funds and periodically reviews asset allocation in accordance with Generation’s nuclear decommissioning trust fund investment policy. A hypothetical 10% increase in interest rates and decrease in equity prices would result in a $329 million reduction in the fair value of the trust assets. See Defined Benefit Pension and Other Postretirement Welfare Benefits in the Critical Accounting Estimates section for information regarding the pension and other postretirement benefit trust assets.
130
| ITEM 8. | FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA |
Management’s Report on Internal Control Over Financial Reporting
The management of Exelon Corporation (Exelon) is responsible for establishing and maintaining adequate internal control over financial reporting. Exelon’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with accounting principles generally accepted in the United States of America.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
Exelon’s management conducted an assessment of the effectiveness of Exelon’s internal control over financial reporting as of December 31, 2004. In making this assessment, management used the criteria in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this assessment, Exelon’s management concluded that, as of December 31, 2004, Exelon’s internal control over financial reporting was effective.
February 22, 2005
Management’s assessment of the effectiveness of Exelon’s internal control over financial reporting as of December 31, 2004 has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report which appears on page 132 of this Annual Report on Form 10-K.
131
Report of Independent Registered Public Accounting Firm
To the Shareholders and Board of Directors of Exelon Corporation:
We have completed an integrated audit of Exelon Corporation’s 2004 consolidated financial statements and of its internal control over financial reporting as of December 31, 2004 and audits of its 2003 and 2002 consolidated financial statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Our opinions, based on our audits, are presented below.
Consolidated financial statements and financial statement schedule
In our opinion, the consolidated financial statements listed in the index appearing under Item 15(a)(1)(i) present fairly, in all material respects, the financial position of Exelon Corporation and its subsidiaries at December 31, 2004 and 2003, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2004 in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedule listed in the index appearing under Item 15(a)(1)(ii) presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements. These financial statements and the financial statement schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements and the financial statement schedule based on our audits. We conducted our audits of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit of financial statements includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
As discussed in Note 1 to the consolidated financial statements, Exelon Corporation changed its method of accounting for goodwill as of January 1, 2002; its method of accounting for asset retirement obligations as of January 1, 2003; and its method of accounting for variable interest entities in 2003 and 2004.
Internal control over financial reporting
Also, in our opinion, management’s assessment, included in Management’s Report on Internal Control Over Financial Reporting appearing under Item 8, that the Company maintained effective internal control over financial reporting as of December 31, 2004 based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), is fairly stated, in all material respects, based on those criteria. Furthermore, in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2004, based on criteria established in Internal Control—Integrated Framework issued by the COSO. The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express opinions on management’s assessment and on the effectiveness of the Company’s internal control over financial reporting based on our audit. We conducted our audit of internal control over financial reporting in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. An audit of internal
132
control over financial reporting includes obtaining an understanding of internal control over financial reporting, evaluating management’s assessment, testing and evaluating the design and operating effectiveness of internal control, and performing such other procedures as we consider necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinions.
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
PricewaterhouseCoopers LLP
Chicago, Illinois
February 22, 2005
133
Exelon Corporation and Subsidiary Companies
Consolidated Statements of Income
| For the Years Ended December 31, |
||||||||||||
| (in millions, except per share data) |
2004 |
2003 |
2002 |
|||||||||
| Operating revenues |
$ | 14,515 | $ | 15,812 | $ | 14,955 | ||||||
| Operating expenses |
||||||||||||
| Purchased power |
2,727 | 3,459 | 3,262 | |||||||||
| Purchased power from AmerGen Energy Company, LLC |
— | 382 | 273 | |||||||||
| Fuel |
2,355 | 2,534 | 1,727 | |||||||||
| Impairment of Boston Generating, LLC long-lived assets |
— | 945 | — | |||||||||
| Operating and maintenance |
3,976 | 4,508 | 4,345 | |||||||||
| Depreciation and amortization |
1,305 | 1,126 | 1,340 | |||||||||
| Taxes other than income |
719 | 581 | 709 | |||||||||
| Total operating expenses |
11,082 | 13,535 | 11,656 | |||||||||
| Operating income |
3,433 | 2,277 | 3,299 | |||||||||
| Other income and deductions |
||||||||||||
| Interest expense |
(548 | ) | (869 | ) | (964 | ) | ||||||
| Interest expense to affiliates |
(357 | ) | (12 | ) | (2 | ) | ||||||
| Distributions on preferred securities of subsidiaries |
(3 | ) | (39 | ) | (45 | ) | ||||||
| Equity in earnings (losses) of unconsolidated affiliates |
(153 | ) | 33 | 80 | ||||||||
| Other, net |
140 | (261 | ) | 304 | ||||||||
| Total other income and deductions |
(921 | ) | (1,148 | ) | (627 | ) | ||||||
| Income before income taxes, minority interest and cumulative effect of changes in accounting principles |
2,512 | 1,129 | 2,672 | |||||||||
| Income taxes |
692 | 331 | 998 | |||||||||
| Income before minority interest and cumulative effect of changes in accounting principles |
1,820 | 798 | 1,674 | |||||||||
| Minority interest |
21 | (5 | ) | (4 | ) | |||||||
| Income before cumulative effect of changes in accounting principles |
1,841 | 793 | 1,670 | |||||||||
| Cumulative effect of changes in accounting principles (net of income taxes of $17, $69 and $(90) in 2004, 2003 and 2002, respectively) |
23 | 112 | (230 | ) | ||||||||
| Net income |
$ | 1,864 | $ | 905 | $ | 1,440 | ||||||
| Average shares of common stock outstanding |
||||||||||||
| Basic |
661 | 651 | 645 | |||||||||
| Diluted |
669 | 657 | 649 | |||||||||
| Earnings per average common share—basic: |
||||||||||||
| Income from continuing operations before cumulative effect of changes in accounting principles |
$ | 2.79 | $ | 1.22 | $ | 2.59 | ||||||
| Cumulative effect of changes in accounting principles |
0.03 | 0.17 | (0.36 | ) | ||||||||
| Net income |
$ | 2.82 | $ | 1.39 | $ | 2.23 | ||||||
| Earnings per average common share—diluted: |
||||||||||||
| Income from continuing operations before cumulative effect of changes in accounting principles |
$ | 2.75 | $ | 1.21 | $ | 2.57 | ||||||
| Cumulative effect of changes in accounting principles |
0.03 | 0.17 | (0.35 | ) | ||||||||
| Net income |
$ | 2.78 | $ | 1.38 | $ | 2.22 | ||||||
| Dividends per common share |
$ | 1.26 | $ | 0.96 | $ | 0.88 | ||||||
See Notes to Consolidated Financial Statements
134
Exelon Corporation and Subsidiary Companies
Consolidated Statements of Cash Flows
| For the Years Ended December 31, |
||||||||||||
| (in millions) |
2004 |
2003 |
2002 |
|||||||||
| Cash flows from operating activities |
||||||||||||
| Net income |
$ | 1,864 | $ | 905 | $ | 1,440 | ||||||
| Adjustments to reconcile net income to net cash flows provided by operating activities: |
||||||||||||
| Depreciation, amortization and accretion, including nuclear fuel |
1,933 | 1,681 | 1,701 | |||||||||
| Other decommissioning-related activities |
169 | 37 | — | |||||||||
| Cumulative effect of changes in accounting principles (net of income taxes) |
(23 | ) | (112 | ) | 230 | |||||||
| Impairment of investments |
10 | 309 | 41 | |||||||||
| Impairment of goodwill and other long-lived assets |
1 | 990 | — | |||||||||
| Deferred income taxes and amortization of investment tax credits |
202 | (36 | ) | 278 | ||||||||
| Provision for uncollectible accounts |
87 | 94 | 129 | |||||||||
| Equity in (earnings) losses of unconsolidated affiliates |
153 | (33 | ) | (80 | ) | |||||||
| (Gains) losses on sales of investments and wholly owned subsidiaries |
(162 | ) | 25 | (199 | ) | |||||||
| Net realized (gains) losses on nuclear decommissioning trust funds |
(72 | ) | 16 | 32 | ||||||||
| Other non-cash operating activities |
(24 | ) | 18 | 101 | ||||||||
| Changes in assets and liabilities |
||||||||||||
| Accounts receivables |
(123 | ) | 102 | (357 | ) | |||||||
| Inventories |
(60 | ) | (54 | ) | (37 | ) | ||||||
| Other current assets |
79 | (68 | ) | 45 | ||||||||
| Accounts payable, accrued expenses and other current liabilities |
173 | (74 | ) | 43 | ||||||||
| Income taxes |
293 | (271 | ) | 288 | ||||||||
| Net realized and unrealized mark-to-market and hedging transactions |
49 | (10 | ) | 18 | ||||||||
| Pension and non-pension postretirement benefits obligations |
(270 | ) | (144 | ) | (165 | ) | ||||||
| Other noncurrent assets and liabilities |
119 | 9 | 134 | |||||||||
| Net cash flows provided by operating activities |
4,398 | 3,384 | 3,642 | |||||||||
| Cash flows from investing activities |
||||||||||||
| Capital expenditures |
(1,921 | ) | (1,954 | ) | (2,150 | ) | ||||||
| Proceeds from liquidated damages |
— | 92 | — | |||||||||
| Proceeds from nuclear decommissioning trust fund sales |
2,320 | 2,341 | 1,612 | |||||||||
| Investment in nuclear decommissioning trust funds |
(2,587 | ) | (2,564 | ) | (1,824 | ) | ||||||
| Collection of other notes receivable |
59 | 35 | (35 | ) | ||||||||
| Proceeds from sales of investments and wholly owned subsidiaries |
329 | 263 | 287 | |||||||||
| Proceeds from sales of long-lived assets |
52 | 10 | ||||||||||
| Acquisitions of businesses, net of cash acquired |
— | (272 | ) | (445 | ) | |||||||
| Investments in synthetic fuel-producing facilities |
(56 | ) | — | — | ||||||||
| Change in restricted cash |
55 | (92 | ) | (24 | ) | |||||||
| Net cash increase from consolidation of Sithe Energies, Inc. |
19 | — | — | |||||||||
| Other investing activities |
(6 | ) | 32 | 17 | ||||||||
| Net cash flows used in investing activities |
(1,736 | ) | (2,109 | ) | (2,562 | ) | ||||||
| Cash flows from financing activities |
||||||||||||
| Issuance of long-term debt |
232 | 3,015 | 1,223 | |||||||||
| Retirement of long-term debt |
(1,629 | ) | (2,922 | ) | (2,134 | ) | ||||||
| Issuance of long-term debt to financing affiliates |
— | 103 | — | |||||||||
| Retirement of long-term debt to financing affiliates |
(728 | ) | — | — | ||||||||
| Change in short-term debt |
164 | (355 | ) | 321 | ||||||||
| Issuance of mandatorily redeemable preferred securities |
— | 200 | — | |||||||||
| Retirement of mandatorily redeemable preferred securities |
— | (250 | ) | (18 | ) | |||||||
| Payment on acquisition note payable to Sithe Energies, Inc. |
(27 | ) | (446 | ) | — | |||||||
| Retirement of preferred stock |
— | (50 | ) | — | ||||||||
| Dividends paid on common stock |
(831 | ) | (620 | ) | (563 | ) | ||||||
| Proceeds from employee stock plans |
240 | 181 | 75 | |||||||||
| Purchase of treasury stock |
(82 | ) | — | — | ||||||||
| Contribution from minority interest of consolidated subsidiary |
— | — | 43 | |||||||||
| Other financing activities |
34 | (96 | ) | (43 | ) | |||||||
| Net cash flows used in financing activities |
(2,627 | ) | (1,240 | ) | (1,096 | ) | ||||||
| Increase (decrease) in cash and cash equivalents |
35 | 35 | (16 | ) | ||||||||
| Cash and cash equivalents at beginning of period |
493 | 469 | 485 | |||||||||
| Cash and cash equivalents, including cash held for sale |
528 | 504 | 469 | |||||||||
| Cash classified as held for sale on the consolidated balance sheet |
— | 11 | — | |||||||||
| Cash and cash equivalents at end of period |
$ | 528 | $ | 493 | $ | 469 | ||||||
See Notes to Consolidated Financial Statements
135
Exelon Corporation and Subsidiary Companies
Consolidated Balance Sheets
| December 31, | ||||||
| (in millions) |
2004 |
2003 | ||||
| Assets |
||||||
| Current assets |
||||||
| Cash and cash equivalents |
$ | 528 | $ | 493 | ||
| Restricted cash and investments |
31 | 97 | ||||
| Accounts receivable, net |
||||||
| Customer |
1,649 | 1,567 | ||||
| Other |
409 | 676 | ||||
| Mark-to-market derivative assets |
403 | 337 | ||||
| Inventories, at average cost |
||||||
| Fossil fuel |
230 | 212 | ||||
| Materials and supplies |
312 | 310 | ||||
| Notes receivable from affiliate |
— | 92 | ||||
| Deferred income taxes |
68 | 122 | ||||
| Assets held for sale |
— | 242 | ||||
| Other |
296 | 413 | ||||
| Total current assets |
3,926 | 4,561 | ||||
| Property, plant and equipment, net |
21,482 | 20,630 | ||||
| Deferred debits and other assets |
||||||
| Regulatory assets |
4,790 | 5,226 | ||||
| Nuclear decommissioning trust funds |
5,262 | 4,721 | ||||
| Investments |
804 | 955 | ||||
| Goodwill |
4,705 | 4,719 | ||||
| Mark-to-market derivative assets |
383 | 133 | ||||
| Other |
1,418 | 991 | ||||
| Total deferred debits and other assets |
17,362 | 16,745 | ||||
| Total assets |
$ | 42,770 | $ | 41,936 | ||
See Notes to Consolidated Financial Statements
136
Exelon Corporation and Subsidiary Companies
Consolidated Balance Sheets
| December 31, |
||||||||
| (in millions) |
2004 |
2003 |
||||||
| Liabilities and shareholders’ equity |
||||||||
| Current liabilities |
||||||||
| Commercial paper |
$ | 490 | $ | 326 | ||||
| Note payable to Sithe Energies, Inc. |
— | 90 | ||||||
| Long-term debt due within one year |
427 | 1,385 | ||||||
| Long-term debt to ComEd Transitional Funding Trust and PECO Energy Transitional Trust due within one year |
486 | 470 | ||||||
| Accounts payable |
1,255 | 1,238 | ||||||
| Mark-to-market derivative liabilities |
598 | 584 | ||||||
| Accrued expenses |
1,143 | 1,260 | ||||||
| Liabilities held for sale |
— | 61 | ||||||
| Other |
483 | 306 | ||||||
| Total current liabilities |
4,882 | 5,720 | ||||||
| Long-term debt |
7,292 | 7,889 | ||||||
| Long-term debt due to ComEd Transitional Funding Trust and PECO Energy Transitional Trust |
4,311 | 5,055 | ||||||
| Long-term debt to other financing trusts |
545 | 545 | ||||||
| Deferred credits and other liabilities |
||||||||
| Deferred income taxes |
4,488 | 4,320 | ||||||
| Unamortized investment tax credits |
275 | 288 | ||||||
| Asset retirement obligations |
3,981 | 2,997 | ||||||
| Pension obligations |
1,993 | 1,668 | ||||||
| Non-pension postretirement benefits obligations |
1,065 | 1,053 | ||||||
| Spent nuclear fuel obligation |
878 | 867 | ||||||
| Regulatory liabilities |
2,204 | 1,891 | ||||||
| Mark-to-market derivative liabilities |
323 | 141 | ||||||
| Other |
981 | 912 | ||||||
| Total deferred credits and other liabilities |
16,188 | 14,137 | ||||||
| Total liabilities |
33,218 | 33,346 | ||||||
| Commitments and contingencies |
||||||||
| Minority interest of consolidated subsidiaries |
42 | — | ||||||
| Preferred securities of subsidiaries |
87 | 87 | ||||||
| Shareholders’ equity |
||||||||
| Common stock (No par value, 1,200 shares authorized, 666.7 and 656.4 shares outstanding at December 31, 2004 and 2003, respectively) |
7,598 | 7,292 | ||||||
| Treasury stock, at cost (2.5 shares held at December 31, 2004) |
(82 | ) | — | |||||
| Retained earnings |
3,353 | 2,320 | ||||||
| Accumulated other comprehensive loss |
(1,446 | ) | (1,109 | ) | ||||
| Total shareholders’ equity |
9,423 | 8,503 | ||||||
| Total liabilities and shareholders’ equity |
$ | 42,770 | $ | 41,936 | ||||
See Notes to Consolidated Financial Statements
137
Exelon Corporation and Subsidiary Companies
Consolidated Statements of Changes in Shareholders’ Equity
| (Dollars in millions, shares in thousands) |
Issued Shares |
Common Stock |
Treasury Stock |
Deferred Compensation |
Retained Earnings |
Accumulated Other Comprehensive Loss |
Total Shareholders’ Equity |
||||||||||||||||||
| Balance, December 31, 2001 |
642,014 | $ | 6,961 | $ | — | $ | (2 | ) | $ | 1,169 | $ | (26 | ) | $ | 8,102 | ||||||||||
| Net income |
— | — | — | — | 1,440 | — | 1,440 | ||||||||||||||||||
| Long-term incentive plan activity |
4,098 | 87 | — | — | — | — | 87 | ||||||||||||||||||
| Employee stock purchase plan issuances |
514 | 11 | — | — | — | — | 11 | ||||||||||||||||||
| Amortization of deferred compensation |
— | — | — | 1 | — | — | 1 | ||||||||||||||||||
| Common stock dividends declared |
— | — | — | — | (567 | ) | — | (567 | ) | ||||||||||||||||
| Other comprehensive loss, net of income taxes of $(850) |
— | — | — | — | — | (1,332 | ) | (1,332 | ) | ||||||||||||||||
| Balance, December 31, 2002 |
646,626 | 7,059 | — | (1 | ) | 2,042 | (1,358 | ) | 7,742 | ||||||||||||||||
| Net income |
— | — | — | — | 905 | — | 905 | ||||||||||||||||||
| Long-term incentive plan activity |
9,322 | 222 | — | — | — | — | 222 | ||||||||||||||||||
| Employee stock purchase plan issuances |
418 | 11 | — | — | — | — | 11 | ||||||||||||||||||
| Amortization of deferred compensation |
— | — | — | 1 | — | — | 1 | ||||||||||||||||||
| Common stock dividends declared |
— | — | — | — | (625 | ) | — | (625 | ) | ||||||||||||||||
| Redemption premium on PECO preferred stock |
— | — | — | — | (2 | ) | — | (2 | ) | ||||||||||||||||
| Other comprehensive income, net of income taxes of $217 |
— | — | — | — | — | 249 | 249 | ||||||||||||||||||
| Balance, December 31, 2003 |
656,366 | 7,292 | — | — | 2,320 | (1,109 | ) | 8,503 | |||||||||||||||||
| Net income |
— | — | — | — | 1,864 | — | 1,864 | ||||||||||||||||||
| Long-term incentive plan activity |
10,013 | 296 | — | — | — | — | 296 | ||||||||||||||||||
| Employee stock purchase plan issuances |
309 | 10 | — | — | — | — | 10 | ||||||||||||||||||
| Common stock purchases |
— | — | (82 | ) | — | — | — | (82 | ) | ||||||||||||||||
| Common stock dividends declared |
— | — | — | — | (831 | ) | — | (831 | ) | ||||||||||||||||
| Adjustments to accumulated other comprehensive loss due to the consolidation of Sithe |
— | — | — | — | — | (6 | ) | (6 | ) | ||||||||||||||||
| Other comprehensive loss, net of income taxes of $(190) |
— | — | — | — | — | (331 | ) | (331 | ) | ||||||||||||||||
| Balance, December 31, 2004 |
666,688 | $ | 7,598 | $ | (82 | ) | $ | — | $ | 3,353 | $ | (1,446 | ) | $ | 9,423 | ||||||||||
See Notes to Consolidated Financial Statements
138
Exelon Corporation and Subsidiary Companies
Consolidated Statements of Comprehensive Income
| For the Years Ended December 31, |
|||||||||||
| (in millions) |
2004 |
2003 |
2002 |
||||||||
| Net income |
$ | 1,864 | $ | 905 | $ | 1,440 | |||||
| Other comprehensive income (loss) |
|||||||||||
| Minimum pension liability, net of income taxes of $(228), $16 and $(597), respectively |
(392 | ) | 26 | (1,007 | ) | ||||||
| SFAS No. 143 transition adjustment, net of income taxes of $167 |
— | 168 | — | ||||||||
| Change in net unrealized gain (loss) on cash-flow hedges, net of income taxes of $6, $5 and $(129), respectively |
8 | 9 | (193 | ) | |||||||
| Foreign currency translation adjustment, net of income taxes of $1, $0 and $0, respectively |
1 | 3 | — | ||||||||
| Unrealized gain (loss) on marketable securities, net of income taxes of $31, $29, and $(124), respectively |
52 | 43 | (132 | ) | |||||||
| Total other comprehensive income (loss) |
(331 | ) | 249 | (1,332 | ) | ||||||
| Total comprehensive income |
$ | 1,533 | $ | 1,154 | $ | 108 | |||||
See Notes to Consolidated Financial Statements
139
Exelon Corporation and Subsidiary Companies
Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
1. Significant Accounting Policies
Description of Business
Exelon Corporation (Exelon) is a utility services holding company engaged, through its subsidiaries, in the energy delivery, generation and other businesses discussed below (see Note 22—Segment Information). The energy delivery businesses (Energy Delivery) include the purchase and retail sale of electricity and distribution and transmission services by Commonwealth Edison Company (ComEd) in northern Illinois and by PECO Energy Company (PECO) in southeastern Pennsylvania and the purchase and retail sale of natural gas and related distribution services by PECO in the Pennsylvania counties surrounding the City of Philadelphia. The generation business consists principally of the electric generating facilities and wholesale energy marketing operations of Exelon Generation Company, LLC (Generation), the competitive retail sales business of Exelon Energy Company (Exelon Energy), Generation’s investment in Sithe Energies, Inc. (Sithe) and certain other generation projects. Exelon’s other businesses, constituting the enterprises segment, consist of the infrastructure and electrical contracting services of Exelon Enterprises Company, LLC (Enterprises). Effective January 1, 2004, Exelon Energy Company, which had been previously included in the Enterprises segment, became part of Generation. See Note 2—Acquisitions and Dispositions for information regarding the disposition of businesses within the Enterprises segment and Note 25—Subsequent Events for information regarding the sale of Sithe.
Basis of Presentation
Exelon’s consolidated financial statements include the accounts of entities in which it has a controlling financial interest, other than certain financing trusts of ComEd and PECO described below, and its proportionate interests in jointly owned electric utility plants, after the elimination of intercompany transactions. A controlling financial interest is evidenced by either a voting interest greater than 50% or a risk and rewards model that identifies Exelon or one of its subsidiaries as the primary beneficiary of the variable interest entity. Investments and joint ventures in which Exelon does not have a controlling financial interest and certain financing trusts of ComEd and PECO are accounted for under the equity or cost methods of accounting.
Exelon owns 100% of all significant consolidated subsidiaries, either directly or indirectly, except for ComEd, of which Exelon owns more than 99%, Southeast Chicago Energy Project, LLC (SCEP), of which Exelon owns 71%, and Sithe, of which Exelon owned 50% at December 31, 2004. Exelon has reflected the third-party interests in the above majority-owned investments as minority interests in its consolidated financial statements. As a result of the adoption of Financial Accounting Standards Board (FASB) Statement of Financial Accounting Standards (SFAS) No. 150, “Accounting for Certain Financial Instruments with Characteristics of Both Liabilities and Equity” (SFAS No. 150), on July 1, 2003, Exelon reclassified the minority interest associated with SCEP to a long-term liability. The total minority interest related to SCEP was $49 million and $51 million as of December 31, 2004 and 2003.
In accordance with FASB Interpretation No. (FIN) 46 (revised December 2003), “Consolidation of Variable Interest Entities” (FIN 46-R), Sithe was consolidated in Exelon’s financial statements as of March 31, 2004. Certain trusts and limited partnerships that are financing subsidiaries of ComEd and PECO have issued debt or mandatorily redeemable preferred securities. Due to the adoption of FIN 46-R, these subsidiaries are no longer consolidated within the financial statements of Exelon as of December 31, 2003, or as of July 1, 2003 for PECO Energy Capital Trust IV (PECO Trust IV). See “Variable Interest Entities” below for further discussion of the adoption of FIN 46-R and the resulting consolidation of Sithe and the deconsolidation of these financing subsidiaries.
140
Exelon Corporation and Subsidiary Companies
Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, except per share data unless otherwise noted)
The share and per-share amounts included in Exelon’s Consolidated Financial Statements and Notes to Consolidated Financial Statements have been adjusted for all periods presented to reflect a 2-for-1 stock split of Exelon’s common stock with a distribution date of May 5, 2004. See Note 18—Common Stock for additional information regarding the stock split.
Reclassifications
Certain prior year amounts have been reclassified for comparative purposes. The reclassifications did not affect net income or shareholders’ equity.
Use of Estimates
The preparation of financial statements in conformity with accounting principles generally accepted in the United States (GAAP) requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. Areas in which significant estimates have been made include, but are not limited to, the accounting for nuclear decommissioning costs and asset retirement obligations, inventory reserves, allowance for doubtful accounts, goodwill and asset impairments, pension and other postretirement benefits, derivative instruments, fixed asset depreciation, environmental costs, taxes, severance and unbilled energy revenues.
Accounting for the Effects of Regulation
Exelon accounts for its operations in accordance with accounting policies prescribed by the regulatory authorities having jurisdiction, principally the Illinois Commerce Commission (ICC) and the Pennsylvania Public Utility Commission (PUC) under state public utility laws, the Federal Energy Regulatory Commission (FERC) under various Federal laws, and the Securities and Exchange Commission (SEC) under the Public Utility Holding Company Act of 1935 (PUHCA), and Energy Delivery applies SFAS No. 71, “Accounting for the Effects of Certain Types of Regulation,” (SFAS No. 71) when appropriate. SFAS No. 71 requires Energy Delivery to record in its financial statements the effects of rate regulation for utility operations that meet the following criteria: (1) third-party regulation of rates; (2) cost-based rates; and (3) a reasonable assumption that all costs will be recoverable from customers through rates. Exelon believes that it is probable that currently recorded regulatory assets and liabilities will be recovered in future rates. If a separable portion of Energy Delivery’s business were no longer to meet the provisions of SFAS No. 71, Exelon would be required to eliminate from its financial statements the effects of regulation for that portion.
Variable Interest Entities
FIN 46-R addressed the requirements for consolidating certain variable interest entities. FIN 46 was effective for Exelon’s variable interest entities created after January 31, 2003. FIN 46-R was effective December 31, 2003 for Exelon’s other variable interest entities that were considered to be special-purpose entities and as of March 31, 2004 for all other variable interest entities.
Exelon consolidated Sithe, 50% owned through a wholly owned subsidiary of Generation, as of March 31, 2004 pursuant to the provisions of FIN 46-R and recorded income of $32 million (net of income taxes) as a result of the reversal of guarantees of Sithe’s commitments previously recorded by
141
Exelon Corporation and Subsidiary Companies
Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, except per share data unless otherwise noted)
Generation. This income was reported as a cumulative effect of a change in accounting principle in the first quarter of 2004. As of March 31, 2004, Generation was a 50% owner of Sithe, and Exelon had accounted for Sithe as an unconsolidated equity method investment prior to March 31, 2004. Sithe owns and operates power-generating facilities and was sold by Generation on January 31, 2005. See Note 3—Sithe for additional information on the consolidation of Sithe and Note 25—Subsequent Events for additional information on the sale of Sithe in 2005.
PECO Trust IV, a financing subsidiary of PECO created in May 2003, was deconsolidated from the financial statements of Exelon pursuant to the provisions of FIN 46 as of July 1, 2003. Pursuant to the provisions of FIN 46-R, as of December 31, 2003, the financing trusts of ComEd, namely ComEd Financing II (formed in November 1996), ComEd Financing III (formed in September 2002), ComEd Funding LLC (formed in July 1998) and ComEd Transitional Funding Trust (formed in October 1998), and the other financing trusts of PECO, namely PECO Energy Capital Trust III (PECO Trust III) (formed in April 1998) and PECO Energy Transition Trust (PETT) (formed in June 1998), were deconsolidated from Exelon’s financial statements. Amounts owed to these financing trusts at December 31, 2004 and 2003 of $5,342 million and $6,070 million, respectively, were recorded as debt to financing trusts within the Consolidated Balance Sheets.
This change in presentation related to the financing trusts had no effect on Exelon’s net income. In accordance with FIN 46-R, prior periods were not restated. The maximum exposure to loss as a result of ComEd and PECO’s involvement with the financing trusts is $62 million and $87 million, respectively, at December 31, 2004.
Revenues
Operating Revenues. Operating revenues are recorded as service is rendered or energy is delivered to customers. At the end of each month, Exelon accrues an estimate for the unbilled amount of energy delivered or services provided to customers (see Note 6—Accounts Receivable).
Option Contracts, Swaps, and Commodity Derivatives. Premiums received and paid on option contracts and swap arrangements considered “normal” derivatives pursuant to SFAS No. 133, “Accounting for Derivatives and Hedging Activities” (SFAS No. 133) are amortized to revenue and expensed over the lives of the contracts. Certain option contracts and swap arrangements are considered derivative instruments and are recorded at fair value with subsequent changes in fair value recognized as revenues and expenses, unless hedge accounting is applied. Commodity derivatives used for trading purposes are accounted for using the mark-to-market method with unrealized gains and losses recognized in operating revenues.
Trading Activities. Exelon accounts for its trading activities under the provisions of Emerging Issues Task Force (EITF) Issue No. 02-3, “Accounting for Contracts Involved in Energy Trading and Risk Management Activities” (EITF 02-3), which requires revenues and energy costs related to energy trading contracts to be presented on a net basis in the income statement.
Physically Settled Derivative Contracts. Exelon accounts for realized gains and losses on physically settled derivative contracts not “held for trading purposes” in accordance with EITF Issue No. 03-11, “Reporting Realized Gains and Losses on Derivative Instruments That Are Subject to FASB Statement No. 133, ‘Accounting for Derivative Instruments and Hedging Activities,’ and Not ‘Held for Trading Purposes’ as Defined in EITF Issue No. 02-3, ‘Issues Involved in Accounting for Derivative
142
Exelon Corporation and Subsidiary Companies
Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, except per share data unless otherwise noted)
Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities’” (EITF 03-11).
EITF 03-11 was ratified by the FASB in August 2003. The EITF concluded that determining whether realized gains and losses on physically settled derivative contracts not “held for trading purposes” should be reported in the income statement on a gross or net basis is a matter of judgment that depends on the relevant facts and circumstances. Exelon adopted EITF 03-11 as of January 1, 2004 and presented $966 million of purchased power and $14 million of fuel expense net within revenues during 2004. Prior periods were not reclassified. The adoption of EITF 03-11 had no effect on Exelon’s net income. Had EITF 03-11 been retroactively applied to 2003, operating revenues, purchased power and fuel expense would have been affected as follows:
| 2003 |
As Reported |
EITF 03-11 Impact |
Pro Forma | |||||||
| Operating revenue |
$ | 15,812 | $ | (996 | ) | $ | 14,816 | |||
| Purchased power |
3,841 | (943 | ) | 2,898 | ||||||
| Fuel expense |
2,534 | (53 | ) | 2,481 | ||||||
Exelon is unable to determine the impact on operating revenues, purchased power and fuel expense, had EITF 03-11 been applied retroactively to 2002 results of operations, due to system constraints.
Stock-Based Compensation
Exelon accounts for its stock-based compensation plans under the intrinsic method prescribed by Accounting Principles Board No. 25, “Accounting for Stock Issued to Employees” (APB No. 25) and related interpretations and follows the disclosure requirements of SFAS No. 123, “Accounting for Stock-Based Compensation” (SFAS No. 123), and SFAS No. 148, “Accounting for Stock-Based Compensation—Transition and Disclosure—an amendment of FASB Statement No. 123.” Accordingly, compensation expense related to stock options recognized within the Consolidated Statements of Income was insignificant in 2004, 2003 and 2002. Expense recognized related to other stock-based compensation plans is further described in Note 18—Common Stock. The tables below show the effect on Exelon’s net income and earnings per share for 2004, 2003 and 2002 had Exelon elected to account for all of its stock-based compensation plans using the fair-value method under SFAS No. 123:
| 2004 |
2003 |
2002 |
||||||||||
| Net income—as reported |
$ | 1,864 | $ | 905 | $ | 1,440 | ||||||
| Add: Stock-based compensation expense included in reported net income, net of income taxes |
39 | 19 | 12 | |||||||||
| Deduct: Total stock-based compensation expense determined under fair-value method for all awards, net of income taxes (a) |
(60 | ) | (39 | ) | (45 | ) | ||||||
| Pro forma net income |
$ | 1,843 | $ | 885 | $ | 1,407 | ||||||
| Earnings per share: |
||||||||||||
| Basic—as reported |
$ | 2.82 | $ | 1.39 | $ | 2.23 | ||||||
| Basic—pro forma |
$ | 2.79 | $ | 1.36 | $ | 2.18 | ||||||
| Diluted—as reported |
$ | 2.78 | $ | 1.38 | $ | 2.22 | ||||||
| Diluted—pro forma |
$ | 2.75 | $ | 1.35 | $ | 2.17 | ||||||
| (a) | The fair value of options granted was estimated using a Black-Scholes option pricing model. |
143
Exelon Corporation and Subsidiary Companies
Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, except per share data unless otherwise noted)
Income Taxes
Deferred Federal and state income taxes are provided on all significant temporary differences between the book basis and the tax basis of assets and liabilities and for tax benefits carried forward. Investment tax credits previously utilized for income tax purposes have been deferred on the Consolidated Balance Sheets and are recognized in book income over the life of the related property.
Pursuant to the Internal Revenue Code, Exelon files a consolidated Federal income tax return that includes its subsidiaries in which it owns at least 80% of the outstanding stock. Income taxes are allocated to each of Exelon’s subsidiaries included in the filing of the consolidated Federal income tax return based on the separate return method. Exelon records its income tax valuation allowance by assessing which deferred tax assets are more likely than not to be realized in the future (see Note 13—Income Taxes).
Losses on Reacquired Debt
Recoverable losses on reacquired debt related to regulated operations are deferred and amortized to interest expense over the life of new debt issued to finance the debt redemption consistent with rate recovery for rate-making purposes. Losses on other reacquired debt are recognized in Exelon’s Consolidated Statements of Income as incurred (see Note 21—Supplemental Financial Information).
Comprehensive Income
Comprehensive income includes all changes in equity during a period except those resulting from investments by and distributions to shareholders. Other comprehensive income primarily relates to unrealized gains or losses on securities held in nuclear decommissioning trust funds and unrealized gains and losses on cash-flow hedge instruments. Comprehensive income is reflected in the Consolidated Statements of Changes in Shareholders’ Equity and the Consolidated Statements of Comprehensive Income.
Cash and Cash Equivalents
Exelon considers all temporary cash investments purchased with an original maturity of three months or less to be cash equivalents.
Restricted Cash and Investments
As of December 31, 2004, restricted cash and investments primarily represented restricted cash related to Sithe’s Independence Plant partnership distribution fund. As of December 31, 2003, restricted cash and investments primarily represented liquidated damages receipts at Generation and proceeds from a ComEd pollution control bond offering in December 2003 which were applied to pay pollution control bonds upon their maturity in January 2004.
Restricted cash and investments not available for general operations or to satisfy current liabilities are classified as noncurrent assets. As of December 31, 2004, $93 million of restricted cash and investments were classified within deferred debits and other assets, which included $83 million of debt service reserves, major overhaul reserves of $7 million and lease service reserves of $3 million. As of December 31, 2003, there were no restricted cash and investments classified as noncurrent assets.
144
Exelon Corporation and Subsidiary Companies
Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, except per share data unless otherwise noted)
Allowance for Doubtful Accounts
The allowance for doubtful accounts reflects Exelon’s best estimate of probable losses in the accounts receivable balances. The allowance is based on known troubled accounts, historical experience and other currently available evidence. Customer accounts are generally considered delinquent if the amount billed is not received by the time the next bill is issued, typically monthly. Customer accounts are written off based upon approved regulatory or legislative requirements.
Inventories
Inventory is recorded at the lower of cost or market, and provisions are made for excess and obsolete inventory.
Fossil Fuel. Fossil fuel inventory includes the weighted average costs of stored natural gas, coal and oil. The costs of natural gas, coal and oil are generally included in inventory when purchased and charged to fuel expense when used. Fossil fuel also includes propane at cost. PECO has several long-term storage contracts for natural gas as well as a liquefied natural gas storage facility.
Materials and Supplies. Materials and supplies inventory generally includes the average costs of transmission, distribution and generating plant materials. Materials are generally charged to inventory when purchased and then expensed or capitalized to plant, as appropriate, when installed.
Emission Allowances
Emission allowances are included in inventories and deferred debits or other assets and are carried at the lower of weighted average cost or market and charged to fuel expense as they are used in operations. Exelon’s emission allowance balances as of December 31, 2004 and 2003 were $106 million and $105 million, respectively.
Marketable Securities
Marketable securities are classified as available-for-sale securities and are reported at fair value pursuant to SFAS No. 115, “Accounting for Certain Investments in Debt and Equity Securities” (SFAS No. 115). Unrealized gains and losses, net of tax, on nuclear decommissioning trust funds transferred to Generation from PECO and ComEd are considered in the determination of the regulatory assets and liabilities on Exelon’s Consolidated Balance Sheets. See Note 21—Supplemental Financial Information for additional information regarding Exelon’s regulatory assets and liabilities. Unrealized gains and losses on nuclear decommissioning trust funds for the AmerGen units are reported in other comprehensive income. Prior to the adoption of SFAS No. 143, “Accounting for Asset Retirement Obligations” (SFAS No. 143) on January 1, 2003, unrealized gains and losses on marketable securities held in nuclear decommissioning trust funds were reported in accumulated depreciation for operating units transferred to Generation from PECO and as other comprehensive income for operating and retired units transferred to Generation from ComEd. At December 31, 2004 and 2003, Exelon had no held-to-maturity securities.
Purchased Gas Adjustment Clause
PECO’s natural gas rates are subject to a fuel adjustment clause designed to recover or refund the difference between the actual cost of purchased gas and the amount included in rates. Differences
145
Exelon Corporation and Subsidiary Companies
Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, except per share data unless otherwise noted)
between the amounts billed to customers and the actual costs recoverable are deferred and recovered or refunded in future periods by means of prospective quarterly adjustments to rates. At December 31, 2004 and 2003, deferred energy costs of $71 million and $81 million, respectively, were recorded in other current assets on Exelon’s Consolidated Balance Sheets.
Leases
Exelon accounts for leases in accordance with SFAS No. 13 “Accounting for Leases” and determines whether its long-term power purchase and sales contracts are leases pursuant to EITF Issue No. 01-8, “Determining Whether an Arrangement is a Lease” (EITF 01-8) which applies to arrangements initiated or modified after October 1, 2003. At the inception of the lease, or subsequent modification, Exelon determines whether the lease is an operating or capital lease based upon its terms and characteristics. Several of Exelon’s long-term power purchase agreements which have been determined to be operating leases have significant contingent rental payments which are dependent on the future operating characteristics of the associated plants such as plant availability. Exelon recognizes contingent rental expense when it becomes probable of payment.
Property, Plant and Equipment
Property, plant and equipment is recorded at cost. The cost of maintenance, repairs and minor replacements of property is charged to maintenance expense as incurred.
For Energy Delivery, upon retirement, the cost of regulated property, net of salvage, is charged to accumulated depreciation and removal costs reduce the related regulated liability in accordance with the composite method of depreciation. For unregulated property, the cost and accumulated depreciation of property, plant and equipment retired or otherwise disposed of are removed from the related accounts and included in the determination of any gain or loss on disposition.
For Generation, upon retirement, the cost of property, including net salvage cost, is charged to accumulated depreciation.
See Note 7—Property, Plant and Equipment and Note 21—Supplemental Financial Information for additional information regarding property, plant and equipment.
Nuclear Fuel
The cost of nuclear fuel is capitalized and charged to fuel expense using the unit-of-production method. The estimated cost of disposal of Spent Nuclear Fuel (SNF) is established per the Standard Waste Contract with the Department of Energy (DOE) and is expensed at one mill ($.001) per kilowatthour of net nuclear generation. On-site SNF storage costs are capitalized or expensed, as incurred, based upon the nature of the work performed.
Nuclear Outage Costs
Costs associated with nuclear outages are recorded in the period incurred.
Capitalized Software Costs
Costs incurred during the application development stage of software projects that are developed or obtained for internal use are capitalized. At December 31, 2004 and 2003, net unamortized
146
Exelon Corporation and Subsidiary Companies
Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, except per share data unless otherwise noted)
capitalized software costs totaled $311 million and $356 million, respectively. Such capitalized amounts are amortized ratably over the expected lives of the projects when they become operational, generally not to exceed ten years. Certain capitalized software costs are being amortized over fifteen years pursuant to regulatory approval. During 2004, 2003 and 2002, Exelon amortized capitalized software costs of $80 million, $69 million and $64 million, respectively.
Depreciation and Amortization
Depreciation is provided over the estimated service lives of property, plant and equipment on a straight-line basis using the composite method. Annual depreciation provisions for financial reporting purposes, expressed as a percentage of average service life for each asset category, are presented in the table below. See Note 7—Property, Plant and Equipment for information regarding a change in Energy Delivery’s depreciation rates.
| Asset Category |
2004 |
2003 |
2002 | |||
| Electric—transmission and distribution |
2.82% | 2.81% | 3.11% | |||
| Electric—generation |
3.34% | 2.90% | 3.58% | |||
| Gas |
2.52% | 2.38% | 2.13% | |||
| Common—gas and electric |
4.60% | 7.53% | 6.40% | |||
| Other property and equipment |
6.77% | 8.20% | 7.88% |
Amortization of regulatory assets is provided over the recovery period specified in the related legislation or regulatory agreement. See Note 21—Supplemental Financial Information for further information regarding Exelon’s regulatory assets.
Nuclear Generating Station Decommissioning
Exelon accounts for the costs of decommissioning its nuclear generating stations in accordance with SFAS No. 143. See Note 14—Nuclear Decommissioning and Spent Fuel Storage for information regarding the adoption and application of SFAS No. 143 and “Cumulative Effect of Changes in Accounting Principles” below for pro forma net income and earnings per common share for the year ended December 31, 2002, adjusted as if SFAS No. 143 had been applied during that period.
Capitalized Interest and Allowance for Funds Used During Construction
Exelon uses SFAS No. 34, “Capitalizing Interest Costs” to calculate the costs during construction of debt funds used to finance its non-regulated construction projects. Exelon recorded capitalized interest of $11 million, $15 million and $20 million in 2004, 2003 and 2002, respectively.
Allowance for funds used during construction (AFUDC) is the cost, during the period of construction, of debt and equity funds used to finance construction projects for regulated operations. AFUDC is recorded as a charge to construction work in progress and as a non-cash credit to AFUDC that is included in interest expense for debt-related funds and other income and deductions for equity-related funds. The rates used for capitalizing AFUDC are computed under a method prescribed by regulatory authorities (see Note 21—Supplemental Financial Information). Exelon recorded credits to AFUDC of $5 million, $16 million and $19 million in 2004, 2003 and 2002, respectively.
147
Exelon Corporation and Subsidiary Companies
Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, except per share data unless otherwise noted)
Guarantees
Beginning February 1, 2003, pursuant to FIN 45, “Guarantor’s Accounting and Disclosure Requirements, Including Indirect Guarantees of Indebtedness to Others” (FIN 45), Exelon recognizes, at the inception of a guarantee, a liability for the fair market value of the obligations it has undertaken in issuing the guarantee, including its ongoing obligation to perform over the term of the guarantee in the event that the specified triggering events or conditions occur.
The liability that is initially recognized at the inception of the guarantee is reduced as Exelon is released from risk under the guarantee. Depending on the nature of the guarantee, Exelon’s release from risk may be recognized only upon the expiration or settlement of the guarantee or by a systematic and rational amortization method over the term of the guarantee. The recognition and subsequent adjustment of the liability is highly dependent upon the nature of the associated guarantee.
Asset Impairments
Long-Lived Assets. Exelon evaluates the carrying value of long-lived assets to be held and used for impairment whenever indications of impairment exist in accordance with the requirements of SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets” (SFAS No. 144). The carrying value of long-lived assets is considered impaired when the projected undiscounted cash flows are less than the carrying value. In that event, a loss would be recognized based on the amount by which the carrying value exceeds the fair value. Fair value is determined primarily by available market valuations or, if applicable, discounted cash flows. See Note 2—Acquisitions and Dispositions for a description of the impairment charge recorded in 2003 related to the long-lived assets of Boston Generating, LLC (Boston Generating).
Upon meeting certain criteria defined in SFAS No. 144, the assets and associated liabilities that compose a disposal group are classified as held for sale and the carrying value of these assets is adjusted downward, if necessary, to the estimated sales price, less cost to sell. See Note 2—Acquisitions and Dispositions for a description of assets and liabilities classified as held for sale as of December 31, 2003 and impairments recorded related to those assets.
Goodwill. Goodwill represents the excess of the purchase price paid over the estimated fair value of the assets acquired and liabilities assumed in the acquisition of a business. As of January 1, 2002, Exelon adopted SFAS No. 142, “Goodwill and Other Intangible Assets” (SFAS No. 142) and recorded a loss of $230 million as a cumulative effect of a change in accounting principle upon its adoption. Pursuant to SFAS No. 142, goodwill is not amortized but is tested for impairment at least annually or on an interim basis if an event occurs or circumstances change that would reduce the fair value of a reporting unit below its carrying value. See Note 9—Intangible Assets for information regarding the adoption of SFAS No. 142 and goodwill impairment studies that have been performed.
Investments. Investments are considered to be impaired when a decline in fair value is judged to be other-than-temporary. If the cost of an investment exceeds its fair value, Exelon evaluates, among other factors, general market conditions, the duration and extent to which the fair value is less than cost, as well as Exelon’s intent and ability to hold the investment. Exelon also considers specific adverse conditions related to the financial health of and business outlook for the investee. Once a decline in fair value is determined to be other-than-temporary, an impairment charge is recorded and a new cost basis is established. See Note 3—Sithe for a description of the impairments recorded in 2003 related to Generation’s investment in Sithe and Note 16—Fair Value of Financial Assets and Liabilities for a description of the other-than-temporary impairments in the nuclear decommissioning trust funds determined in 2004.
148
Exelon Corporation and Subsidiary Companies
Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, except per share data unless otherwise noted)
Derivative Financial Instruments
Exelon enters into derivatives to manage its exposure to fluctuations in interest rates, changes in interest rates related to planned future debt issuances and changes in the fair value of outstanding debt. Generation utilizes derivatives with respect to energy transactions to manage the utilization of its available generating capability and the supply of wholesale energy to its affiliates. Generation also utilizes energy option contracts and energy financial swap arrangements to limit the market price risk associated with forward energy commodity contracts. Additionally, Generation enters into energy-related derivatives for trading purposes. Exelon’s derivative activities are in accordance with Exelon’s Risk Management Policy (RMP).
Exelon accounts for derivative financial instruments under SFAS No. 133. Under the provisions of SFAS No. 133, all derivatives are recognized on the balance sheet at their fair value unless they qualify for a normal purchases or normal sales exception. Derivatives on the balance sheet are presented as current or noncurrent mark-to-market derivative assets or liabilities. Changes in the fair value of derivatives are recognized in earnings unless specific hedge accounting criteria are met, in which case those changes are recorded in earnings as an offset to the changes in fair value of the exposure being hedged or deferred in accumulated other comprehensive income and recognized in earnings as hedged transactions occur. Amounts recorded in earnings are included in revenue, purchased power or other, net on the consolidated statements of income.
Revenues and expenses on contracts that qualify as normal purchases or normal sales are recognized when the underlying physical transaction is completed. “Normal” purchases and sales are contracts where physical delivery is probable, quantities are expected to be used or sold in the normal course of business over a reasonable period of time, and price is not tied to an unrelated underlying derivative. As part of Generation’s energy marketing business, Generation enters into contracts to buy and sell energy to meet the requirements of its customers. These contracts include short-term and long-term commitments to purchase and sell energy and energy-related products in the retail and wholesale markets with the intent and ability to deliver or take delivery. While these contracts are considered derivative financial instruments under SFAS No. 133, the majority of these transactions have been designated as “normal” purchases or “normal” sales and are thus not required to be recorded at fair value, but on an accrual basis of accounting.
A derivative financial instrument can be designated as a hedge of the fair value of a recognized asset or liability or of an unrecognized firm commitment (fair-value hedge), or a hedge of a forecasted transaction or the variability of cash flows to be received or paid related to a recognized asset or liability (cash-flow hedge). Changes in the fair value of a derivative that is highly effective as, and is designated and qualifies as, a fair-value hedge, are recognized in earnings as offsets to the changes in fair value of the exposure being hedged. Changes in the fair value of a derivative that is highly effective as, and is designated as and qualifies as, a cash-flow hedge are deferred in accumulated other comprehensive income and are recognized in earnings as the hedged transactions occur. Any ineffectiveness is recognized in earnings immediately. On an ongoing basis, the Company assesses the hedge effectiveness of all derivatives that are designated as hedges for accounting purposes in order to determine that each derivative continues to be highly effective in offsetting changes in fair values or cash flows of hedged items. If it is determined that the derivative is not highly effective as a hedge, hedge accounting will be discontinued prospectively.
Generation enters into contracts to buy and sell energy for trading purposes subject to limits. These contracts are recognized on the balance sheet at fair value and changes in the fair value of these derivative financial instruments are recognized in earnings.
149
Exelon Corporation and Subsidiary Companies
Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, except per share data unless otherwise noted)
Severance Benefits
Exelon accounts for its ongoing severance plans in accordance with SFAS No. 112, “Employer’s Accounting for Postemployment Benefits, an amendment of FASB Statements No. 5 and 43” (SFAS No. 112) and SFAS No. 88, “Employers’ Accounting for Settlements and Curtailments of Defined Benefit Pension Plans and for Termination Benefits” and accrues amounts associated with severance benefits that are considered probable and that can be reasonably estimated. See Note 10—Severance Accounting for further discussion of Exelon’s accounting for severance benefits.
Retirement Benefits
Exelon’s defined benefit pension plans and postretirement welfare benefit plans are accounted for in accordance with SFAS No. 87, “Employer’s Accounting for Pensions” (SFAS No. 87), SFAS No. 106, “Employers’ Accounting for Postretirement Benefits Other than Pensions” (SFAS No. 106) and FASB Staff Position (FSP) FAS 106-2, “Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003” (FSP FAS 106-2), and are disclosed in accordance with SFAS No. 132, “Employers’ Disclosures about Pensions and Other Postretirement Benefits—an Amendment of FASB Statements No. 87, 88, and 106” (revised 2003) (SFAS No. 132). See Note 15—Retirement Benefits for further discussion of Exelon’s accounting for retirement benefits in accordance with SFAS No. 87 and SFAS No. 106 and disclosures pursuant to SFAS No. 132.
FSP FAS 106-2. Through its postretirement benefit plans, Exelon provides retirees with prescription drug coverage. The Medicare Prescription Drug, Improvement and Modernization Act of 2003 (Prescription Drug Act) was enacted on December 8, 2003. The Prescription Drug Act introduced a prescription drug benefit under Medicare as well as a Federal subsidy to sponsors of retiree health care benefit plans that provide a benefit that is at least actuarially equivalent to the Medicare prescription drug benefit. Management believes the prescription drug benefit provided under Exelon’s postretirement benefit plans is at least actuarially equivalent to the Medicare prescription drug benefit. In response to the enactment of the Prescription Drug Act, in May 2004, the FASB issued FSP FAS 106-2, which provided transition guidance for accounting for the effects of the Prescription Drug Act and superseded FSP FAS 106-1, which had been issued in January 2004. FSP FAS 106-1 permitted a plan sponsor of a postretirement health care plan that provides a prescription drug benefit to make a one-time election to defer the accounting for the effects of the Prescription Drug Act. Exelon made the one-time election allowed by FSP FAS 106-1 during the first quarter of 2004.
During the second quarter of 2004, Exelon early adopted the provisions of FSP FAS 106-2, resulting in a remeasurement of its postretirement benefit plans’ assets and accumulated postretirement benefit obligations (APBO) as of December 31, 2003. Upon adoption, the effect of the subsidy on benefits attributable to past service was accounted for as an actuarial experience gain, resulting in a decrease of the APBO of approximately $186 million. The annualized reduction in the net periodic postretirement benefit cost is estimated to be approximately $33 million compared to the annual cost calculated without considering the effects of the Prescription Drug Act. The effect of the subsidy on the components of net periodic postretirement benefit cost for 2004 included in the consolidated financial statements and Note 15—Retirement Benefits was as follows:
| 2004 | |||
| Amortization of the actuarial experience gain |
$ | 15 | |
| Reduction in current period service cost |
6 | ||
| Reduction in interest cost on the APBO |
12 | ||
150
Exelon Corporation and Subsidiary Companies
Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, except per share data unless otherwise noted)
Previously reported historical financial information for the three months ended March 31, 2004 has been adjusted in Note 24—Quarterly Data (Unaudited).
Treasury Stock
Treasury shares are recorded at cost. Any shares of common stock repurchased are held as treasury shares unless cancelled or reissued.
Foreign Currency Translation
The financial statements of Exelon’s foreign subsidiaries were prepared in their respective local currencies and translated into U.S. dollars based on the current exchange rates at the end of the periods for the Consolidated Balance Sheets and on weighted-average rates for the periods for the Consolidated Statements of Income. Foreign currency translation adjustments, net of deferred income tax benefits, are reflected as a component of other comprehensive income on the Consolidated Statements of Comprehensive Income and, accordingly, have no effect on net income.
New Accounting Pronouncements
EITF 03-1. In March 2004, the EITF reached a consensus on and the FASB ratified EITF Issue No. 03-1, “The Meaning of Other-Than-Temporary Impairment and Its Application to Certain Investments” (EITF 03-1). EITF 03-1 provides guidance for evaluating whether an investment is other-than-temporarily impaired. Exelon adopted the disclosure requirements of EITF 03-1 for investments accounted for under SFAS No. 115 for the year ended December 31, 2003. On September 30, 2004, the FASB issued FSP EITF 03-1-1, “Effective Date of Paragraphs 10-20 of EITF Issue No. 03-1, ‘The Meaning of Other-Than-Temporary Impairment and its Application to Certain Investments,’” which delayed the effective date of the application guidance on impairment of securities included within EITF 03-1. The EITF and the FASB are reconsidering the conclusions reached within EITF 03-1.
SFAS No. 151. In November 2004, the FASB issued FASB Statement No. 151, “Inventory Costs—an amendment of ARB No. 43, Chapter 4” (SFAS No. 151), which is the result of its efforts to converge U.S. accounting standards for inventories with International Accounting Standards. SFAS No. 151 requires abnormal amounts of idle facility expense, freight, handling costs and wasted material or spoilage to be recognized as current-period charges. It also requires that allocation of fixed production overheads to the costs of conversion be based on the normal capacity of the production facilities. SFAS No. 151 will be effective for inventory costs incurred during fiscal years beginning after June 15, 2005. Exelon is assessing the impact SFAS No. 151 will have on its consolidated financial statements.
SFAS No. 123-R. In December 2004, the FASB issued FASB Statement No. 123 (revised 2004), “Share-Based Payment” (SFAS No. 123-R). SFAS No. 123-R replaces SFAS No. 123 and supersedes APB No. 25. SFAS No. 123-R requires that the compensation cost relating to share-based payment transactions be recognized in the financial statements. That cost will be measured based on the fair value of the equity or liability instruments issued. Exelon will no longer be permitted to follow the intrinsic value accounting method of APB No. 25, which resulted in no expense being recorded for stock option grants for which the strike price was equal to the fair value of the underlying stock on the date of grant. Exelon has not elected to early adopt SFAS No. 123-R. As a result, SFAS No. 123-R will be effective for Exelon in the third quarter of 2005 and will apply to all of Exelon’s outstanding unvested share-based payment awards as of July 1, 2005 and all prospective awards. Exelon is assessing the impact SFAS No. 123-R will have on its consolidated financial statements and which of three transition methods allowed by SFAS No. 123-R will be elected.
151
Exelon Corporation and Subsidiary Companies
Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, except per share data unless otherwise noted)
SFAS No. 153. In December 2004, the FASB issued FASB Statement No. 153, “Exchanges of Nonmonetary Assets, an amendment of APB Opinion No. 29, ‘Accounting for Nonmonetary Transactions’” (SFAS No. 153). Previously, APB Opinion No. 29 had required that the accounting for an exchange of a productive asset for a similar productive asset or an equivalent interest in the same or similar productive asset should be based on the recorded amount of the asset relinquished. The amendments made by SFAS No. 153 are based on the principle that exchanges of nonmonetary assets should be measured based on the fair value of the assets exchanged. Further, the amendments eliminate the narrow exception for nonmonetary exchanges of similar productive assets and replace it with a broader exception for exchanges of nonmonetary assets that do not have commercial substance. SFAS No. 153 will be effective for Exelon in the third quarter of 2005 and earlier application is permitted for nonmonetary asset exchanges occurring after the issuance of SFAS No. 153. The provisions of SFAS No. 153 are applied prospectively. Exelon is assessing the impact SFAS No. 153 will have on its consolidated financial statements.
FSP FAS 109-1 and FSP FAS 109-2. In December 2004, the FASB issued FSP FAS 109-1, “Application of FASB Statement No. 109, ‘Accounting for Income Taxes,’ to the Tax Deduction on Qualified Production Activities Provided by the American Jobs Creation Act of 2004” (FSP FAS 109-1) and FSP FAS 109-2, “Accounting and Disclosure Guidance for the Foreign Earnings Repatriation Provisions within the American Jobs Creation Act of 2004” (FSP FAS 109-2). FSP FAS 109-1 and FSP FAS 109-2 were effective upon issuance. The American Jobs Creation Act of 2004 (Act), signed into law on October 22, 2004, provided, generally, for a tax deduction for domestic manufacturing activities of up to nine percent (when fully phased-in) of the lesser of “qualified production activities income,” as defined in the Act, or taxable income. FSP FAS 109-1 clarified that the tax deduction for domestic manufacturing activities under the Act should be accounted for as a special deduction in accordance with SFAS No. 109, “Accounting for Income Taxes” (SFAS No. 109). The Act also provided a special limited-time dividends received deduction on the repatriation of certain foreign earnings to a U.S. taxpayer, provided certain criteria are met. FSP FAS 109-2 provides a registrant more time to evaluate the Act’s impact on the registrant’s plan for reinvestment or repatriation of certain foreign earnings for purposes of applying SFAS No. 109. Exelon is assessing the impact, if any, that the Act and these standards may have on its consolidated financial statements in future periods.
Cumulative Effect of Changes in Accounting Principles
EITF 03-16. In March 2004, the EITF reached a consensus on and the FASB ratified EITF Issue No. 03-16, “Accounting for Investments in Limited Liability Companies” (EITF 03-16). The EITF concluded that if investors in a limited liability company have specific ownership accounts, they should follow the guidance prescribed in Statement of Position 78-9, “Accounting for Investments in Real Estate Ventures,” and EITF Topic No. D-46, “Accounting for Limited Partnership Investments.” Otherwise, investors should follow the significant influence model prescribed in Accounting Principles Board Opinion No. 18, “The Equity Method of Accounting for Investments in Common Stock.” EITF 03-16 was effective for Exelon and its subsidiaries during the third quarter of 2004. Exelon recorded a charge of $9 million (net of an income tax benefit of $5 million) as a cumulative effect of a change in accounting principle in connection with its adoption of EITF 03-16 as of July 1, 2004. This charge related to certain investments in limited liability partnerships held by Enterprises.
FIN 46-R. See discussion of the adoption of FIN 46-R within the “Variable Interest Entities” discussion above.
152
Exelon Corporation and Subsidiary Companies
Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, except per share data unless otherwise noted)
SFAS No. 143. SFAS No. 143 provides accounting guidance for retirement obligations (whether statutory, contractual or as a result of principles of promissory estoppel) associated with tangible long- lived assets. Exelon adopted SFAS No. 143 as of January 1, 2003 and recorded income of $112 million (net of income taxes) as a cumulative effect of a change in accounting principle in connection with its adoption of this standard in the first quarter of 2003. The components of the cumulative effect of a change in accounting principle, net of income taxes, were as follows:
| Generation (net of income taxes of $52) |
$ | 80 | ||
| Generation’s investments in AmerGen and Sithe (net of income taxes of $18) |
28 | |||
| ComEd (net of income taxes of $0) |
5 | |||
| Enterprises (net of income taxes of $(1)) |
(1 | ) | ||
| Total |
$ | 112 | ||
The following tables set forth Exelon’s net income and basic and diluted earnings per common share for the years ended December 31, 2004, 2003 and 2002, adjusted as if SFAS No. 143, FIN 46-R and EITF 03-16 had been applied during those periods. SFAS No. 143, FIN 46-R and EITF 03-16 had adoption dates of January 1, 2003, March 31, 2004 and July 1, 2004, respectively.
| 2004 |
2003 |
2002 |
||||||||||
| Reported income before cumulative effect of changes in accounting principles |
$ | 1,841 | $ | 793 | $ | 1,670 | ||||||
| Pro forma earnings effects (net of income taxes): |
||||||||||||
| EITF 03-16 |
(1 | ) | — | (6 | ) | |||||||
| FIN 46-R |
— | 32 | — | |||||||||
| SFAS No. 143 |
— | — | 27 | |||||||||
| Pro forma income before cumulative effect of changes in accounting principles |
$ | 1,840 | $ | 825 | $ | 1,691 | ||||||
| Reported net income |
$ | 1,864 | $ | 905 | $ | 1,440 | ||||||
| Pro forma earnings effects (net of income taxes): |
||||||||||||
| EITF 03-16 |
(1 | ) | — | (6 | ) | |||||||
| FIN 46-R |
— | 32 | — | |||||||||
| SFAS No. 143 |
— | — | 27 | |||||||||
| Reported cumulative effects of changes in accounting principles: |
||||||||||||
| EITF 03-16 |
9 | — | — | |||||||||
| FIN 46-R |
(32 | ) | — | — | ||||||||
| SFAS No. 143 |
— | (112 | ) | — | ||||||||
| SFAS No. 142 |
— | — | 230 | |||||||||
| Pro forma net income |
$ | 1,840 | $ | 825 | $ | 1,691 | ||||||
153
Exelon Corporation and Subsidiary Companies
Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, except per share data unless otherwise noted)
| 2004 |
2003 |
2002 | |||||||
| Basic earnings per common share: |
|||||||||
| Reported income before cumulative effect of changes in accounting principles |
$ | 2.79 | $ | 1.22 | $ | 2.59 | |||
| Pro forma income before cumulative effect of changes in accounting principles |
$ | 2.79 | $ | 1.27 | $ | 2.62 | |||
| Reported net income |
$ | 2.82 | $ | 1.39 | $ | 2.23 | |||
| Pro forma net income |
$ | 2.79 | $ | 1.27 | $ | 2.62 | |||
| 2004 |
2003 |
2002 | |||||||
| Diluted earnings per common share: |
|||||||||
| Reported income before cumulative effect of changes in accounting principles |
$ | 2.75 | $ | 1.21 | $ | 2.57 | |||
| Pro forma income before cumulative effect of changes in accounting principles |
$ | 2.75 | $ | 1.26 | $ | 2.60 | |||
| Reported net income |
$ | 2.78 | $ | 1.38 | $ | 2.22 | |||
| Pro forma net income |
$ | 2.75 | $ | 1.26 | $ | 2.60 | |||
2. Acquisitions and Dispositions
On December 20, 2004, Exelon entered into an Agreement and Plan of Merger (Merger Agreement) with Public Service Enterprise Group Incorporated (PSEG), a holding company for an electric and gas utility company primarily located and serving customers in New Jersey, whereby PSEG will be merged with and into Exelon (Merger). Under the Merger Agreement, each share of PSEG common stock will be converted into 1.225 shares of Exelon common stock. As of December 31, 2004, PSEG’s market capitalization was over $12 billion. Additionally, PSEG, on a consolidated basis, has approximately $14 billion of outstanding debt which will become part of Exelon’s consolidated debt.
The Merger Agreement contains certain termination rights for both Exelon and PSEG, and further provides that, upon termination of the Merger Agreement under specified circumstances, (i) Exelon may be required to pay PSEG a termination fee of $400 million plus PSEG’s transaction expenses up to $40 million and (ii) PSEG may be required to pay Exelon a termination fee of $400 million plus Exelon’s transaction expenses up to $40 million. The Merger Agreement has been unanimously approved by both companies’ boards of directors but is contingent upon, among other things, the approval by shareholders of both companies, antitrust clearance and a number of regulatory approvals or reviews by Federal and state energy authorities. The parties have made certain of the regulatory filings to obtain necessary regulatory approvals. It is anticipated that this approval process will be completed and the Merger will close within 12 months to 15 months after the announcement of the Merger Agreement in December 2004.
The Merger will be accounted for as a purchase under accounting principles generally accepted in the United States of America. Under the purchase method of accounting, the assets and liabilities of PSEG will be recorded, as of the completion of the Merger, at their respective fair values and added to those of Exelon. The reported financial condition and results of operations of Exelon after completion of the Merger will reflect PSEG’s balances and results after completion of the Merger, but will not be restated retroactively to reflect the historical financial position or results of operations of PSEG.
Exelon has capitalized external costs associated with the Merger since the execution of the Merger Agreement on December 20, 2004. Total capitalized costs as of December 31, 2004 were $10 million. External costs of $7 million incurred prior to the execution of the Merger Agreement were expensed.
Acquisition and Disposition of Generation Entities
Sale of Ownership Interest in Boston Generating, LLC. On May 25, 2004, Generation completed the sale, transfer and assignment of ownership of its indirect wholly owned subsidiary Boston
154
Exelon Corporation and Subsidiary Companies
Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, except per share data unless otherwise noted)
Generating, which owns the companies that own Mystic 4-7, Mystic 8 and 9 and Fore River generating facilities, to a special purpose entity owned by the lenders under Boston Generating’s $1.25 billion credit facility (Boston Generating Credit Facility).
The sale was pursuant to a settlement agreement reached with Boston Generating’s lenders on February 23, 2004. The FERC approved the sale of Boston Generating on May 25, 2004. Responsibility for plant operations and power marketing activities were transferred to the lenders’ special purpose entity on September 1, 2004.
In connection with the settlement reached on February 23, 2004, Exelon, Generation, the lenders and Raytheon Company (Raytheon), the guarantor of the obligations of the turnkey contractor under the projects’ engineering, procurement and construction agreements, entered into a global settlement of all disputes relating to the construction of the Mystic 8 and 9 and Fore River generating facilities.
In connection with the decision to transition out of Boston Generating and the generating units, Exelon recorded during the third quarter of 2003 an impairment charge of long-lived assets pursuant to SFAS No. 144 of $945 million ($573 million net of income taxes) in operating expenses within its Consolidated Statements of Income.
Boston Generating was reported in the Generation segment of Exelon’s consolidated financial statements prior to its sale. At the date of the sale, Boston Generating had approximately $1.2 billion in assets, primarily consisting of property, plant and equipment, and approximately $1.3 billion of liabilities of which approximately $1.0 billion was debt outstanding under the Boston Generating Credit Facility. As of the date of transfer, these amounts were eliminated from Exelon’s Consolidated Balance Sheets. As a result of Boston Generating’s liabilities being greater than its assets at the time of the sale, transfer and assignment of ownership, Exelon recorded a gain of $85 million ($52 million net of income taxes) in other income and deductions within the Consolidated Statements of Income in the second quarter of 2004. In connection with the sale, Exelon recorded a liability associated with an existing guarantee by its subsidiary Exelon New England Holdings, LLC (Exelon New England) of fuel purchase obligations of Boston Generating. Due to the existence of this guarantee and in accordance with SFAS No. 144 and EITF Issue No. 03-13, “Applying the Conditions in Paragraph 42 of FASB Statement No. 144, ‘Accounting for the Impairment or Disposal of Long-Lived Assets,’ in Determining Whether to Report Discontinued Operations” (EITF 03-13), Generation determined that it had retained risk and continuing involvement associated with the operations of Boston Generating and, as a result, the results of Boston Generating have not been classified as a discontinued operation within Exelon’s Consolidated Statements of Income. See Note 20—Commitments and Contingencies for further information regarding the guarantee.
Exelon’s Consolidated Statements of Income include the following results related to Boston Generating:
| 2004 |
2003 |
2002 |
||||||||||
| Operating revenues |
$ | 248 | $ | 618 | $ | 39 | ||||||
| Operating loss (a) |
(49 | ) | (954 | ) | (2 | ) | ||||||
| Income (loss) (b) |
21 | (583 | ) | (3 | ) | |||||||
| (a) | The operating loss in 2003 included an impairment loss of $945 million ($573 million net of income taxes) related to Boston Generating’s long-lived assets. |
| (b) | Net income for 2004 included an after-tax gain of $52 million related to the sale of Boston Generating in the second quarter of 2004. |
155
Exelon Corporation and Subsidiary Companies
Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, except per share data unless otherwise noted)
See Note 4—Selected Pro Forma and Consolidating Financial Information for the effect of the sale of Boston Generating as if the transaction had occurred on January 1, 2003 and was excluded from Exelon’s results from that date.
Sithe. See Note 3—Sithe for information regarding Generation’s investment in Sithe and Note 25—Subsequent Events for information regarding Generation’s sale of Sithe on January 31, 2005.
Acquisition of Sithe International. On October 13, 2004, Generation acquired a 100% interest in Sithe International in exchange for cancellation of a $92 million note. Sithe International, through its subsidiaries, has a 49.5% interest in Termoeléctria del Golfo (TEG) and Termoeléctrica Peñoles (TEP), two generating facilities in Mexico that began commercial operation in the second quarter of 2004. Effective January 26, 2005, Sithe International’s name was changed to Tamuin International, Inc.
AmerGen Energy Company, LLC. On December 22, 2003, Generation purchased British Energy plc’s (British Energy) 50% interest in AmerGen Energy Company, LLC (AmerGen). The resolution of purchase price contingencies related to the valuation of long-lived assets was finalized during the fourth quarter of 2004, reflecting the final purchase price of $267 million after working capital adjustments.
Prior to the purchase, Generation was a 50% owner of AmerGen and had accounted for the investment as an unconsolidated equity method investment. From January 1, 2003 through the date of closing, Generation recorded $47 million ($28 million, net of tax) of equity in earnings of unconsolidated affiliates related to its investment in AmerGen and recorded $382 million of purchased power from AmerGen. The book value of Generation’s investment in AmerGen prior to the purchase was $316 million.
The transaction was accounted for as a step acquisition. As such, upon consolidation, Generation was required to allocate its $316 million book value to 50% of AmerGen’s equity book value. The difference between Generation’s investment in AmerGen and 50% of AmerGen’s equity book value of approximately $227 million was primarily due to Generation not recognizing a significant portion of the cumulative effect of the change in accounting principle at AmerGen related to the adoption of SFAS No. 143. Generation reduced AmerGen’s equity book value through the reduction of the book value of AmerGen’s long-lived assets.
Exelon recorded the acquired assets and liabilities of AmerGen (remaining 50%) at fair value as of the date of purchase. The following assets and liabilities, after final purchase accounting adjustments, reflecting the equity basis and fair value adjustments discussed above, of AmerGen were recorded within Exelon’s Consolidated Balance Sheets as of the date of purchase:
| Current assets (including $36 million of cash acquired) |
$ | 116 | ||
| Property, plant and equipment, including nuclear fuel |
111 | |||
| Nuclear decommissioning trust funds |
1,108 | |||
| Deferred debits and other assets |
30 | |||
| Current liabilities |
(140 | ) | ||
| Asset retirement obligation |
(496 | ) | ||
| Deferred credits and other liabilities |
(106 | ) | ||
| Long-term debt |
(40 | ) | ||
| Total equity |
$ | 583 | ||
156
Exelon Corporation and Subsidiary Companies
Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, except per share data unless otherwise noted)
The assets and liabilities of AmerGen were included in Exelon’s Consolidated Balance Sheets as of December 31, 2004 and 2003, and AmerGen’s results of operations were included in Exelon’s Consolidated Statement of Income for the year ended December 31, 2004.
In connection with the purchase of Unit No. 1 of the Three Mile Island (TMI) facility by AmerGen in 2000, AmerGen entered into an agreement with the seller whereby the seller would receive additional consideration based upon future power purchase prices through 2009. Under the terms of the agreement, approximately $7 million had been accrued at December 31, 2004, which will be payable to the former owner of the TMI facility in the first quarter of 2005. This payment represents contingent consideration for the original acquisition and has accordingly been reflected as an increase to the long-lived assets associated with the TMI facility, and will be depreciated over the remaining useful life of the facility.
Acquisition of Generating Plants from TXU. On April 25, 2002, Generation acquired two natural-gas generation plants with a total of 2,334 MWs of capacity from TXU Corp. (TXU) for an aggregate purchase price of $443 million. Substantially the entire purchase price was allocated to property, plant and equipment. The transaction included a tolling agreement that provided for TXU to purchase power from the plants during the months of May through September from 2002 through 2006. In December 2004, TXU and Generation terminated the original tolling agreement and entered into a new agreement whereby TXU agreed to purchase 1,900 MWs of capacity and related energy/ancillary services from Generation through 2006. Upon termination of the original agreement, Generation received a cash payment of $172 million. The resulting gain was deferred and will be recognized as income over the contractual term of the new agreement.
Disposition of Enterprises Entities
Exelon Thermal Holdings, Inc. On June 30, 2004, Enterprises sold the Chicago businesses of Exelon Thermal Holdings, Inc. (Thermal) for net cash proceeds of $134 million and expected proceeds of $2 million from a working capital settlement, resulting in a pre-tax gain of $45 million. Prior to closing, Enterprises repaid $37 million of related debt, resulting in prepayment penalties of $9 million.
On September 29, 2004, Enterprises sold ETT Nevada, Inc., the holding company for its investment in Northwind Aladdin, LLC, for a net cash outflow of $1 million, resulting in a pre-tax loss of $3 million.
On October 28, 2004, Northwind Windsor, of which Enterprises owned a 50% interest, sold substantially all of its assets, providing Enterprises with cash proceeds of $8 million, resulting in a pre-tax gain of $2 million.
See Assets and Liabilities Held for Sale below for discussion of the classification of the Thermal assets and liabilities as held for sale as of December 31, 2003.
Exelon Services, Inc. During 2004, Enterprises disposed of or wound down all of the operating businesses of Exelon Services, Inc. (Exelon Services), including Exelon Solutions, the mechanical services businesses and the Integrated Technology Group. Total expected proceeds and the net pre-tax gain on sale recorded during 2004 related to these dispositions were $61 million and $9 million, respectively. Pre-tax impairment charges of $5 million and $14 million related to Exelon Services’ tangible assets were recorded in 2004 and 2003, respectively. Exelon Services also recorded a pre-tax
157
Exelon Corporation and Subsidiary Companies
Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, except per share data unless otherwise noted)
charge of $24 million in 2003 to impair its remaining goodwill. As of December 31, 2004, Exelon Services had remaining assets and liabilities of $74 million and $22 million, respectively, which primarily consisted of tax assets, affiliate receivables and payables, and sales proceeds to be collected. See Assets and Liabilities Held for Sale below for information regarding the classification of the assets and liabilities of Exelon Services as held for sale as of December 31, 2003.
PECO TelCove. On June 30, 2004, Enterprises sold its investment in PECO TelCove, a communications joint venture, along with certain telecommunications assets, for proceeds of $49 million. A pre-tax gain of $9 million was recorded in other income and deductions on Exelon’s Consolidated Statements of Income. An impairment charge of $5 million (before income taxes) related to the telecommunications assets had been recorded in the fourth quarter of 2003.
InfraSource. On September 24, 2003, Enterprises sold the electric construction and services, underground and telecom businesses of InfraSource. Cash proceeds to Enterprises from the sale were approximately $175 million, net of transaction costs and cash transferred to the buyer upon sale, plus a $30 million subordinated note receivable maturing in 2011. At the time of closing, the present value of the note receivable was approximately $12 million. The note was collected in full during the second quarter of 2004, resulting in pre-tax income of $18 million. In connection with the transaction, Enterprises entered into an agreement that may result in certain payments to InfraSource if the amount of services Exelon purchases from InfraSource during the period from closing through 2006 is below specified thresholds. Due to Exelon’s ongoing involvement with InfraSource through this agreement and in accordance with SFAS No. 144 and EITF 03-13, the results of InfraSource have not been classified as a discontinued operation within Exelon’s Consolidated Statements of Income.
In connection with the agreement to sell InfraSource, Enterprises recorded an impairment charge during the second quarter of 2003 of approximately $48 million (before income taxes and minority interest) pursuant to SFAS No. 142 related to the goodwill recorded within the InfraSource reporting unit. Management of Enterprises primarily considered the negotiated sales price and the estimated book value of InfraSource at the time of the closing of the sale in determining the amount of the goodwill impairment charge. In connection with the closing of the sale in the third quarter of 2003, Enterprises recorded a pre-tax gain of $44 million, primarily due to the book value of InfraSource at the date of closing being lower than estimated in the second quarter of 2003. The net impact of the goodwill impairment in the second quarter and the gain recorded in the third quarter was a pre-tax loss and minority interest of $4 million for the year ended December 31, 2003. The net impact was recorded as an operating and maintenance expense within the Consolidated Statements of Income.
Sale of Investments. On December 1, 2004, Enterprises sold its limited partnership interest in EnerTech Capital Partners II, L.P. and its limited liability company interests in Kinetic Ventures I, LLC and Kinetic Ventures II, LLC for $8 million in cash and the assumption by the buyers of approximately $10 million in unfunded capital commitments. Prior to the sale, in 2004, these investments were written down to their expected sales price, resulting in pre-tax impairment charges totaling $18 million. As such, there was no net gain or loss recorded associated with the sale.
Sale of Investment in AT&T Wireless. On April 1, 2002, Enterprises sold its 49% interest in AT&T Wireless PCS of Philadelphia, LLC to a subsidiary of AT&T Wireless Services for $285 million in cash. Exelon recorded a pre-tax gain of $198 million ($116 million net of income taxes) on the $84 million investment in other income and deductions on its Consolidated Statements of Income.
158
Exelon Corporation and Subsidiary Companies
Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, except per share data unless otherwise noted)
The results of Thermal and Exelon Services have been included in income from continuing operations within Exelon’s Consolidated Statements of Income (as opposed to discontinued operations) as the impact on Exelon’s consolidated financial statements was not significant.
Investments in Synthetic Fuel-Producing Facilities
Synthetic fuel-producing facilities chemically change coal, including waste and marginal coal, into a fuel used at power plants. Section 29 of the Internal Revenue Code provides that tax credits are available for the production of this synthetic fuel.
In November 2003, Exelon purchased interests in two synthetic fuel-producing facilities. The purchase price for these facilities included a combination of cash, notes payable and contingent consideration dependent upon the production level of the facilities. The notes payable recorded for the purchase of the facilities were $238 million. Exelon’s right to acquire a fixed amount of tax credits generated by the facilities was recorded as an intangible asset which is amortized as the tax credits are earned.
In July 2004, Exelon purchased an interest in a limited partnership that indirectly owns four synthetic fuel-producing facilities. Exelon’s purchase price for these facilities included a combination of a note payable and contingent consideration dependent upon the production levels of the facilities. The note payable recorded for the purchase of the facilities was $22 million. Exelon’s right to acquire a fixed amount of tax credits generated by the facilities was recorded as an intangible asset which is amortized as these tax credits are earned.
Private letter rulings have been received that affirm that the process used by the facilities will produce a solid synthetic fuel that qualifies for tax credits under Section 29 of the Internal Revenue Code.
Tax credits generated by the production of synthetic fuel are subject to a phase-out provision that gradually reduces tax credits as the annual average wellhead price per barrel of domestic crude oil increases into an inflation-adjusted phase-out range. For 2003, the tax credit would have begun to phase out when the annual average wellhead price per barrel of domestic crude oil exceeded $50.14 and would have been completely phased out when the annual average wellhead price per barrel of domestic crude oil reached $62.94. The 2004 and 2005 phase-out range will be calculated using inflation rates published in 2005 and 2006, respectively, by the Internal Revenue Service.
If domestic crude oil prices remain high in 2005, the tax credits and net income generated by the investments may be reduced substantially. The intangible asset recorded by Exelon related to its investments in these facilities could become impaired if domestic crude oil prices continue to increase in the future. See Note 9—Intangible Assets for additional information regarding the intangible assets.
Exelon’s investments in synthetic fuel-producing facilities increased net income by $70 million and $5 million in 2004 and 2003, respectively. The increase in net income is reflected in the Consolidated Statements of Income as a benefit within income taxes, partially offset by charges to operating and maintenance expense, depreciation and amortization expense, interest expense and equity in losses of unconsolidated affiliates. See Note 13—Income Taxes for information regarding the effect of these investments on Exelon’s effective income tax rate.
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Exelon Corporation and Subsidiary Companies
Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, except per share data unless otherwise noted)
Investments in Affordable Housing
On October 15, 2004 and November 12, 2004, Exelon sold investments in affordable housing for total proceeds of $78 million and recognized a net gain on sale of $4 million before income taxes. Of the total proceeds, $2 million is being held in escrow pending possible purchase price adjustments.
Assets and Liabilities Held for Sale
There were no assets or liabilities classified as held for sale as of December 31, 2004. The major classes of assets and liabilities classified as held for sale within Exelon’s Consolidated Balance Sheet as of December 31, 2003 consisted of the following:
| December 31, 2003 |
Generation |
Enterprises |
Total | ||||||
| Cash |
$ | — | $ | 11 | $ | 11 | |||
| Accounts receivable, net |
— | 59 | 59 | ||||||
| Other current assets |
— | 24 | 24 | ||||||
| Property, plant and equipment, net |
— | 86 | 86 | ||||||
| Other long-term assets |
36 | 26 | 62 | ||||||
| Total assets classified as held for sale |
$ | 36 | $ | 206 | $ | 242 | |||
| December 31, 2003 |
Generation |
Enterprises |
Total | ||||||
| Accounts payable, accrued expenses and other current liabilities |
$ | — | $ | 44 | $ | 44 | |||
| Debt |
— | 1 | 1 | ||||||
| Asset retirement obligation |
— | 3 | 3 | ||||||
| Other long-term liabilities |
— | 13 | 13 | ||||||
| Total liabilities classified as held for sale |
$ | — | $ | 61 | $ | 61 | |||
Generation. Generation classified three gas turbines with a book value of $36 million as held for sale as of December 31, 2003. The turbines were sold during the first quarter of 2004 for proceeds of $42 million, resulting in a gain of $6 million. In anticipation of their sale in 2004, these turbines had been classified as other long-term assets as they had not been placed into service.
Enterprises. As of December 31, 2003, the assets and liabilities of certain entities of Thermal and Exelon Services were classified as held for sale. The assets and liabilities of Thermal classified as held for sale were $120 million and $18 million, respectively, at December 31, 2003. The assets and liabilities of Exelon Services classified as held for sale were $86 million and $43 million, respectively, at December 31, 2003. Enterprises recognized impairment charges totaling $14 million (before income taxes) under SFAS No. 144 related to the assets of Exelon Services that were classified as held for sale during the year ended December 31, 2003. These assets and liabilities were reported under the Enterprises segment in Note 22—Segment Information. See “Disposition of Enterprises Entities” above for information regarding the disposition of these businesses in 2004.
3. Sithe
Sithe is primarily engaged in the ownership and operation of electric wholesale generating facilities in North America. At December 31, 2004, Sithe operated nine power units with total average net
160
Exelon Corporation and Subsidiary Companies
Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, except per share data unless otherwise noted)
capacity of 1,323 MWs. Described below is a series of transactions in 2004 and 2003 involving Generation’s investment in Sithe that ultimately resulted in the sale of Generation’s ownership interest in Sithe to a third party on January 31, 2005. See Note 25—Subsequent Events for a further discussion of the sale transaction.
Exercise of Call Option and Subsequent Agreement to Sell. On November 25, 2003, Generation, Reservoir Capital Group (Reservoir) and Sithe completed a series of transactions resulting in Generation and Reservoir each indirectly owning a 50% interest in Sithe (Generation owned 49.9% prior to November 25, 2003). See below for further details regarding these 2003 transactions.
Both Generation’s and Reservoir’s 50% interests in Sithe were subject to put and call options. On September 29, 2004, Generation exercised its call option and entered into an agreement to acquire Reservoir’s 50% interest in Sithe for $97 million. On November 1, 2004, Generation entered into an agreement to sell Sithe to Dynegy Inc. (Dynegy) for $135 million in cash. On January 31, 2005, Generation completed the closing of the call exercise and the sale of the resulting 100% interest in Sithe. The sale did not include Sithe International, Inc., which was sold to a subsidiary of Generation in a separate transaction described below.
Acquisition of Sithe International, Inc. Sithe International, through its subsidiaries, has 49.5% interests in two Mexican business trusts that own the TEG and TEP power stations, two 230 MW petcoke-fired generating facilities in Tamuín, Mexico that commenced commercial operations in the second quarter of 2004. On October 13, 2004, Sithe transferred all of the shares of Sithe International, Inc. and its subsidiaries to a subsidiary of Generation in exchange for cancellation of a $92 million note, which is eliminated as part of the consolidation of Sithe. Effective January 26, 2005, Sithe International’s name was changed to Tamuin International Inc.
2003 Transactions. On November 25, 2003, Generation, Reservoir and Sithe completed a series of transactions resulting in Generation and Reservoir each indirectly owning a 50% interest in Sithe. Immediately prior to these transactions, Sithe was owned 49.9% by Generation, 35.2% by Apollo Energy, LLC (Apollo), and 14.9% by subsidiaries of Marubeni Corporation (Marubeni).
On November 25, 2003, entities controlled by Reservoir purchased certain Sithe entities holding six U.S. generating facilities, each a qualifying facility under the Public Utility Regulatory Policies Act, in exchange for $37 million ($21 million in cash and a $16 million two-year note); and entities controlled by Marubeni purchased all of Sithe’s entities and facilities outside of North America (other than Sithe Energies Australia (SEA) of which it purchased a 49.9% interest on November 24, 2003 and the remaining 50.1% interest on May 27, 2004 for separate consideration) for $178 million.
Following the sales of the above entities, Generation transferred its wholly owned subsidiary that held the Sithe investment to a newly formed holding company, EXRES SHC, Inc. The subsidiary holding the Sithe investment acquired the remaining Sithe interests from Apollo and Marubeni for $612 million using proceeds from a $580 million bridge financing and available cash. Generation sold a 50% interest in the newly formed holding company for $76 million to an entity controlled by Reservoir on November 25, 2003. On November 26, 2003, Sithe distributed $580 million of available cash to its parent, which then utilized the distributed funds to repay the bridge financing.
Guarantees. In connection with the 2003 transactions, Generation recorded obligations related to $39 million of guarantees in accordance with FIN 45. These guarantees were issued to protect
161
Exelon Corporation and Subsidiary Companies
Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, except per share data unless otherwise noted)
Reservoir from credit exposure of certain counter-parties through 2015 and other indemnities. In determining the value of the FIN 45 guarantees, Generation utilized probabilistic models to assess the possibilities of future payments under the guarantees. These guarantees were reversed upon the consolidation of Sithe in accordance with FIN 45 as this liability was associated with guarantees for the performance of a consolidated entity. The consolidation of Sithe in accordance with FIN 46-R resulted in Exelon recording income of $32 million (net of income taxes), which included the reversal of the aforementioned guarantees, as a cumulative effect of a change in accounting principle during the first quarter of 2004.
Accounting Prior to the Consolidation of Sithe on March 31, 2004. Generation had accounted for the investment in Sithe as an unconsolidated equity method investment prior to its consolidation on March 31, 2004 pursuant to FIN 46-R. See Note 1—Significant Accounting Policies for further discussion. In 2003, Generation recorded impairment charges of $255 million (before income taxes) in other income and deductions within the Consolidated Statements of Income associated with a decline in the fair value of the Sithe investment, which was considered to be other-than-temporary. Generation’s management considered various factors in the decision to impair this investment, including management’s negotiations to sell its interest in Sithe. The discussions surrounding the sale indicated that the fair value of the Sithe investment was below its book value and, as such, impairment charges were required.
The book value of Generation’s investment in Sithe immediately prior to its consolidation on March 31, 2004 was $49 million. For the year ended December 31, 2004, Exelon recorded $2 million of equity method losses from Sithe prior to its consolidation. For the year ended December 31, 2003 and 2002, Exelon recorded $2 million and $23 million of equity method income, respectively, related to its investment in Sithe.
Consolidation of Sithe as of March 31, 2004. As a result of the 2003 transactions referred to above, the consolidation of Sithe at March 31, 2004 was accounted for as a step acquisition pursuant to purchase accounting policies. Under the provisions of FIN 46-R, the operating results of Sithe were included in Exelon’s results of operations beginning April 1, 2004.
The condensed consolidating financial information included in Note 4—Selected Pro Forma and Consolidating Financial Information (Unaudited) presents the financial position of Exelon and Sithe, as well as consolidating entries related primarily to acquisition notes payables and receivables between Exelon and Sithe.
Intangible Assets. Sithe had entered into a tolling arrangement (Tolling Agreement) with Dynegy Power Marketing and its affiliates with respect to Sithe’s Independence Station. The Tolling Agreement commenced on July 1, 2001 and runs through 2014. Additionally, Sithe has entered into an energy purchase agreement (Energy Purchase Agreement) with a counterparty relating to the Independence Station, which continues through 2014. As a result of the acquisition accounting described above, values were assigned to the Tolling Agreement and the Energy Purchase Agreement of approximately $73 million and $384 million, respectively, which have been recorded as intangible assets on Exelon’s Consolidated Balance Sheets in deferred debits and other assets. These amounts were determined based on fair value techniques utilizing the contract terms and various other estimates including forward power prices, discount rates and option pricing models.
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Exelon Corporation and Subsidiary Companies
Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, except per share data unless otherwise noted)
The intangible assets representing the Tolling Agreement and the Energy Purchase Agreement are being amortized on a straight-line basis over the lives of the associated agreements. See Note 9—Intangible Assets for further information regarding Exelon’s intangible assets.
Long-Term Debt and Letters of Credit. Substantially all of Sithe’s property, plant and equipment and project agreements secure Sithe’s outstanding long-term debt, which consists primarily of project debt. During 2003, Sithe entered into an agreement with Exelon and Generation under which Exelon obtained letters of credit to support contractual obligations of Sithe and its subsidiaries. As of December 31, 2004, Exelon had obtained $61 million of letters of credit in support of Sithe’s obligations not including a $50 million letter of credit that is not guaranteed by Exelon. With the exception of the issuance of letters of credit to support contractual obligations, the creditors of Sithe have no recourse against the general credit of Exelon or Generation.
4. Selected Pro Forma and Consolidating Financial Information (Unaudited)
The following unaudited pro forma financial information gives effect to the acquisition on December 22, 2003 of the remaining 50% interest in AmerGen by Generation and the sale of Boston Generating by Generation on May 25, 2004, in each case, as if the transaction had occurred on January 1, 2003.
| 2004 |
Exelon As Reported |
Sale of Boston Generating |
Eliminating Entries |
Pro Forma Exelon | ||||||||
| Total operating revenues |
$14,515 | $248 | $— | $14,267 | ||||||||
| Operating income (loss) |
3,433 | (49 | ) | — | 3,482 | |||||||
| Income before cumulative effect of changes in accounting principles |
1,841 | 21 | — | 1,820 | ||||||||
| 2003 |
Exelon As Reported |
Acquisition of 50% of AmerGen |
Sale of Boston Generating |
Eliminating Entries(a) |
Pro Forma Exelon | |||||||
| Total operating revenues | $15,812 | $623 | $618 | $(382 | ) | $15,435 | ||||||
| Operating income (loss) | 2,277 | 99 | (954 | ) | — | 3,330 | ||||||
| Income (loss) before cumulative effect of changes in accounting principles |
793 | 89 | (583 | ) | (47 | ) | 1,418 | |||||
| (a) | Represents the elimination of intercompany revenues at AmerGen and equity in earnings from AmerGen in 2003. |
The above unaudited pro-forma financial information should not be relied upon as being indicative of the historical results that would have been obtained if the transactions had actually occurred in prior periods nor of the results that might be obtained in the future.
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Exelon Corporation and Subsidiary Companies
Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, except per share data unless otherwise noted)
Condensed Consolidating Balance Sheet at December 31, 2004
The following condensed consolidating financial information presents the financial position of Exelon and Sithe, as well as eliminating entries, related primarily to acquisition notes payable and receivables between Generation and Sithe.
| December 31, 2004 |
Pro Forma Exelon |
Sithe |
Eliminating Entries |
Exelon As Reported | |||||||||
| Assets |
|||||||||||||
| Current assets |
$ | 3,951 | $ | 336 | $ | (361 | ) | $ | 3,926 | ||||
| Property, plant and equipment, net |
21,212 | 270 | — | 21,482 | |||||||||
| Other noncurrent assets |
16,643 | 750 | (31 | ) | 17,362 | ||||||||
| Total assets |
$ | 41,806 | $ | 1,356 | $ | (392 | ) | $ | 42,770 | ||||
| Liabilities and shareholders’ equity |
|||||||||||||
| Current liabilities |
$ | 4,920 | $ | 323 | $ | (361 | ) | $ | 4,882 | ||||
| Long-term debt |
11,363 | 785 | — | 12,148 | |||||||||
| Other long-term liabilities (a) |
16,013 | 181 | 36 | 16,230 | |||||||||
| Shareholders’ equity (b) |
9,510 | 67 | (67 | ) | 9,510 | ||||||||
| Total liabilities and shareholders’ equity |
$ | 41,806 | $ | 1,356 | $ | (392 | ) | $ | 42,770 | ||||
| (a) | Includes minority interest in consolidated subsidiaries. |
| (b) | Includes preferred securities of subsidiaries. |
5. Regulatory Issues
Energy Delivery
PJM Integration. On June 2, 2003, ComEd began receiving electric transmission reservation services from PJM Interconnection, LLC (PJM) and transferred control of ComEd’s Open Access Same Time Information System to PJM. On April 27, 2004, the FERC issued its order approving ComEd’s application to complete its integration into PJM, subject to certain stipulations, including a provision to hold certain utilities in Michigan and Wisconsin harmless from the associated impacts for ComEd to join PJM. ComEd agreed to these stipulations and fully integrated its transmission facilities into PJM on May 1, 2004. In the fourth quarter of 2004, ComEd entered into settlement agreements with all such Michigan and Wisconsin utilities requiring a total payment of approximately $4 million by ComEd. FERC has approved these agreements and payment is expected to be made in the first quarter of 2005.
Through and Out Rates. In November 2004, the FERC issued two orders authorizing ComEd and PECO to recover from various entities revenue representing amounts ComEd and PECO will lose as a result of the elimination of through and out (T&O) charges, for energy flowing across ComEd’s and PECO’s transmission systems, that were terminated pursuant to the FERC orders effective December 1, 2004. The collection of this revenue will be over a transitional period of December 1, 2004 through March 31, 2006. Several parties have sought rehearing of the FERC orders and there likely will be appeals filed in the matter after the rehearing order is issued. During 2004 prior to the termination of T&O charges, ComEd and PECO collected net T&O charges of approximately $50 million and $3 million, respectively. As a result of this proceeding, ComEd may see reduced net collections, and PECO may be come a net payer of these charges. The ultimate outcome of this proceeding is uncertain and may have a material adverse effect on ComEd’s and PECO’s financial condition, results of operations or cash flows.
164
Exelon Corporation and Subsidiary Companies
Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, except per share data unless otherwise noted)
Delivery Service Rates. On March 3, 2003, ComEd entered into, and the ICC subsequently entered orders to implement, an agreement (Agreement) with various Illinois retail market participants and other interested parties that settled, among other things, delivery service rates and the market value index proceeding and facilitates competitive service declarations for large-load customers and an extension of ComEd’s PPA with Generation. The effect of the Agreement is to lower competitive transition charge (CTC) collections that ComEd receives from customers who take electricity from an alternative electric supplier or under the purchase power option (PPO) through 2006. The Agreement also allows customers to lock in current CTCs for multiple years. In 2004 and 2003, ComEd collected $169 million and $304 million in CTC revenues, respectively.
In 2003, ComEd recorded a charge to earnings associated with the required funding of specified programs and initiatives associated with the Agreement of $51 million (before income taxes) on a present value basis. This amount was partially offset by the reversal of a $12 million (before income taxes) reserve established in the third quarter of 2002 for a potential capital disallowance in ComEd’s delivery services rate proceeding and a credit of $10 million (before income taxes) related to the capitalization of employee incentive payments provided for in the delivery services order. The charge of $51 million and the credit of $10 million were recorded in operating and maintenance expense and the reversal of the $12 million reserve was recorded in other, net within Exelon’s Consolidated Statements of Income. The net charge for these items was $29 million (before income taxes). In accordance with the Agreement, ComEd made payments of $10 million and $23 million during 2004 and 2003, respectively.
Customer Choice. All ComEd’s retail customers are eligible to choose an alternative electric supplier and most non-residential customers may also buy electricity from ComEd at market-based prices under the PPO. No alternative electric supplier has approval from the ICC, and no electric utilities have chosen, to serve ComEd’s residential customers. As of December 31, 2004, approximately 22,100 non-residential customers, or 35% of ComEd’s annual retail kilowatthour sales, had elected either the PPO or an alternative electric supplier. Customers who receive energy from an alternative supplier continue to pay a delivery charge.
All PECO customers may choose to purchase energy from an alternative electric supplier. As of December 31, 2004, approximately 101,500 customers, representing approximately 8% of PECO’s annual kilowatthour sales, had elected to purchase their electric energy from an alternative electric supplier. Customers who receive energy from an alternative electric supplier continue to pay delivery charges and CTCs.
Competitive Service Declarations. On November 14, 2002, the ICC allowed ComEd, by operation of law, to revise its provider of last resort obligation to be the back-up energy supplier at market-based rates for certain customers with energy demands of at least three MWs. About 370 of ComEd’s largest energy customers are affected, representing an aggregate supply obligation or load of approximately 2,500 MWs. These customers will not have a right to take bundled service after June 2006 or to return to bundled rates if they choose an alternative supplier prior to June 2006.
On March 28, 2003, the ICC approved changes to ComEd’s real-time pricing tariff for non-residential customers, including those with energy demands of at least three MWs, who choose hourly energy supply for their electric power and energy. The ICC orders were affirmed on appeal.
Exelon cannot predict the long-term impact of customer choice and customer service declarations on its results of operations.
165
Exelon Corporation and Subsidiary Companies
Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, except per share data unless otherwise noted)
Rate Reductions and Return on Common Equity Threshold. The Illinois restructuring legislation, as amended, required a 15% residential base rate reduction effective August 1, 1998 and an additional 5% residential base rate reduction effective October 1, 2001. In addition, a base rate freeze, reflecting the residential base rate reduction, is in effect through January 1, 2007. A utility may request a rate increase during the rate freeze period only when necessary to ensure the utility’s financial viability. Under the Illinois legislation, if the two-year average of the earned return on common equity of a utility through December 31, 2006 exceeds an established threshold, one-half of the excess earnings must be refunded to customers. The threshold rate of return on common equity is based on a two-year average of the Monthly Treasury Bond Long-Term Average Rates (20 years and above) plus 8.5% in the years 2000 through 2006. Earnings for purposes of ComEd’s threshold include ComEd’s net income calculated in accordance with GAAP and reflect the amortization of regulatory assets. Under Illinois statute, any impairment of goodwill would have no impact on the determination of the cap on ComEd’s allowed equity return during the transition period. As a result of the Illinois legislation, at December 31, 2004, ComEd had a regulatory asset related to recoverable transition costs with an unamortized balance of $87 million that it expects to fully recover and amortize by the end of 2006. Consistent with the provisions of the Illinois legislation, regulatory assets may be recovered in amounts that provide ComEd an earned return on common equity within the Illinois legislation earnings threshold. ComEd has not triggered the earnings sharing provision through 2004.
Rate limitations. Pursuant to a settlement agreement related to the merger of Exelon, Unicom Corporation and PECO on October 20, 2000 (PECO/Unicom Merger) with the PUC, PECO is subject to agreed-upon electric service rate reductions of $200 million, in aggregate, for the period January 1, 2002 through December 31, 2005, including $40 million in each of 2004 and 2005. As required by the 1998 electric restructuring settlement and as modified by the PECO / Unicom Merger-related settlement agreement, PECO is subject to rate caps (subject to limited exceptions for significant increases in Federal or state income taxes or other significant changes in law or regulation that do not allow PECO to earn a fair rate of return) on its transmission and distribution rates through December 31, 2006, and on its energy rates through December 31, 2010.
Nuclear Decommissioning Costs. In connection with the transfer of ComEd’s nuclear generating stations to Generation, the ICC permitted ComEd to recover $73 million per year from retail customers for decommissioning for the years 2001 through 2004 and, depending upon the portion of the output from those stations taken by ComEd, up to $73 million annually in 2005 and 2006. Because ComEd is not expected to take all of the output of these stations, actual collections are expected to be less than $73 million annually in 2005 and 2006. Subsequent to 2006, there will be no further recoveries of decommissioning costs from customers. Any surplus funds after a nuclear station is decommissioned must be refunded to ComEd’s customers. The amounts collected by ComEd from retail customers are remitted to Generation. See Note 14—Nuclear Decommissioning and Spent Fuel Storage.
Effective January 1, 2004, the PUC approved an adjustment to PECO’s nuclear decommissioning cost adjustment clause permitting PECO to recover an additional $3.6 million annually, or $33 million compared to $29 million previously. The amounts recovered by PECO are remitted to Generation upon collection.
Open Access Transmission Tariff. On November 10, 2003, the FERC issued an order allowing ComEd to put into effect, subject to refund and rehearing, new transmission rates designed to reflect nearly $500 million of infrastructure investments made since 1998; however, because of the Illinois retail rate freeze and the method for calculating CTCs, the increase is not expected to significantly
166
Exelon Corporation and Subsidiary Companies
Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, except per share data unless otherwise noted)
increase operating revenues until December 31, 2006. During the third quarter of 2004, a settlement agreement was reached which was approved by the FERC during the fourth quarter of 2004, which established new rates that became effective May 1, 2004.
Generation
Service Life Extension. Upon the December 2003 acquisition of the remaining 50% interest in AmerGen, Generation changed its accounting estimates related to the depreciation of certain AmerGen generating facilities to conform with Generation’s depreciation policies. The estimated service lives were extended by 20 years for the three AmerGen stations. These changes were based on engineering and economic feasibility analyses performed by Generation. The service life extensions are subject to approval by the Nuclear Regulatory Commission (NRC) of renewals of the existing NRC operating licenses. Generation has not applied for license renewals at the AmerGen facilities, but has announced its plan to file a renewal request in 2005 for the Oyster Creek Nuclear Generating Station (Oyster Creek), and is planning on filing for license renewals for TMI Unit 1 and the Clinton Nuclear Power Station (Clinton) on a timeline consistent and integrated with the other planned license renewal filings for the Generation nuclear fleet.
License Renewals. In December 2004, the NRC issued an order that will permit Oyster Creek to operate beyond its license expiration in April 2009 if the NRC has not completed reviewing the application for renewal. The application for Oyster Creek’s license renewal is anticipated to be filed by August 2005 in order to comply with this agreement. On October 28, 2004, the NRC approved 20-year renewals of the operating licenses for Generation’s Dresden and Quad Cities generating stations. The licenses for Dresden Unit 2, Dresden Unit 3 and Quad Cities Units 1 and 2 were renewed to 2029, 2031 and 2032, respectively. On May 7, 2003, the operating licenses for Peach Bottom Unit 2 and Peach Bottom Unit 3 were renewed to 2033 and 2034, respectively. Depreciation provisions are based on the estimated useful lives of the stations, which assumes the renewal of these licenses for all nuclear generating stations. As a result, these license renewals had no impact on the Consolidated Statements of Income.
6. Accounts Receivable
Customer accounts receivable at December 31, 2004 and 2003 included unbilled revenues related to unread meters for Energy Delivery and Exelon Energy Company customers of $482 million and $452 million, respectively. Also included in customer accounts receivable was $385 million and $366 million at December 31, 2004 and 2003, respectively, related to Generation’s unbilled revenues for amounts of energy delivered to customers in the month of December. The allowance for uncollectible accounts at December 31, 2004 and 2003 was $93 million and $110 million, respectively.
PECO is party to an agreement with a financial institution under which it can sell or finance with limited recourse an undivided interest, adjusted daily, in up to $225 million of designated accounts receivable until November 2005. At December 31, 2004, PECO had sold a $225 million interest in accounts receivable, consisting of a $179 million interest in accounts receivable which PECO accounted for as a sale under SFAS No. 140, “Accounting for Transfers and Servicing of Financial Assets and Extinguishment of Liabilities—a Replacement of FASB Statement No. 125,” (SFAS No. 140) and a $46 million interest in special-agreement accounts receivable which was accounted for as a long-term note payable and reflected on the consolidated balance sheet as long-term debt due within one year. At December 31, 2003, PECO had sold a $225 million interest in accounts receivable,
167
Exelon Corporation and Subsidiary Companies
Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, except per share data unless otherwise noted)
consisting of a $176 million interest in accounts receivable which PECO accounted for as a sale under SFAS No. 140 and a $49 million interest in special-agreement accounts receivable which was accounted for as a long-term note payable (see Note 12—Long-Term Debt). PECO retains the servicing responsibility for these receivables. The agreement requires PECO to maintain the $225 million interest, which, if not met, requires cash, which would otherwise be received by PECO under this program, to be held in escrow until the requirement is met. At December 31, 2004 and 2003, PECO met this requirement and was not required to make any cash deposits.
7. Property, Plant, and Equipment
A summary of property, plant and equipment by asset category as of December 31, 2004 and 2003 is as follows:
| Asset Category |
2004 |
2003 | ||||
| Electric—transmission and distribution |
$ | 13,479 | $ | 12,644 | ||
| Electric—generation |
7,125 | 7,968 | ||||
| Gas—transmission and distribution |
1,436 | 1,381 | ||||
| Common |
501 | 492 | ||||
| Nuclear fuel |
2,926 | 2,568 | ||||
| Construction work in progress |
593 | 862 | ||||
| Asset retirement cost |
1,024 | 203 | ||||
| Other property, plant and equipment (a) |
1,627 | 1,549 | ||||
| Total property, plant and equipment |
28,711 | 27,667 | ||||
| Less accumulated depreciation (including accumulated amortization of nuclear fuel of $1,976 and $1,596 as of December 31, 2004 and 2003, respectively) |
7,229 | 7,037 | ||||
| Property, plant and equipment, net |
$ | 21,482 | $ | 20,630 | ||
| (a) | Includes buildings under capital lease with a net carrying value of $43 million and $46 million at December 31, 2004 and 2003, respectively. The original cost basis of the buildings was $53 million and total accumulated amortization was $10 million and $7 million at December 31, 2004 and 2003, respectively. |
Energy Delivery’s depreciation expense, which is included in cost of service for rate purposes, includes the estimated cost of dismantling and removing plant from service upon retirement. Beginning in 2003, in accordance with new interpretations of regulatory accounting practice, collections for future removal costs are recorded as a regulatory liability. For more information, see Note 21—Supplemental Financial Information.
Effective July 1, 2002, ComEd decreased its depreciation rates based on a new depreciation study reflecting its significant construction program in recent years, changes in and development of new technologies, and changes in estimated plant service lives since the last depreciation study. The annualized reduction in depreciation expense was $96 million.
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Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, except per share data unless otherwise noted)
8. Jointly Owned Electric Utility Plant
Exelon’s undivided ownership interests in jointly owned electric plant at December 31, 2004 and 2003 were as follows:
| Nuclear generation |
Fossil fuel generation |
Transmission/ Other | |||||||||||||||||||
| Quad Cities |
Peach Bottom |
Salem (a) |
Keystone |
Conemaugh |
Wyman |
||||||||||||||||
| PSEG | |||||||||||||||||||||
| Operator |
Generation | Generation | Nuclear | Reliant | Reliant | FP&L | (b,c) | ||||||||||||||
| Ownership interest |
75.00% | 50.00% | 42.59% | 20.99% | 20.72% | 5.89% | (b,c) | ||||||||||||||
| Exelon’s share at December 31, 2004: |
|||||||||||||||||||||
| Plant |
$ | 287 | $ | 438 | $ | 127 | $ | 167 | $ | 212 | $ | 2 | $ | 61 | |||||||
| Accumulated depreciation |
54 | 231 | 33 | 102 | 133 | — | 27 | ||||||||||||||
| Construction work in progress |
39 | 16 | 81 | 5 | 1 | — | — | ||||||||||||||
| Exelon’s share at December 31, 2003: |
|||||||||||||||||||||
| Plant |
$ | 191 | $ | 453 | $ | 106 | $ | 168 | $ | 210 | $ | 2 | $ | 61 | |||||||
| Accumulated depreciation |
18 | 239 | 24 | 106 | 138 | — | 26 | ||||||||||||||
| Construction work in progress |
40 | 1 | 48 | 2 | 1 | — | — | ||||||||||||||
| (a) | Generation also owns a proportionate share in the fossil fuel combustion turbine, which is fully depreciated. The gross book value was $3 million at December 31, 2004 and 2003. |
| (b) | PECO has a 22.00% ownership of 127 miles of 500,000 voltage lines located in Pennsylvania and a 42.55% ownership of 151 miles of 500,000 voltage lines located in Delaware and New Jersey. |
| (c) | Generation has a 44.24% ownership interest in Merrill Creek Reservoir located in New Jersey with a book value of $1 million at December 31, 2004 and 2003. |
Exelon’s undivided ownership interests are financed with Exelon funds and all operations are accounted for as if such participating interests were wholly owned facilities. Exelon’s share of direct expenses of the jointly owned plants is included in the corresponding operating expenses on the Consolidated Statements of Income.
9. Intangible Assets
Goodwill
Adoption of SFAS No. 142. Effective January 1, 2002, Exelon adopted SFAS No. 142. Pursuant to SFAS No. 142, goodwill is no longer amortized; however, in addition to an initial assessment, goodwill is subject to an assessment for impairment at least annually, or more frequently, if events or circumstances indicate that goodwill might be impaired. The impairment assessment is performed using a two-step, fair-value based test. The first step compares the fair value of the reporting unit to its carrying amount, including goodwill. If the carrying amount of the reporting unit exceeds its fair value, the second step is performed. The second step compares the carrying amount of the goodwill to the estimated fair value of the goodwill. If the fair value of goodwill is less than the carrying amount, an impairment loss is reported as a reduction to goodwill and a charge to operating expense.
As of December 31, 2001, Exelon’s Consolidated Balance Sheets reflected approximately $5.3 billion in goodwill net of accumulated amortization, including $4.9 billion of goodwill, net of accumulated
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Exelon Corporation and Subsidiary Companies
Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, except per share data unless otherwise noted)
amortization, related to the PECO / Unicom Merger recorded on ComEd’s Consolidated Balance Sheets, with the remainder related to Enterprises. The first step of the transitional impairment analysis indicated that Energy Delivery’s goodwill was not impaired but that an impairment did exist with respect to goodwill recorded in Enterprises’ reporting units. The second step of the analysis, which compared the fair value of each of Enterprises’ reporting units’ goodwill to the carrying value at December 31, 2001, indicated a total goodwill impairment of $357 million ($243 million, net of income taxes and minority interest). The fair value of Enterprises’ reporting units was determined using discounted cash flow models reflecting the expected range of future cash flow outcomes related to each of Enterprises’ reporting units over the life of the investment. These cash flows were discounted to 2002 using a risk-adjusted discount rate.
The components of the net transitional impairment loss recognized in the first quarter of 2002 as a cumulative effect of a change in accounting principle were as follows:
| Enterprises goodwill impairment (net of income taxes of ($95)) |
$ | (243 | ) | |
| Exelon Energy’s goodwill impairment (net of income taxes of ($8)) |
(11 | ) | ||
| Minority interest (net of income taxes of $4) |
11 | |||
| Elimination of AmerGen negative goodwill (net of income taxes of $9) |
13 | |||
| Total cumulative effect of a change in accounting principle |
$ | (230 | ) | |
Accounting Methodology Under SFAS No. 142. The changes in the carrying amount of goodwill by reportable segment (see Note 22—Segment Information) for the years ended December 31, 2003 and 2004 were as follows:
| Energy Delivery |
Enterprises |
Total |
||||||||||
| Balances as of January 1, 2003 |
$ | 4,916 | $ | 76 | $ | 4,992 | ||||||
| Impairment losses |
— | (72 | ) | (72 | ) | |||||||
| Adoption of SFAS No. 143: (a) |
||||||||||||
| Reduction of asset retirement obligation |
(210 | ) | — | (210 | ) | |||||||
| Cumulative effect of change in accounting principle |
5 | — | 5 | |||||||||
| Resolution of certain tax matters |
8 | — | 8 | |||||||||
| Other |
— | (4 | ) | (4 | ) | |||||||
| Balances as of January 1, 2004 |
4,719 | — | 4,719 | |||||||||
| Resolution of certain tax matters |
(9 | ) | — | (9 | ) | |||||||
| PECO / Unicom Merger severance adjustments |
(5 | ) | — | (5 | ) | |||||||
| Balances as of December 31, 2004 |
$ | 4,705 | $ | — | $ | 4,705 | ||||||
| (a) | See Note 14—Nuclear Decommissioning and Spent Fuel Storage. |
2004 Annual Goodwill Impairment Assessment. The annual goodwill impairment assessment was performed as of November 1, 2004. The first step of the annual impairment analysis, comparing the fair value of a reporting unit to its carrying value, including goodwill, indicated no impairment of goodwill. In its assessment to estimate the fair value of the Energy Delivery reporting unit, Exelon used a probability-weighted, discounted cash flow model with multiple scenarios. The determination of the fair value is dependent on many sensitive, interrelated and uncertain variables including changing interest rates, utility sector market performance, capital structure, market prices for power, post-2006 rate regulatory structures, operating and capital expenditure requirements and other factors.
170
Exelon Corporation and Subsidiary Companies
Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, except per share data unless otherwise noted)
Changes from the assumptions used in the impairment review could possibly result in a future impairment loss of Energy Delivery’s goodwill, which could be material. Illinois legislation provides that reductions to ComEd’s common equity resulting from goodwill impairments will have no impact on the determination of the rate cap on ComEd’s allowed equity return during the electricity industry restructuring transition period through 2006. See Note—5 Regulatory Issues for further discussion of ComEd’s earnings provisions.
2003 Goodwill Impairment Assessments. The 2003 annual goodwill impairment assessment was performed as of November 1, 2003, and Exelon determined that goodwill was not impaired at Energy Delivery but that the remaining goodwill at Exelon Services was fully impaired. Exelon recorded a pre-tax charge of $24 million within operating and maintenance expenses during 2003 to fully impair the goodwill that had been recorded within the Exelon Services reporting unit of the Enterprises segment.
In connection with the sale of InfraSource in 2003, Exelon recorded a goodwill impairment charge of approximately $48 million pre-tax to fully impair the goodwill recorded within the InfraSource reporting unit of the Enterprises segment. Management of Exelon primarily considered the negotiated sales price of InfraSource in determining the amount of the goodwill impairment charge.
Other Intangible Assets
Other Intangible Assets. Exelon’s other intangible assets, included in deferred debits and other assets consisted of the following:
| December 31, 2004 |
December 31, 2003 | |||||||||||||||||||
| Gross |
Accumulated Amortization |
Net |
Gross |
Accumulated Amortization |
Net | |||||||||||||||
| Amortized intangible assets: |
||||||||||||||||||||
| Energy purchase agreement (a) |
$ | 384 | $ | (27 | ) | $ | 357 | $ | — | $ | — | $ | — | |||||||
| Tolling agreement (a) |
73 | (5 | ) | 68 | — | — | — | |||||||||||||
| Synthetic fuel investments (b) |
264 | (56 | ) | 208 | 241 | (4 | ) | 237 | ||||||||||||
| Other |
6 | (6 | ) | — | 6 | — | 6 | |||||||||||||
| Total amortized intangible assets |
727 | (94 | ) | 633 | 247 | (4 | ) | 243 | ||||||||||||
| Other intangible assets: |
||||||||||||||||||||
| Intangible pension asset |
171 | — | 171 | 186 | — | 186 | ||||||||||||||
| Total |
$ | 898 | $ | (94 | ) | $ | 804 | $ | 433 | $ | (4 | ) | $ | 429 | ||||||
| (a) | See Note 3 – Sithe and Note 25 – Subsequent Events for a description of Sithe’s intangible assets that are reflected in Exelon’s balance sheet at December 31, 2004 and a description of the sale of Sithe that was completed on January 31, 2005. |
| (b) | See Note 2 – Acquisitions and Dispositions for a description of Exelon’s right to acquire tax credits through investments in synthetic fuel-producing facilities. |
Amortization expense related to amortized intangible assets was $90 million in 2004, of which $38 million was reflected as a reduction in revenues. Of the $38 million, $32 million was attributable to the energy purchase agreement and the tolling agreement, both of which relate to Generation’s consolidation of Sithe. Amortization expense was not significant in 2003.
In 2004, Generation entered into an agreement to sell its ownership interest in Sithe, which was completed on January 31, 2005 and will result in the elimination of the intangible assets related to
171
Exelon Corporation and Subsidiary Companies
Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, except per share data unless otherwise noted)
Sithe’s energy purchase agreement and tolling agreement from the Consolidated Balance Sheets in future periods. See Note 25—Subsequent Events for further information regarding this sale. Amortization expense related to intangible assets is expected to be in the range of $100 million to $120 million annually from 2005 through 2007 and approximately $50 million in 2008 and 2009. This estimate includes amortization related to Sithe’s intangible assets of $43 million annually through 2009, which will not be incurred as a result of the sale of Sithe. The remaining amortization expense relates to Exelon’s investments in synthetic fuel-producing facilities.
10. Severance Accounting
Exelon provides severance and health and welfare benefits to terminated employees pursuant to pre-existing severance plans primarily based upon each individual employee’s years of service with Exelon and compensation level.
During the years ended December 31, 2004 and 2003, Exelon identified approximately 260 and 1,580 positions, respectively, for elimination. As of December 31, 2004, approximately 380 of the identified positions had not been eliminated. Exelon recorded charges for salary continuance severance of $32 million and $135 million (before income taxes) during 2004 and 2003, respectively, which represented salary continuance costs that were probable and could be reasonably estimated as of the end of the year. During 2004 and 2003, Exelon recorded charges of $16 million and $48 million (before income taxes), respectively, associated with special health and welfare severance benefits. Additionally, Exelon incurred curtailment and settlement costs in 2004 and 2003 associated with its pension and postretirement benefit plans of $24 million and $80 million (before income taxes), respectively, as a result of personnel reductions. In total, Exelon recorded charges of $56 million and $258 million (before income taxes) in 2004 and 2003, respectively. See Note 15—Retirement Benefits for a description of the curtailment charges related to the pension and postretirement benefit plans.
Exelon based its estimate of the number of positions to be eliminated on management’s current plans and its ability to determine the appropriate staffing levels to effectively operate the businesses. Exelon may incur further severance costs if additional positions are identified for elimination. These costs will be recorded in the period in which the costs can be reasonably estimated.
The following table details, by segment, Exelon’s total salary continuance severance costs, recorded as an operating and maintenance expense, for the years ended December 31, 2004, 2003 and 2002:
| Salary continuance severance charges |
Energy Delivery |
Generation |
Enterprises |
Corporate and Intersegment Eliminations |
Consolidated | |||||||||||
| Expenses recorded—2004 (a) |
$ | 13 | $ | 2 | $ | 2 | $ | 15 | $ | 32 | ||||||
| Expenses recorded—2003 (a) |
77 | 38 | 9 | 11 | 135 | |||||||||||
| Expenses recorded—2002 (b) |
— | 2 | (1 | ) | 7 | 8 | ||||||||||
| (a) | Severance expense in 2004 and 2003 reflects severance costs associated with The Exelon Way, revised estimates to reflect specific individuals instead of positions previously identified under The Exelon Way and other severance costs incurred in the normal course of business. |
| (b) | Severance expense in 2002 generally represents severance activity associated with the PECO / Unicom Merger and in the normal course of business. |
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Exelon Corporation and Subsidiary Companies
Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, except per share data unless otherwise noted)
The following table provides a roll forward of Exelon’s salary continuance severance obligation from January 1, 2003 through December 31, 2004.
| Salary continuance severance obligation |
||||
| Balance as of January 1, 2003 |
$ | 39 | ||
| Severance charges recorded |
135 | |||
| Cash payments |
(39 | ) | ||
| Other adjustments |
4 | |||
| Balance as of January 1, 2004 |
139 | |||
| Severance charges recorded |
32 | |||
| Cash payments |
(87 | ) | ||
| Other adjustments |
(15 | ) | ||
| Balance as of December 31, 2004 |
$ | 69 | ||
11. Short-Term Debt
| 2004 |
2003 |
2002 | |||||||
| Average borrowings |
$ | 149 | $ | 144 | $ | 337 | |||
| Maximum borrowings outstanding |
622 | 1,288 | 783 | ||||||
| Average interest rates, computed on a daily basis |
1.37% | 1.25% | 1.9% | ||||||
| Average interest rates, at December 31 |
2.43% | 1.08% | 1.88% | ||||||
At December 31, 2003, Exelon, along with ComEd, PECO and Generation, participated with a group of banks in a $750 million 364-day unsecured revolving credit agreement and a $750 million three-year unsecured revolving credit agreement. On July 16, 2004, the $750 million 364-day facility was replaced with a $1 billion unsecured revolving facility maturing on July 16, 2009, and the $750 million three-year facility was reduced to $500 million maturing on October 31, 2006. Both revolving credit agreements are used principally to support the commercial paper programs at Exelon, ComEd, PECO and Generation and to issue letters of credit.
At December 31, 2004, Exelon, ComEd, PECO and Generation had the following sublimits and available capacity under the credit agreements and the indicated amounts of outstanding commercial paper:
| Borrower |
Bank Sublimit (a) |
Available Capacity (b) |
Outstanding Commercial Paper | ||||||
| Exelon |
$ | 700 | $ | 685 | $ | 490 | |||
| ComEd |
100 | 74 | — | ||||||
| PECO |
100 | 100 | — | ||||||
| Generation |
600 | 444 | — | ||||||
| (a) | Sublimits under the credit agreements can change upon written notification to the bank group. |
| (b) | Available capacity represents the bank sublimit net of outstanding letters of credit. The amount of commercial paper outstanding does not reduce the available capacity under the credit facilities. |
Interest rates on advances under the credit facilities are based on either prime or the London Interbank Offering Rate (LIBOR) plus an adder based on the credit rating of the borrower as well as the
173
Exelon Corporation and Subsidiary Companies
Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, except per share data unless otherwise noted)
total outstanding amounts under the agreement at the time of borrowing. The maximum LIBOR adder is 170 basis points.
The credit agreements require Exelon, ComEd, PECO and Generation to maintain a minimum cash from operations to interest expense ratio for the twelve-month period ended on the last day of any quarter. The ratios exclude revenues and interest expenses attributable to securitization debt, certain changes in working capital, distributions on preferred securities of subsidiaries and, in the case of Exelon and Generation, revenues from Sithe and interest on the debt of its project subsidiaries. The following table summarizes the minimum thresholds reflected in the credit agreements for the twelve-month period ended December 31, 2004:
| Exelon |
ComEd |
PECO |
Generation | |||||
| Credit agreement threshold |
2.65 to 1 | 2.25 to 1 | 2.25 to 1 | 3.25 to 1 |
At December 31, 2004, Exelon, ComEd, PECO and Generation were in compliance with the foregoing thresholds.
174
Exelon Corporation and Subsidiary Companies
Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, except per share data unless otherwise noted)
12. Long-Term Debt
| Rates |
Maturity |
December 31, |
||||||||||
| 2004 |
2003 |
|||||||||||
| Long-term debt |
||||||||||||
| First Mortgage Bonds (a) (b): |
||||||||||||
| Fixed rates |
3.50%-9.875% | 2005-2033 | $ | 3,510 | $ | 4,312 | ||||||
| Floating rates |
1.70%-1.95% | 2012-2020 | 406 | 406 | ||||||||
| Notes payable and other (c) |
5.35%-9.20% | 2005-2020 | 2,411 | 2,943 | ||||||||
| Boston Generating Credit Facility (d) |
— | — | — | 1,037 | ||||||||
| Pollution control notes: |
||||||||||||
| Fixed rates |
— | — | — | 157 | ||||||||
| Floating rates |
1.71%-2.04% | 2016-2034 | 520 | 363 | ||||||||
| Notes payable—accounts receivable agreement |
2.50% | 2005 | 46 | 49 | ||||||||
| Sinking fund debentures |
3.875%-4.75% | 2005-2011 | 12 | 17 | ||||||||
| Sithe long-term debt (e) |
||||||||||||
| Non-recourse project debt |
||||||||||||
| Independence |
8.50%-9.00% | 2007-2013 | 499 | — | ||||||||
| Batavia |
18.00% | 2007 | 1 | — | ||||||||
| Subordinated debt |
7.00% | 2034 | 419 | — | ||||||||
| Total long-term debt (f) |
7,824 | 9,284 | ||||||||||
| Unamortized debt discount and premium, net |
(114 | ) | (43 | ) | ||||||||
| Fair-value hedge carrying value adjustment, net |
9 | 33 | ||||||||||
| Long-term debt due within one year |
(427 | ) | (1,385 | ) | ||||||||
| Long-term debt |
$ | 7,292 | $ | 7,889 | ||||||||
| Long-term debt due to ComEd Transitional Funding Trust and PECO Energy Transition Trust (g, h) |
||||||||||||
| Payable to ComEd Transitional Funding Trust |
5.44%-5.74% | 2005-2008 | $ | 1,341 | $ | 1,676 | ||||||
| Payable to PETT |
2.98%-7.65% | 2005-2010 | 3,456 | 3,849 | ||||||||
| Long-term debt due to ComEd Transitional Funding Trust and PECO Energy Transition Trust |
4,797 | 5,525 | ||||||||||
| Long-term debt due to ComEd Transitional Funding Trust and PECO Energy Transition Trust due within one year |
(486 | ) | (470 | ) | ||||||||
| Total long-term debt due to ComEd Transitional Funding Trust and PECO Energy Transition Trust |
$ | 4,311 | $ | 5,055 | ||||||||
| Long-term debt to other financing trusts (g, h) |
||||||||||||
| Subordinated debentures to ComEd Financing II |
8.50% | 2027 | 155 | 155 | ||||||||
| Subordinated debentures to ComEd Financing III |
6.35% | 2033 | 206 | 206 | ||||||||
| Subordinated debentures to PECO Trust III |
7.38% | 2028 | 81 | 81 | ||||||||
| Subordinated debentures to PECO Trust IV |
5.75% | 2033 | 103 | 103 | ||||||||
| Total long-term debt to other financing trusts |
$ | 545 | $ | 545 | ||||||||
| (a) | Utility plant of ComEd and PECO is subject to the liens of their respective mortgage indentures. |
| (b) | Includes first mortgage bonds issued under the ComEd and PECO mortgage indentures securing pollution control bonds and notes. |
| (c) | Includes capital lease obligations of $50 million at December 31, 2004 and December 31, 2003. Lease payments of $3 million, $3 million, $2 million, $2 million and $40 million will be made in 2005, 2006, 2007, 2008, and thereafter, respectively. |
| (d) | Approximately $1.0 billion of debt was outstanding under the non-recourse Boston Generating Credit Facility at December 31, 2003, all of which was reflected in the Consolidated Balance Sheet of Exelon as a current liability due to certain events of default under the Boston Generating Credit Facility. The outstanding debt under the Boston Generating Credit Facility was |
175
Exelon Corporation and Subsidiary Companies
Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, except per share data unless otherwise noted)
| eliminated from the financial statements of Exelon upon the sale of Generation’s ownership interest in Boston Generating in May 2004. See Note 2 – Acquisitions and Dispositions for additional information regarding the sale. |
| (e) | In addition to the stated interest rate, an additional 1.97% and 0.99% of interest on the carrying amount of the secured bonds payable is being credited due to debt premiums and 1.63% of interest on the carrying amount of the subordinated debt is being incurred due to the debt discount recorded at the time of the purchase. There is $100 million of unamortized debt discount associated with Sithe long-term debt. These amounts represent obligations of Sithe and will be removed from Exelon’s Consolidated Balance Sheet following Generation’s sale of Sithe, which was completed on January 31, 2005. See Note 25—Subsequent Events for additional information. |
| (f) | Long-term debt maturities in the periods 2005 through 2009 and thereafter are as follows: |
| 2005 |
$ | 427 | |
| 2006 |
446 | ||
| 2007 |
271 | ||
| 2008 |
942 | ||
| 2009 |
85 | ||
| Thereafter |
5,653 | ||
| Total |
$ | 7,824 | |
| Included in the table above are maturities of Sithe’s debt of $34, $38, $40, $44, $57 and $706 in 2005, 2006, 2007, 2008, 2009 and thereafter, respectively. In connection with Generation’s sale of Sithe on January 31, 2005, Generation is no longer obligated to fulfill these debt maturities, and the related obligations will be removed from the Consolidated Balance Sheets. See Note 25 – Subsequent Events for a further discussion of Generation’s the sale of Sithe. |
| (g) | Effective July 1, 2003, PECO Trust IV, a financing subsidiary created in May 2003, was deconsolidated from the financial statements in conjunction with the adoption of FIN 46. Effective December 31, 2003, ComEd Financing II, ComEd Financing III, ComEd Transitional Funding Trust, PECO Trust III, and PETT were deconsolidated from the financial statements in conjunction with the adoption of FIN 46-R. Amounts owed to these financing trusts are recorded as debt to financing trusts within the Consolidated Balance Sheets. |
| (h) | Long-term debt to financing trusts maturities in the periods 2005 through 2009 and thereafter are as follows: |
| 2005 |
$ | 486 | |
| 2006 |
860 | ||
| 2007 |
980 | ||
| 2008 |
965 | ||
| 2009 |
700 | ||
| Thereafter |
1,351 | ||
| Total |
$ | 5,342 | |
Issuances of Long-Term Debt. The following long-term debt was issued during 2004:
| Company |
Type |
Interest Rate |
Maturity |
Amount | |||||
| PECO |
First Mortgage Bonds | 5.90% | May 1, 2034 | $ | 75 | ||||
| Generation |
Pollution Control Revenue Bonds (a) | Variable | April 1, 2021 | 51 | |||||
| Generation |
Pollution Control Revenue Bonds (a) | Variable | October 1, 2030 | 92 | |||||
| Generation |
Pollution Control Revenue Bonds (a) | Variable | October 1, 2034 | 14 | |||||
| Exelon |
Note (b) | 6.00% | January 15, 2008 | 22 | |||||
| Total issuances |
$ | 254 | |||||||
| (a) | The proceeds from the issuances were used to redeem pollution control revenue bonds of PECO. |
| (b) | Represents a non-cash issuance for investments in synthetic fuel-producing facilities. See Note 2 – Acquisitions and Dispositions for additional information regarding these investments. |
176
Exelon Corporation and Subsidiary Companies
Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, except per share data unless otherwise noted)
Debt Retirements and Redemptions. The following debt was retired, through tender, open market purchases, optional redemption or payment at maturity, during 2004:
| Company |
Type |
Interest Rate |
Maturity |
Amount | |||||
| ComEd |
Medium Term Notes | 9.200% | October 15, 2004 | $ | 56 | ||||
| ComEd |
Notes | 6.400% | October 15, 2005 | 128 | |||||
| ComEd |
Notes | 6.950% | July 15, 2018 | 85 | |||||
| ComEd |
Notes | 7.375% | January 15, 2004 | 150 | |||||
| ComEd |
Notes | 7.625% | January 15, 2007 | 5 | |||||
| ComEd |
Pollution Control Revenue Bonds | 5.300% | January 15, 2004 | 26 | |||||
| ComEd |
Pollution Control Revenue Bonds | 5.700% | January 15, 2009 | 4 | |||||
| ComEd |
Pollution Control Revenue Bonds | 5.850% | January 15, 2014 | 3 | |||||
| ComEd |
Sinking Fund Debentures | 3.125% | October 1, 2004 | 2 | |||||
| ComEd |
Sinking Fund Debentures | 3.875% | January 1, 2008 | 1 | |||||
| ComEd |
Sinking Fund Debentures | 4.625% | January 1, 2009 | 1 | |||||
| ComEd |
Sinking Fund Debentures | 4.750% | December 1, 2011 | 1 | |||||
| ComEd |
First Mortgage Bonds | 3.700% | February 1, 2008 | 55 | |||||
| ComEd |
First Mortgage Bonds | 4.700% | April 15, 2015 | 135 | |||||
| ComEd |
First Mortgage Bonds | 4.740% | August 15, 2010 | 38 | |||||
| ComEd |
First Mortgage Bonds | 5.875% | February 1, 2033 | 96 | |||||
| ComEd |
First Mortgage Bonds | 6.150% | March 15, 2012 | 150 | |||||
| ComEd |
First Mortgage Bonds | 7.000% | July 1, 2005 | 62 | |||||
| ComEd |
First Mortgage Bonds | 7.500% | July 1, 2013 | 20 | |||||
| ComEd |
First Mortgage Bonds | 7.625% | April 15, 2013 | 94 | |||||
| ComEd |
First Mortgage Bonds | 8.000% | May 15, 2008 | 20 | |||||
| ComEd |
First Mortgage Bonds | 8.250% | October 1, 2006 | 5 | |||||
| ComEd |
First Mortgage Bonds | 8.375% | October 15, 2006 | 94 | |||||
| PECO |
Pollution Control Revenue Bonds (a) | 5.200% | April 1, 2021 | 51 | |||||
| PECO |
Pollution Control Revenue Bonds (a) | 5.200% | October 1, 2030 | 92 | |||||
| PECO |
Pollution Control Revenue Bonds (a) | 5.300% | October 1, 2034 | 14 | |||||
| PECO |
First Mortgage Bonds | 6.375% | August 15, 2005 | 75 | |||||
| Enterprises |
Note | 7.680% | June 30, 2023 | 11 | |||||
| Enterprises |
Note | 9.090% | January, 31, 2020 | 26 | |||||
| Generation |
Note—AmerGen | 6.330% | August 8, 2009 | 10 | |||||
| Generation |
Note—AmerGen | 6.200% | December 20, 2004 | 16 | |||||
| Generation |
Note—Sithe | 8.500% | June 30, 2007 | 32 | |||||
| Exelon |
Notes | 7.980% to 8.875% | 2009 and 2010 | 63 | |||||
| Other |
8 | ||||||||
| Total retirements |
$ | 1,629 | |||||||
| (a) | The bonds were redeemed with the proceeds from the issuance of pollution control revenue bonds by Generation. |
During 2004, ComEd made payments of $335 million related to its obligation to the ComEd Transitional Funding Trust, and PECO made payments of $393 million related to its obligation to PETT.
During 2004, ComEd retired $1.2 billion of long-term debt, including $1.0 billion prior to its maturity and $206 million at maturity, pursuant to Exelon’s accelerated liability management plan. ComEd
177
Exelon Corporation and Subsidiary Companies
Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, except per share data unless otherwise noted)
funded the retirements through cash from operations, a return of contributions to the intercompany money pool and collections on an intercompany note receivable from UII, LLC (formerly Unicom Investments, Inc.) Exelon recorded charges of $130 million (before income taxes) in 2004 associated with the retirement of debt under the plan. The charges were included within other, net within Exelon’s Consolidated Statements of Income. The components of the charges included the following: $86 million for prepayment premiums; $12 million for net unamortized premiums, discounts and debt issuance costs; $24 million of losses on reacquired debt previously deferred as regulatory assets; and $12 million for settled cash-flow interest-rate swaps previously deferred as regulatory assets partially offset by $4 million of unamortized gain on settled fair value interest-rate swaps.
See Note 2—Acquisitions and Dispositions for information regarding debt classified as held for sale as of December 31, 2003.
See Note 16—Fair Value of Financial Assets and Liabilities for additional information regarding interest-rate swaps of ComEd, PECO and Generation.
See Note 17—Preferred Securities for additional information regarding preferred stock.
13. Income Taxes
Income tax expense (benefit) is comprised of the following components:
| For the Years Ended December 31, |
||||||||||||
| 2004 |
2003 |
2002 |
||||||||||
| Included in operations: |
||||||||||||
| Federal |
||||||||||||
| Current |
$ | 401 | $ | 275 | $ | 624 | ||||||
| Deferred |
243 | 63 | 250 | |||||||||
| Investment tax credit amortization |
(13 | ) | (13 | ) | (15 | ) | ||||||
| State |
||||||||||||
| Current |
89 | 92 | 96 | |||||||||
| Deferred |
(28 | ) | (86 | ) | 43 | |||||||
| Total income tax expense |
$ | 692 | $ | 331 | $ | 998 | ||||||
| Included in cumulative effect of changes in accounting principles: |
||||||||||||
| Deferred |
||||||||||||
| Federal |
$ | 12 | $ | 58 | $ | (87 | ) | |||||
| State |
5 | 11 | (3 | ) | ||||||||
| Total income tax expense (benefit) |
$ | 17 | $ | 69 | $ | (90 | ) | |||||
178
Exelon Corporation and Subsidiary Companies
Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, except per share data unless otherwise noted)
The effective income tax rate varies from the U.S. Federal statutory rate principally due to the following:
| For the Years Ended December 31, |
|||||||||
| 2004 |
2003 |
2002 |
|||||||
| U.S. Federal statutory rate |
35.0 | % | 35.0 | % | 35.0 | % | |||
| Increase (decrease) due to: |
|||||||||
| State income taxes, net of Federal income tax benefit |
1.6 | 0.4 | 3.2 | ||||||
| Synthetic fuel-producing facilities credit (a) |
(8.6 | ) | (2.0 | ) | — | ||||
| Low income housing credit |
(0.4 | ) | (1.2 | ) | (0.5 | ) | |||
| Amortization of investment tax credit |
(0.4 | ) | (0.9 | ) | (0.4 | ) | |||
| Tax exempt income |
(0.4 | ) | (0.7 | ) | (0.2 | ) | |||
| Qualified nuclear decommissioning trust fund income |
(0.3 | ) | 0.8 | — | |||||
| Nontaxable employee benefits |
(0.3 | ) | — | — | |||||
| Other |
1.3 | (2.1 | ) | 0.3 | |||||
| Effective income tax rate |
27.5 | % | 29.3 | % | 37.4 | % | |||
| (a) | Change between 2003 and 2004 reflects investments in synthetic fuel-producing facilities made in the fourth quarter of 2003 and the third quarter of 2004. See Note 2—Acquisitions and Dispositions for additional information regarding investments in synthetic fuel-producing facilities. |
The tax effects of temporary differences giving rise to significant portions of Exelon’s deferred tax assets and liabilities as of December 31, 2004 and 2003 are presented below:
| 2004 |
2003 |
|||||||
| Deferred tax liabilities: |
||||||||
| Plant basis difference |
$ | 4,177 | $ | 3,932 | ||||
| Stranded cost recovery |
1,632 | 1,784 | ||||||
| Deferred debt refinancing costs |
56 | 69 | ||||||
| Total deferred tax liabilities |
5,865 | 5,785 | ||||||
| Deferred tax assets: |
||||||||
| Deferred pension and postretirement obligations |
(985 | ) | (901 | ) | ||||
| Excess of tax value over book value of impaired assets (a) |
(44 | ) | (200 | ) | ||||
| Decommissioning and decontamination obligations |
(145 | ) | (97 | ) | ||||
| Unrealized loss on derivative financial instruments |
(57 | ) | (70 | ) | ||||
| Goodwill |
(6 | ) | (29 | ) | ||||
| Other, net |
(208 | ) | (290 | ) | ||||
| Total deferred tax assets |
(1,445 | ) | (1,587 | ) | ||||
| Deferred income tax liabilities (net) on the Consolidated Balance Sheets |
$ | 4,420 | $ | 4,198 | ||||
| (a) | Includes impairments related to Exelon’s investments in Sithe and Boston Generating and write-downs of certain Enterprises investments. |
In accordance with regulatory treatment of certain temporary differences, Exelon has recorded a net regulatory asset associated with deferred income taxes, pursuant to SFAS No. 71 and SFAS No. 109, of $751 million and $701 million at December 31, 2004 and 2003, respectively. See Note 21—
179
Exelon Corporation and Subsidiary Companies
Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, except per share data unless otherwise noted)
Supplemental Financial Information for further discussion of Exelon’s regulatory asset associated with deferred income taxes.
ComEd and PECO have certain tax returns that are under review at the audit or appeals level of the IRS, and certain state authorities. Except for the tax positions discussed below, these reviews by governmental taxing authorities are not expected to have an adverse impact on the financial condition or result of operations of Exelon.
Exelon, through its ComEd subsidiary, has taken certain tax positions, which have been disclosed to the IRS, to defer the tax gain on the 1999 sale of its fossil generating assets. As of December 31, 2004, deferred tax liabilities related to the fossil plant sale are reflected in Exelon’s Consolidated Balance Sheets with the majority allocated to ComEd and the remainder to Generation. The 1999 income tax liability deferred as a result of these transactions was approximately $1.1 billion. Exelon’s ability to continue to defer a portion of this liability depends on whether its treatment of a portion of the sales proceeds as having been received in connection with an involuntary conversion is proper pursuant to IRS regulations and interpretations. Exelon’s ability to continue to defer the remainder of this liability may depend in part on whether its tax characterization of a lease transaction it entered into in connection with the sale is proper pursuant to IRS regulations and interpretations. The IRS is likely to argue that the lease transaction is of a type it has recently announced its intention to challenge, and Exelon understands that somewhat similar transactions entered into by other companies have been the subject of review and challenge by the IRS. Changes in IRS interpretations of existing primary tax authority or challenges to ComEd’s positions could have the impact of accelerating future income tax payments and increasing interest expense related to the deferred tax gain that becomes current. Any required payments could be significant to the cash flows of Exelon. Exelon’s management believes Exelon’s reserve for interest, which has been established in the event that such positions are not sustained, has been appropriately recorded in accordance with SFAS No. 5, “Accounting for Contingencies” (SFAS No. 5); however, the ultimate outcome of such matters could result in unfavorable or favorable adjustments to the results of operations, and such adjustments could be material. Federal tax returns covering the period of the 1999 sale are currently under Internal Revenue Service (IRS) audit. Final resolution of this matter is not anticipated for several years.
It is presently unclear the extent to which any IRS challenge to such deferral would be successful. If the deferral was successfully challenged by the IRS, it could have a material adverse impact on Exelon’s operating results.
As of December 31, 2004 and 2003, Exelon had recorded valuation allowances of $9 million and $22 million, respectively, with respect to deferred taxes associated with separate company state taxes. As of December 31, 2004, Exelon had net capital loss carryforwards for income tax purposes of approximately $183 million, which expire beginning in 2008.
14. Nuclear Decommissioning and Spent Fuel Storage
Nuclear Decommissioning
Overview
Exelon has a legal obligation to decommission its nuclear power plants following the expiration of their operating licenses. This obligation is reflected as an asset retirement obligation (ARO), which is
180
Exelon Corporation and Subsidiary Companies
Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, except per share data unless otherwise noted)
classified as a noncurrent liability. Based on the actual or anticipated extended license lives of the nuclear plants, decommissioning expenditures for Exelon’s nuclear power plants currently operating are expected to occur primarily during the period 2029 through 2056. Exelon owns three nuclear units that are retired and currently incur certain costs associated with decommissioning. The cost of nuclear decommissioning will be funded by investments held in trust funds that have been established for each nuclear station. Exelon had nuclear decommissioning trust funds totalling $5,262 million and $4,721 million as of December 31, 2004 and 2003, respectively. See Note 16—Fair Value of Financial Assets and Liabilities for more information regarding Exelon’s nuclear decommissioning trust funds.
Cost Recovery and Decommissioning Responsibilities
Former ComEd plants. Exelon currently recovers in revenues funds for decommissioning the former ComEd nuclear plants through regulated rates collected by ComEd. The amounts recovered from customers are remitted to Generation and deposited into the trust accounts to fund the future decommissioning costs. Under a December 2000 Illinois Commerce Commission Order issued to ComEd, amended February 2001 (ICC Order), ComEd is permitted to collect up to $73 million annually through 2006 from ratepayers to decommission the former ComEd nuclear plants. The amount of decommissioning revenue collections for 2005 and 2006 are anticipated to be less than than $73 million. Under the current ICC Order, ComEd will not collect amounts for decommissioning subsequent to 2006.
Based on the provisions of the ICC Order and NRC regulations, Exelon is financially responsible for the decommissioning obligations related to these plants. If trust assets plus future collections permitted by the ICC Order are exceeded by the ultimate ARO, Exelon is responsible for any shortfall in funding; however, if amounts remain in the trust funds for these units following the completion of the decommissioning activities, those amounts will be returned to the ComEd ratepayers. At the end of each financial reporting period, Exelon assesses the amounts currently recorded in trust assets plus future collections less amounts recorded in the ARO. At December 31, 2004 and 2003, Exelon recorded a regulatory liability for the amount of decommissioning-related assets in excess of the ARO.
Former PECO plants. Exelon currently recovers costs for decommissioning the former PECO nuclear plants through regulated rates collected by PECO. The amounts recovered from customers are remitted to Generation and deposited into the trust accounts to fund the future decommissioning costs. Under orders from the Pennsylvania Public Utility Commission (PUC), PECO is permitted to collect from ratepayers up to $33 million annually for the full funding of the expected costs to decommission the former PECO nuclear plants. Based on the provisions of the PUC order, the PECO ratepayers are financially responsible for the majority of any shortfalls in the costs to decommission these nuclear units; however, the PECO ratepayers will receive any excess amounts from the trust funds at the completion of decommissioning. Exelon is responsible for 1) the first $50 million of the decommissioning costs above a certain threshold established under the PUC order and 2) five percent of the decommissioning costs above that first $50 million of costs that exceed the established threshold. Exelon expects total decommissioning costs to exceed this threshold and expects to be held responsible for the entire $50 million over the remaining life of the assets. At the end of each financial reporting period, Exelon assesses the amounts currently recorded in trust assets plus future collections less amounts recorded in the ARO. At December 31, 2004 and 2003, Exelon recorded a regulatory liability for the amount of decommissioning-related assets in excess of the ARO.
AmerGen plants. Exelon does not recover costs for decommissioning the AmerGen nuclear plants from customers. As such, Exelon is financially responsible for the decommissioning of these plants and
181
Exelon Corporation and Subsidiary Companies
Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, except per share data unless otherwise noted)
bears all risks and benefits related to the funding levels associated with these plants’ decommissioning trust funds.
Adoption of SFAS No. 143
Exelon adopted SFAS No. 143 on January 1, 2003, which promulgates the accounting for AROs. In accordance with SFAS No. 143, a probability-weighted, discounted cash flow model with multiple scenarios was used to determine the fair value of the decommissioning obligation. SFAS No. 143 states that the estimated fair value of the decommissioning obligation represents the amount a third party would receive for assuming an entity’s entire obligation. The present value of future estimated cash flows required to decommission the nuclear stations was calculated using credit-adjusted, risk-free rates applicable to the various businesses in order to determine the fair value of the decommissioning obligation at the time of adoption of SFAS No. 143.
Former ComEd plants. The transition provisions of SFAS No. 143 required Exelon to apply the fair value remeasurement back to the historical periods in which AROs were originally incurred, resulting in a remeasurement of these obligations at the date the assets were acquired by Exelon. Since the nuclear plants previously owned by ComEd were acquired by Exelon on October 20, 2000 (and subsequently transferred to Generation as a result of the Exelon corporate restructuring on January 1, 2001), Exelon’s historical accounting for its ARO associated with those plants was revised as if SFAS No. 143 had been in effect at the merger date. The calculation of the SFAS No. 143 ARO yielded decommissioning obligations lower than the value of the corresponding trust assets at January 1, 2003. Since the trust fund assets exceeded the fair value of the ARO, a regulatory liability of $948 million was recorded at January 1, 2003. As a result of increases in the trust funds due to market conditions, the regulatory liability has increased to $1,433 million at December 31, 2004.
In accordance with the provisions of SFAS No. 143 and regulatory accounting guidance, Exelon recorded a SFAS No. 143 transition adjustment to accumulated other comprehensive income to reclassify $168 million, net of tax, of accumulated net unrealized losses in the nuclear decommissioning trust funds to the regulatory liability associated with the former ComEd plants.
Former PECO plants. In the case of the former PECO plants, the SFAS No. 143 ARO calculation yielded decommissioning obligations greater than the corresponding trust assets at January 1, 2003. As such, a regulatory asset of $20 million was recorded. As a result of increases in the trust funds due to market conditions and contributions collected from PECO customers, the trust fund assets exceeded the ARO at December 31, 2004 and Exelon has a regulatory liability to the PECO ratepayers of $46 million. At December 31, 2003, Exelon had a regulatory liability to the PECO ratepayers of $12 million related to nuclear decommissioning.
Upon adoption, and in accordance with the provisions of SFAS No. 143, Exelon capitalized an asset retirement cost (ARC) asset within property, plant and equipment of $172 million related to the establishment of the ARO for the former PECO plants. The ARC is being amortized over the remaining useful lives of the former PECO plants.
Exelon believes that all of the decommissioning assets, anticipated earnings thereon and future revenues from decommissioning collections will be used to decommission the former ComEd and PECO nuclear plants. As such, Exelon expects the regulatory liabilities to be reduced to zero at the conclusion of the decommissioning activities.
182
Exelon Corporation and Subsidiary Companies
Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, except per share data unless otherwise noted)
AmerGen plants. At the time of the adoption of SFAS No. 143 on January 1, 2003, Exelon had a 50% ownership of AmerGen. Exelon recorded income of $29 million (after income taxes) as the cumulative effect of changes in accounting principles.
Impact of Current Regulatory Orders on the Application of SFAS No. 143
Increases in the ARO due to the passage of time are recorded in operating and maintenance expense as accretion expense. Increases in the ARO resulting from revisions to the estimated future cash flows are generally recorded with a corresponding adjustment to the basis of plant value, by recording an ARC asset. The ARC is depreciated on a straight-line basis over the remaining life of the unit to which it relates. Changes in the nuclear decommissioning trust funds are discussed in Note 16 -Fair Value of Financial Assets and Liabilities.
Former ComEd plants. As of December 31, 2004, the trust assets associated with the former ComEd plants exceeded the ARO for those plants. Until such time, if ever, that the ARO exceeds the decommissioning-related assets, Exelon’s net income should not reflect the impacts of any income or expenses associated with decommissioning the former ComEd nuclear units. As such, decommissioning revenues collected, nuclear decommissioning trust fund investment income, accretion expense and depreciation of the ARC are not reflected in net income as they are offset by the adjustment to the regulatory liability to ComEd’s ratepayers to the extent the decommissioning-related assets exceed the ARO.
Former PECO plants. As of December 31, 2004, the trust assets associated with the former PECO plants exceeded the ARO for those plants. The regulatory order associated with the former PECO units ensures that Exelon will not be financially responsible for the decommissioning of these units, with the exception of certain amounts described above. As such, Exelon’s net income should not reflect the impacts of any income or expenses associated with decommissioning the former PECO nuclear units, except for the accretion expense associated with its decommissioning cost responsibility above the decommissioning cost thresholds established by the PUC, as previously discussed. The net effect of decommissioning revenues collected, nuclear decommissioning trust fund investment income, accretion expense and depreciation of the ARC is adjusted so that the amounts net to an insignificant amount in Exelon’s Consolidated Statements of Income. This adjustment is reflected as a change in the regulatory liability to PECO’s ratepayers.
AmerGen plants. Beginning in 2004, decommissioning activity related to the AmerGen units is reflected in Exelon’s Consolidated Statements of Income. The AmerGen units are not subject to any cost recovery regulation and, as such, Exelon will be required to fund any shortfall of trust assets below the decommissioning obligations. Similarly, Exelon will not be required to refund any excess trust funds to customers if the obligation is less than the available trust funds. As such, the impacts of nuclear decommissioning trust fund investment income, accretion expense and depreciation of the ARC are all included in Exelon’s Consolidated Statements of Income. Prior to December 2003 and Exelon’s acquisition of British Energy’s 50% interest in AmerGen, the impact to Exelon for accounting for the decommissioning of the AmerGen plants was recorded within Exelon’s equity in earnings of AmerGen. In addition, Exelon’s proportionate share of unrealized gains and losses on AmerGen’s decommissioning trust funds were reflected in Exelon’s other comprehensive income.
183
Exelon Corporation and Subsidiary Companies
Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, except per share data unless otherwise noted)
2004 Update of ARO
Generation updates its ARO on a periodic basis. During 2004, Generation recorded a $780 million net increase to the ARO resulting from revisions to estimated future nuclear decommissioning cash flows. This update also resulted in an adjustment to the basis of property, plant and equipment of $780 million by recording a corresponding net increase to the ARC. This increase to the ARO was primarily a result of updated decommissioning cost studies and changes in cost escalation factors used to estimate future undiscounted costs, both of which are provided by independent third-party appraisers. Cost estimates are updated every three to five years in accordance with NRC regulations and industry practice. The net increase in the ARO for the former ComEd units, the former PECO units and the AmerGen units resulting from revisions to estimated cash flows during 2004 was $563 million, $142 million and $75 million, respectively. As of December 31, 2004, the ARO balances for the former ComEd, the former PECO and the AmerGen units totaled approximately $2.3 billion, $1.0 billion and $0.6 billion, respectively.
The following table provides a roll forward reconciliation of the ARO reflected on Exelon’s Consolidated Balance Sheets from January 1, 2003 to December 31, 2004:
| Asset retirement obligation at January 1, 2003 |
$ | 2,366 | ||
| Consolidation of AmerGen |
487 | |||
| Accretion expense |
161 | |||
| Payments to decommission retired plants |
(14 | ) | ||
| Reclassification of Thermal ARO as held for sale (a) |
(3 | ) | ||
| Asset retirement obligation at December 31, 2003 |
2,997 | |||
| Net increase resulting from updates to future estimated cash flows |
780 | |||
| Accretion expense |
210 | |||
| Additional liabilities incurred (b) |
6 | |||
| Payments to decommission retired plants |
(12 | ) | ||
| Asset retirement obligation at December 31, 2004 |
$ | 3,981 | ||
| (a) | The ARO of Thermal was subsequently relieved upon its sale in the second quarter of 2004. |
| (b) | Additional liabilities incurred are primarily due to the consolidation of Sithe. |
Accounting Prior to the Adoption of SFAS No. 143
Prior to January 1, 2003, Exelon accounted for the current period’s cost of decommissioning related to generating plants previously owned by PECO in accordance with common regulatory accounting practices by recording a charge to depreciation expense and a corresponding liability in accumulated depreciation concurrently with recognizing decommissioning collections. Financial activity of the decommissioning trust (e.g., investment income and realized and unrealized gains and losses on trust investments) was reflected in nuclear decommissioning trust funds in Exelon’s Consolidated Balance Sheets with a corresponding offset recorded to accumulated depreciation.
Regulatory accounting practices for the nuclear generating stations previously owned by ComEd were discontinued as a result of an ICC Order capping ComEd’s ultimate recovery of decommissioning costs. The difference between the decommissioning cost estimate and the decommissioning liability recorded in accumulated depreciation for the former ComEd operating stations was previously amortized to depreciation expense on a straight-line basis over the remaining lives of the stations. The
184
Exelon Corporation and Subsidiary Companies
Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, except per share data unless otherwise noted)
decommissioning cost estimate (adjusted annually to reflect inflation) for the former ComEd retired units recorded in deferred credits and other liability was previously accreted to depreciation expense. Financial activity of the decommissioning trust funds related to Generation’s nuclear generating stations no longer accounted for under common regulatory practices was reflected in nuclear decommissioning trust funds in Exelon’s Consolidated Balance Sheets with a corresponding gain or expense recorded in Exelon’s Consolidated Income Statements or in other comprehensive income.
Spent Nuclear Fuel
Under the Nuclear Waste Policy Act of 1982 (NWPA), the U.S. Department of Energy (DOE) is responsible for the development of a repository for the disposal of spent nuclear fuel (SNF) and high- level radioactive waste. As required by the NWPA, Generation is a party to contracts with the DOE (Standard Contracts) to provide for disposal of SNF from its nuclear generating stations. In accordance with the NWPA and the Standard Contracts, Generation pays the DOE one mill ($.001) per kilowatt- hour of net nuclear generation for the cost of nuclear fuel long-term disposal. This fee may be adjusted prospectively in order to ensure full cost recovery. The NWPA and the Standard Contracts required the DOE to begin taking possession of SNF generated by nuclear generating units by no later than January 31, 1998. The DOE, however, failed to meet that deadline and its performance will be delayed significantly. The DOE’s current estimate for opening a SNF facility is 2012. This extended delay in SNF acceptance by the DOE has led to Generation’s adoption of dry cask storage at its Dresden, Quad Cities, Oyster Creek and Peach Bottom stations and its consideration of dry cask storage at other stations.
The Standard Contracts with the DOE also required the payment to the DOE a one-time fee applicable to nuclear generation through April 6, 1983. PECO’s fee has been paid. Pursuant to the Standard Contracts, ComEd elected to pay the one-time fee of $277 million, with interest to the date of payment, just prior to the first delivery of SNF to the DOE. As of December 31, 2004, the unfunded liability for the one-time fee with interest was $878 million. Interest accrues at the 13-week Treasury Rate, which was 1.987% at December 31, 2004. The liabilities for spent nuclear fuel disposal costs, including the one-time fee, were transferred to Generation as part of the corporate restructuring. The one-time fee obligation for the AmerGen units remains with the prior owner. The Clinton Unit has no outstanding obligation.
In July 1998, ComEd filed a complaint against the United States Government (Government) in the United States Court of Federal Claims (Court) seeking to recover damages caused by the DOE’s failure to honor its contractual obligation to begin disposing of SNF in January 1998. In August 2001, the Court granted ComEd’s motion for partial summary judgment for liability on ComEd’s breach of contract claim. In November 2001, the Government filed two partial summary judgment motions relating to certain damage issues in the case as well as two motions to dismiss claims other than ComEd’s breach of contract claim. On June 10, 2003, the Court granted the Government’s motion to dismiss claims other than the breach of contract claims. Also on June 10, 2003, the Court denied the Government’s summary judgment motions and set the case for trial on damages for November 2004.
In July 2000, PECO entered into an agreement (Amendment) with the DOE relating to PECO’s Peach Bottom nuclear generating unit to address the DOE’s failure to begin removal of SNF in January 1998 as required by the Standard Contracts. Under the Amendment, the DOE agreed to provide PECO with credits against PECO’s future contributions to the Nuclear Waste Fund to compensate PECO for SNF storage costs incurred as a result of the DOE’s breach of the contract. The Amendment also
185
Exelon Corporation and Subsidiary Companies
Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, except per share data unless otherwise noted)
provided that, upon PECO’s request, the DOE will take title to the SNF and the interim storage facility at Peach Bottom provided certain conditions are met. Generation assumed this contract in the 2001 corporate restructuring.
In November 2000, eight utilities with nuclear power plants filed a Joint Petition for Review against the DOE with the United States Court of Appeals for the Eleventh Circuit seeking to invalidate that portion of the Amendment providing for credits to PECO against nuclear waste fund payments on the ground that such provision is a violation of the NWPA. PECO intervened as a defendant in that case, and Generation assumed the claim in the 2001 corporate restructuring. On September 24, 2002, the United States Court of Appeals for the Eleventh Circuit ruled that the fee adjustment provision of the Amendment violates the NWPA and therefore is null and void. The Court did not hold that the Amendment as a whole is invalid. Article XVI(I) of the Amendment provides that if any portion of the Amendment is found to be void, the DOE and Generation agree to negotiate in good faith and attempt to reach an enforceable agreement consistent with the spirit and purpose of the Amendment. That provision further provided that should a major term be declared void, and the DOE and Generation cannot reach a subsequent agreement, the entire Amendment would be rendered null and void, the original Peach Bottom Standard Contracts would remain in effect and the parties would return to pre-Amendment status. Under the Amendment, Generation has received approximately $40 million in credits against contributions to the nuclear waste fund.
On August 14, 2003, Generation received a letter from the DOE demanding repayment of $40 million of previously received credits from the Nuclear Waste Fund. The letter also demanded $1.5 million of interest that was accrued as of that date, and Generation continued to accrue interest expense each subsequent month. Generation reserved its 50% ownership share of these amounts. Because Generation expenses the dry storage casks and capitalizes the permanent components of its spent fuel storage facilities, these reserves increased Generation’s operating and maintenance expense approximately $11 million and its capital base approximately $9 million during 2003.
On July 21, 2004, Exelon and the U.S. Department of Justice, in close consultation with the DOE, reached a settlement under which the government will reimburse Exelon for costs associated with storage of spent fuel at Generation’s nuclear stations pending DOE’s fulfillment of its obligations. Under the agreement, Generation immediately received $80 million in gross reimbursements for storage costs already incurred ($53 million net after considering amounts due from Generation to co-owners of certain nuclear stations), with additional amounts to be reimbursed annually for future costs. In all cases, reimbursements will be made only after costs are incurred and only for costs resulting from DOE delays in accepting the fuel. As of December 31, 2004, the amount of spent fuel storage costs for which reimbursement will be requested in mid-2005 from the DOE under the settlement agreement is $33 million net, which is recorded within accounts receivable, other. This amount is comprised of $14 million, which has been recorded as a reduction to operating and maintenance expense, and $12 million, which has been recorded as a reduction to capital expenditures. The remaining $7 million represents amounts owed to the co-owners of the Peach Bottom and Quad Cities generating facilities.
15. Retirement Benefits
Exelon sponsors defined benefit pension plans and postretirement welfare benefit plans for essentially all ComEd, PECO, Generation (except for AmerGen) and Exelon Business Services Company (BSC) employees and certain employees of Enterprises. Substantially all non-union
186
Exelon Corporation and Subsidiary Companies
Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, except per share data unless otherwise noted)
employees and electing union employees hired on or after January 1, 2001 participate in Exelon-sponsored cash balance pension plans. Substantially all non-union employees hired prior to January 1, 2001 were offered a choice to remain in Exelon’s traditional pension plan or transfer to a cash balance pension plan for management employees. Employees of AmerGen participate in separate defined benefit pension plans and postretirement welfare benefit plans sponsored by AmerGen. AmerGen is currently offering its employees a choice to remain in their traditional benefit formula or convert to a cash balance formula.
The costs of providing benefits under these plans are dependent on historical information, such as employee age, length of service and level of compensation, and the actual rate of return on plan assets, in addition to assumptions about the future, including the expected rate of return on plan assets, the discount rate applied to benefit obligations, rate of compensation increase and the anticipated rate of increase in health care costs. The impact of changes in these factors on pension and other postretirement welfare benefit obligations is generally recognized over the expected remaining service life of the employees rather than immediately recognized in the income statement. Exelon uses a December 31 measurement date for the majority of its plans.
Exelon’s traditional and cash balance pension plans are intended to be tax-qualified defined benefit plans, and Exelon has submitted applications to the IRS for rulings on the tax-qualification of the form of each plan. By letters dated April 21, 2004, the IRS notified Exelon that the rulings on its applications for the traditional and management cash balance plans were delayed pending advice from the IRS’s National Office, pursuant to a previously announced moratorium on rulings with respect to plans involved in so called cash balance “conversions.” On June 1, 2004, the IRS issued a favorable ruling on the union cash balance plan.
Various methods used by other employers to accrue and calculate benefits under cash balance plans have been challenged in recent lawsuits. The design of Exelon’s cash balance plans differs in certain material respects from the cash balance plans involved in the cases decided to date, and the courts have not reached uniform decisions on certain issues. In addition, the U.S. Treasury Department recently withdrew proposed regulations intended to clarify the application of certain rules to cash balance plans, and proposed other regulations that could adversely affect the qualified status of Exelon’s cash balance plans. As a result, considerable uncertainty remains regarding the application of the Employee Retirement Income Security Act of 1974 (ERISA), the Internal Revenue Code and Federal employment laws to Exelon’s cash balance plans. Exelon does not know how the current uncertainty will be resolved and cannot determine at this time what impact, if any, future developments in this area will have on its pension plans or the funding of its pension obligations.
Funding is based upon actuarially determined contributions that take into account the amount deductible for income tax purposes and the minimum contribution required under the Employee Retirement Income Security Act of 1974, as amended.
Effective January 1, 2005, Exelon changed the benefit provisions of its postretirement welfare benefit plans. The changes triggered a remeasurement of the plan assets and obligations as of August 1, 2004. The plan change resulted in a reduction in the accumulated postretirement benefit obligation of $106 million and a reduction of other postretirement benefit costs in 2004 of $6 million.
During 2003, Exelon announced an amendment related to the benefit provisions of its postretirement welfare benefit plans. The amendment was effective August 1, 2003 and reduced the benefits attributable to prior service through increased retiree cost-sharing for medical coverage.
187
Exelon Corporation and Subsidiary Companies
Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, except per share data unless otherwise noted)
Due to an overall reduction in active employees during 2003, certain defined benefit pension plans and postretirement welfare benefit plans were subject to curtailment accounting that resulted in a remeasurement of the plan obligations. The threshold basis for curtailment remeasurement was a reduction in future service greater than 5%. The net benefit obligations of the pension plans and the postretirement welfare benefit plans increased by $48 million and $27 million, respectively, in 2003 due to the curtailment.
For certain of Exelon’s defined benefit pension plans, the benefit payments in 2004 exceeded the service and interest cost recognized. As a result, the plans were subject to settlement accounting that resulted in a reduction in the net benefit obligation of $19 million and an increase in 2004 pension cost of $17 million.
On December 22, 2003, Generation purchased British Energy’s 50% interest in AmerGen, and as a result, the obligations associated with AmerGen’s pension and postretirement welfare plans are reflected in the disclosures below as an acquisition.
The following tables provide a roll forward of the changes in the benefit obligations and plan assets for the most recent two years:
| Pension Benefits |
Other Postretirement Benefits |
|||||||||||||||
| 2004 |
2003 |
2004 |
2003 |
|||||||||||||
| Change in benefit obligation: |
||||||||||||||||
| Net benefit obligation at beginning of year |
$ | 8,758 | $ | 7,854 | $ | 3,019 | $ | 2,555 | ||||||||
| Service cost |
128 | 109 | 78 | 68 | ||||||||||||
| Interest cost |
545 | 519 | 163 | 167 | ||||||||||||
| Plan participants’ contributions |
— | — | 17 | 15 | ||||||||||||
| Plan amendments |
— | — | (106 | ) | (337 | ) | ||||||||||
| Actuarial loss (gain) |
964 | 711 | (10 | ) | 559 | |||||||||||
| AmerGen acquisition |
— | 67 | — | 80 | ||||||||||||
| Curtailments/settlements |
(19 | ) | 48 | — | 27 | |||||||||||
| Special accounting costs |
— | — | 16 | 48 | ||||||||||||
| Gross benefits paid |
(601 | ) | (550 | ) | (189 | ) | (163 | ) | ||||||||
| Net benefit obligation at end of year |
$ | 9,775 | $ | 8,758 | $ | 2,988 | $ | 3,019 | ||||||||
| Change in plan assets: |
||||||||||||||||
| Fair value of plan assets at beginning of year |
$ | 6,442 | $ | 5,395 | $ | 1,171 | $ | 958 | ||||||||
| Actual return on plan assets |
723 | 1,189 | 115 | 227 | ||||||||||||
| Employer contributions |
450 | 367 | 132 | 134 | ||||||||||||
| Plan participants’ contributions |
— | — | 17 | 15 | ||||||||||||
| AmerGen acquisition |
— | 41 | — | — | ||||||||||||
| Gross benefits paid |
(601 | ) | (550 | ) | (189 | ) | (163 | ) | ||||||||
| Fair value of plan assets at end of year |
$ | 7,014 | $ | 6,442 | $ | 1,246 | $ | 1,171 | ||||||||
188
Exelon Corporation and Subsidiary Companies
Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, except per share data unless otherwise noted)
The following table provides a reconciliation of benefit obligations, plan assets and funded status of the plans:
| Pension Benefits |
Other Postretirement Benefits |
|||||||||||||||
| 2004 |
2003 |
2004 |
2003 |
|||||||||||||
| Fair value of plan assets at end of year |
$ | 7,014 | $ | 6,442 | $ | 1,246 | $ | 1,171 | ||||||||
| Benefit obligations at end of year |
9,775 | 8,758 | 2,988 | 3,019 | ||||||||||||
| Funding status (plan assets less plan obligations) |
(2,761 | ) | (2,316 | ) | (1,742 | ) | (1,848 | ) | ||||||||
| Amounts not recognized: |
||||||||||||||||
| Miscellaneous adjustment |
— | 14 | — | — | ||||||||||||
| Unrecognized net actuarial loss |
2,954 | 2,203 | 1,046 | 1,129 | ||||||||||||
| Unrecognized prior service cost (benefit) |
170 | 185 | (445 | ) | (420 | ) | ||||||||||
| Unrecognized net transition obligation (asset) |
(4 | ) | (8 | ) | 76 | 86 | ||||||||||
| Net amount recognized |
$ | 359 | $ | 78 | $ | (1,065 | ) | $ | (1,053 | ) | ||||||
The following table provides a reconciliation of the amounts recognized in the Consolidated Balance Sheets as of December 31, 2004 and 2003:
| Pension Benefits |
Other Postretirement Benefits |
|||||||||||||||
| 2004 |
2003 |
2004 |
2003 |
|||||||||||||
| Prepaid benefit cost |
$ | 407 | $ | 175 | $ | — | $ | — | ||||||||
| Accrued benefit cost |
(48 | ) | (97 | ) | (1,065 | ) | (1,053 | ) | ||||||||
| Additional minimum liability |
(2,352 | ) | (1,746 | ) | — | — | ||||||||||
| Intangible asset |
171 | 186 | — | — | ||||||||||||
| Accumulated other comprehensive income |
2,181 | 1,560 | — | — | ||||||||||||
| Net amount recognized |
$ | 359 | $ | 78 | $ | (1,065 | ) | $ | (1,053 | ) | ||||||
The accumulated benefit obligation (ABO) for all defined benefit pension plans was $9,006 million and $8,104 million at December 31, 2004 and 2003, respectively. The acquisition of AmerGen and assumption of its pension liabilities in December 2003 resulted in a $55 million increase in Exelon’s ABO. The following table provides the projected benefit obligation, accumulated benefit obligation, and fair value of plan assets for pension plans with an ABO in excess of plan assets. The table below is also representative of all pension plans with a projected benefit obligation in excess of plan assets.
| December 31, | ||||||
| 2004 |
2003 | |||||
| Projected benefit obligation |
$ | 9,775 | $ | 8,758 | ||
| Accumulated benefit obligation |
9,006 | 8,104 | ||||
| Fair value of plan assets |
7,014 | 6,442 | ||||
189
Exelon Corporation and Subsidiary Companies
Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, except per share data unless otherwise noted)
The following table provides the components of the net periodic benefit costs for the years ended December 31, 2004, 2003 and 2002. The table reflects an annualized reduction in 2004 net periodic postretirement benefit cost of $33 million related to a Federal subsidy provided under the Prescription Drug Act. This subsidy has been accounted for under FSP FAS 106-2, as described in Note 1— Significant Accounting Policies. A portion of the net periodic benefit cost is capitalized within the Consolidated Balance Sheets.
| Pension Benefits |
Other Postretirement Benefits |
|||||||||||||||||||||||
| 2004 |
2003 |
2002 |
2004 |
2003 |
2002 |
|||||||||||||||||||
| Service cost |
$ | 128 | $ | 109 | $ | 95 | $ | 78 | $ | 68 | $ | 57 | ||||||||||||
| Interest cost |
545 | 519 | 525 | 163 | 167 | 160 | ||||||||||||||||||
| Expected return on assets |
(611 | ) | (584 | ) | (628 | ) | (90 | ) | (75 | ) | (93 | ) | ||||||||||||
| Amortization of: |
||||||||||||||||||||||||
| Transition obligation (asset) |
(4 | ) | (4 | ) | (4 | ) | 10 | 10 | 10 | |||||||||||||||
| Prior service cost |
15 | 16 | 16 | (81 | ) | (54 | ) | (37 | ) | |||||||||||||||
| Actuarial (gain) loss |
73 | 23 | — | 44 | 47 | 6 | ||||||||||||||||||
| Curtailment/settlement charges |
22 | 59 | — | 2 | 21 | — | ||||||||||||||||||
| Net periodic benefit cost |
$ | 168 | $ | 138 | $ | 4 | $ | 126 | $ | 184 | $ | 103 | ||||||||||||
| Special accounting costs |
$ | — | $ | — | $ | 4 | $ | 16 | $ | 48 | $ | — | ||||||||||||
| Other additional information: |
||||||||||||||||||||||||
| Increase (decrease) in other comprehensive income (net of tax) |
$ | (392 | ) | $ | 26 | $ | (1,007 | ) | $ | — | $ | — | $ | — | ||||||||||
Exelon’s costs of providing pension and postretirement benefit plans are dependent upon a number of factors, such as the rates of return on pension plan assets, discount rate, and the rate of increase in health care costs. The market value of plan assets was affected by sharp declines in the equity market from 2000 through 2002. As a result, at December 31, 2002, Exelon was required to recognize an additional minimum liability and an intangible asset as prescribed by SFAS No. 87. The liability was recorded as a reduction to shareholders’ equity. The amount of the reduction to shareholders’ equity (net of income taxes) in 2002 was $1.0 billion. The recording of this reduction did not affect net income or cash flows in 2002 or compliance with debt covenants. In 2003, the additional minimum liability was reduced by $69 million and shareholders’ equity increased by $26 million (net of income taxes) as a result of accounting associated with Exelon’s pension plans. In 2004, the additional minimum pension liability was increased by $606 million and shareholders’ equity decreased by $392 million (net of income taxes) as a result of accounting associated with Exelon’s pension plans.
Special accounting costs of $16 million and $48 million in 2004 and 2003, respectively, represent special health and welfare severance benefits offered to terminated employees. These costs were recorded pursuant to SFAS No. 112. See Note 10—Severance Accounting for additional information. Special accounting costs of $4 million in 2002 represented accelerated separation and enhancement benefits provided to PECO employees expected to be terminated as a result of the PECO / Unicom Merger.
Prior service cost is amortized on a straight-line basis over the average remaining service period of employees expected to receive benefits under the plans.
190
Exelon Corporation and Subsidiary Companies
Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, except per share data unless otherwise noted)
The following weighted average assumptions were used to determine the benefit obligations at December 31 2004, 2003 and 2002:
| Pension Benefits |
Other Postretirement Benefits | |||||||||||
| 2004 (a) |
2003 |
2002 |
2004 (a) |
2003 |
2002 | |||||||
| Discount rate |
5.75% | 6.25% | 6.75% | 5.75% | 6.25% | 6.75% | ||||||
| Rate of compensation increase |
4.00% | 4.00% | 4.00% | 4.00% | 4.00% | 4.00% | ||||||
| Health care cost trend on covered charges |
N/A | N/A | N/A | 9.00% decreasing to ultimate trend of 5.0% in 2010 |
10.00% decreasing to ultimate trend of 4.5% in 2011 |
8.50% decreasing to ultimate trend of 4.5% in 2008 | ||||||
| (a) | Assumptions used to determine year-end 2004 benefit obligations will be the assumptions used to estimate the expected costs of benefits in 2005. |
The following weighted average assumptions were used to determine the net periodic benefit costs for years ended December 31 2004, 2003 and 2002:
| Pension Benefits |
Other Postretirement Benefits | |||||||||||
| 2004 |
2003 |
2002 |
2004 |
2003 |
2002 | |||||||
| Discount rate |
6.25% | 6.60-6.75% | 7.35% | 6.25% | 6.60-6.75% | 7.35% | ||||||
| Expected return on plan assets |
9.00% | 9.00% | 9.50% | 8.33-8.35% | 8.40% | 8.80% | ||||||
| Rate of compensation increase |
4.00% | 4.00% | 4.00% | 4.00% | 4.00% | 4.00% | ||||||
| Health care cost trend on covered charges |
N/A | N/A | N/A | 10.00% decreasing to ultimate trend of 4.5% in 2011 |
8.50% decreasing to ultimate trend of 4.5% in 2008 |
10.00% decreasing to ultimate trend of 4.5% in 2008 | ||||||
In managing its pension and postretirement plan assets, Exelon utilizes a diversified, strategic asset allocation to efficiently and prudently generate investment returns that will meet the objectives of the investment trusts that hold the plan assets. Asset / Liability studies that incorporate specific plan objectives as well as assumptions regarding long-term capital market returns and volatilities generate the specific asset allocations for the trusts. In general, Exelon’s investment strategy reflects the belief that over the long term, equities are expected to outperform fixed-income investments. The long-term nature of the trusts make them well suited to bear the risk of added volatility associated with equity securities, and, accordingly, the asset allocations of the trusts usually reflect a higher allocation to equities as compared to fixed-income securities. Non-U.S. equity securities are used to diversify some of the volatility of the U.S. equity market while providing comparable long-term returns. Alternative asset classes, such as private equity and real estate, may be utilized for additional diversification and return potential when appropriate. Exelon’s investment guidelines do limit exposure to investments in more volatile sectors.
Exelon generally maintains 60% of its plan assets in equity securities and 40% of its plan assets in fixed-income securities. On a quarterly basis, Exelon reviews the actual asset allocations and follows a rebalancing procedure in order to remain within an allowable range of these targeted percentages.
191
Exelon Corporation and Subsidiary Companies
Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, except per share data unless otherwise noted)
In selecting the expected rate of return on plan assets, Exelon considers historical returns for the types of investments that its plans hold. Historical returns and volatilities are modeled to determine asset allocations that best meet the objectives of the asset / liability studies. These asset allocations, when viewed over a long-term historical view of the capital markets, yield an expected return on assets in excess of 9%.
Exelon’s pension plan weighted average asset allocations at December 31, 2004 and 2003 and target allocation for 2004 were as follows:
| Percentage of Plan Assets at December 31, |
|||||||||
| Asset Category |
Target Allocation at December 31, 2004 |
2004 |
2003 |
||||||
| Equity securities |
60 | % | 63 | % | 64 | % | |||
| Debt securities |
35-40 | 33 | 32 | ||||||
| Real estate |
0-5 | 4 | 4 | ||||||
| Total |
100 | % | 100 | % | |||||
Exelon’s other postretirement benefit plan weighted average asset allocations at December 31, 2004 and 2003 and target allocation for 2004 were as follows:
| Percentage of Plan Assets at December 31, |
|||||||||
| Asset Category |
Target Allocation at December 31, 2004 |
2004 |
2003 |
||||||
| Equity securities |
60-65 | % | 64 | % | 67 | % | |||
| Debt securities |
35-40 | 34 | 33 | ||||||
| Real estate |
— | 2 | — | ||||||
| Total |
100 | % | 100 | % | |||||
Exelon’s pension plans and postretirement welfare benefit plans do not directly hold shares of Exelon common stock.
Assumed health care cost trend rates have a significant effect on the costs reported for the health care plans. A one percentage point change in assumed health care cost trend rates would have the following effects:
| Effect of a one percentage point increase in assumed health care cost trend |
||||
| on total service and interest cost components |
$ | 34 | ||
| on postretirement benefit obligation |
$ | 327 | ||
| Effect of a one percentage point decrease in assumed health care cost trend |
||||
| on total service and interest cost components |
$ | (28 | ) | |
| on postretirement benefit obligation |
$ | (276 | ) |
In the fourth quarter of 2004, Exelon’s Board of Directors approved a proposal to make contributions of approximately $2 billion in 2005 to the Exelon defined benefit pension plans, reducing the under funded status of these plans. These contributions exclude benefit payments expected to be
192
Exelon Corporation and Subsidiary Companies
Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, except per share data unless otherwise noted)
made directly from corporate assets. Of the $2 billion expected to be contributed to the pension plans during 2005, $13 million is estimated to be needed to satisfy ERISA minimum funding requirements.
Estimated future benefit payments to participants in Exelon’s pension plans and postretirement welfare benefit plans as of December 31, 2004 were:
| Pension Benefits |
Other Postretirement Benefits (a) | |||||
| 2005 |
$ | 531 | $ | 163 | ||
| 2006 |
530 | 170 | ||||
| 2007 |
536 | 181 | ||||
| 2008 |
537 | 190 | ||||
| 2009 |
544 | 197 | ||||
| 2010 through 2014 |
2,911 | 1,088 | ||||
| Total estimated future benefits payments |
$ | 5,589 | $ | 1,989 | ||
| (a) | Estimated future benefit payments do not reflect an anticipated Federal subsidy provided through the Prescription Drug Act. The Federal subsidies to be received by Exelon in the years 2006, 2007, 2008, 2009 and from 2010 through 2014 are estimated to be $8 million, $8 million, $9 million, $10 million and $63 million, respectively. A subsidy is not anticipated for 2005. |
Exelon sponsors savings plans for the majority of its employees. The plans allow employees to contribute a portion of their pre-tax income in accordance with specified guidelines. Exelon matches a percentage of the employee contribution up to certain limits. The cost of Exelon’s matching contribution to the savings plans totaled $57 million, $55 million, and $63 million in 2004, 2003 and 2002, respectively.
16. Fair Value of Financial Assets and Liabilities
Non-Derivative Financial Assets and Liabilities
Fair Value. As of December 31, 2004 and 2003, Exelon’s carrying amounts of cash and cash equivalents, accounts receivable, accounts payable and accrued liabilities are representative of fair value because of the short-term nature of these instruments. Fair values for long-term debt and preferred securities of subsidiaries are determined by an external valuation model which is based on conventional discounted cash flow methodology and utilizes assumptions of current market pricing curves.
The carrying amounts and fair values of Exelon’s financial liabilities as of December 31, 2004 and 2003 were as follows:
| 2004 |
2003 | |||||||||||
| Carrying Amount |
Fair Value |
Carrying Amount |
Fair Value | |||||||||
| Long-term debt (including amounts due within one year) |
$ | 7,719 | $ | 8,372 | $ | 9,274 | $ | 9,922 | ||||
| Long-term debt to ComEd Transitional Funding Trust and PETT (including amounts due within one year) |
||||||||||||
| 4,797 | 5,182 | 5,525 | 6,006 | |||||||||
| Long-term debt to other financing trusts |
545 | 573 | 545 | 567 | ||||||||
| Preferred securities of subsidiaries |
87 | 69 | 87 | 71 | ||||||||
193
Exelon Corporation and Subsidiary Companies
Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, except per share data unless otherwise noted)
Credit Risk. Financial instruments that potentially subject Exelon to concentrations of credit risk consist principally of cash equivalents and customer accounts receivable. Exelon places its cash equivalents with high-credit quality financial institutions. Generally, such investments are in excess of the Federal Deposit Insurance Corporation limits. Concentrations of credit risk with respect to customer accounts receivable are limited due to Exelon’s large number of customers and, in the case of the Energy Delivery business, their dispersion across many industries.
Derivative Instruments
Fair Value. The fair values of Exelon’s interest-rate swaps and power purchase and sale contracts are determined using quoted exchange prices, external dealer prices or internal valuation models which utilize assumptions of future energy prices and available market pricing curves.
Interest-Rate Swaps. At December 31, 2004 and 2003, Exelon had $0.4 billion and $1.3 billion, respectively, of notional amounts of interest-rate swaps outstanding with net deferred gains (losses) of $11 million and $(44) million, respectively, as follows:
| Notional Amount |
Exelon Pays |
Counterparty Pays |
Fair Value 12/31/04 |
Fair Value 12/31/03 |
|||||||||||
| Fair-Value Hedges |
|||||||||||||||
| ComEd |
$ | 240 | 3 Month LIBOR plus 1.12% – 1.60% |
6.15% | $ | 9 | $ | — | |||||||
| ComEd |
485 | 3 Month LIBOR plus 1.68% – 3.09% |
6.40% – 8.25% | — | 33 | ||||||||||
| Cash-Flow Hedges |
|||||||||||||||
| Exelon |
200 | 4.59% – 4.65% | 3 Month LIBOR | 2 | — | ||||||||||
| Generation |
861 | (a) | 5.71% – 5.74% | 3 Month LIBOR | — | (77 | ) | ||||||||
| Net Deferred Gains (Losses) |
$ | 11 | $ | (44 | ) | ||||||||||
| (a) | Generation was released from its obligation due to sale of Boston Generating assets. |
During 2004, Exelon settled interest-rate swaps in aggregate notional amounts of $800 million, and recorded net pre-tax gains of $27 million. Of the $27 million net gain, $26 million was the result of settlement by ComEd of interest-rate swaps designated as fair-value hedges and is being amortized as a reduction to interest expense over the remaining life of the related debt. The remaining $1 million was the result of settlement by Exelon and PECO of interest-rate swaps designated as cash-flow hedges and is being amortized over the lives of the related debt.
During 2003, Exelon settled interest-rate swaps in aggregate notional amounts of $860 million and recorded net pre-tax gains of $1 million. The $1 million gain was the result of settlement by PECO and Generation of interest-rate swaps designated as cash-flow hedges and is being amortized over the lives of the related debt. Additionally, during 2003, Exelon settled interest-rate swaps in aggregate notional amounts of $1,070 million and recorded net pre-tax losses of $45 million which were recorded as regulatory assets. The pre-tax losses on settlements of interest-rate swaps are being amortized over the life of the related debt to interest expense.
194
Exelon Corporation and Subsidiary Companies
Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, except per share data unless otherwise noted)
Exelon recorded income of $0.2 million for the year ended December 31, 2004, representing the ineffective portions of changes in the fair value of cash-flow hedge positions. This amount was associated with the settlement of interest-rate swaps in December 2004 and was included in other, net on Exelon’s consolidated statements of income. Exelon did not have any amount excluded from the measure of effectiveness for the year ended December 31, 2004.
During 2004 and 2003, no amounts were reclassified from accumulated other comprehensive income into earnings as a result of forecasted financing transactions no longer being probable.
Energy-Related Derivatives. Exelon utilizes derivatives to manage the utilization of its available generating capacity and the provision of wholesale energy to its affiliates. Exelon also utilizes energy option contracts and energy financial swap arrangements to limit the market price risk associated with forward energy commodity contracts. Additionally, Exelon enters into certain energy-related derivatives for trading or speculative purposes. At December 31, 2004 and 2003, Exelon had $145 million and $213 million, respectively, of energy derivatives recorded as net liabilities at fair value on the Consolidated Balance Sheets, which includes the energy derivatives at Generation discussed below.
For the years ended December 31, 2004, 2003, and 2002, Generation recognized net unrealized gains of $42 million, net unrealized losses of $16 million and net unrealized gains of $6 million, respectively, relating to mark-to-market activity of certain non-trading power purchase and sale contracts pursuant to SFAS No. 133. Mark-to-market activity on non-trading power purchase and sale contracts are reported in fuel and purchased power. For the years ended December 31, 2004, 2003 and 2002, Generation recognized net unrealized gains of $3 million and net unrealized losses of $3 million and $9 million, respectively, relating to mark-to-market activity on derivative instruments entered into for trading purposes. Gains and losses associated with financial trading are reported as revenue in the Consolidated Statements of Income.
Exelon Energy has entered into a limited number of energy commodity derivative contracts in connection with its service of gas customers. Prior to January 1, 2004, contracts were maintained by Exelon Energy. While the majority of these contracts qualify as normal purchases and sales or as cash-flow hedges under SFAS No. 133, $15 million was recorded as an increase to fuel expense in 2003 primarily as a result of the reversal of the 2002 mark-to-market adjustments. At December 31, 2004, Exelon Energy’s contracts are included in Generation’s mark-to-market activity. At December 31, 2003, Exelon had net assets of $3 million on the Consolidated Balance Sheets related to Exelon Energy’s mark-to-market contracts. Exelon Energy’s counterparties in these contracts were all investment grade.
As of December 31, 2004, $194 million of deferred net losses on derivative instruments in accumulated other comprehensive income are expected to be reclassified to earnings during the next twelve months. Amounts in accumulated other comprehensive income related to changes in interest-rate cash-flow hedges are reclassified into earnings when the interest payment occurs or when ineffectiveness has been determined. Amounts in accumulated other comprehensive income related to changes in energy commodity cash-flow hedges are reclassified into earnings when the forecasted purchase or sale of the energy commodity occurs. The majority of Exelon’s cash-flow hedges are expected to settle within the next three years.
Credit Risk Associated with Derivative Instruments. Exelon would be exposed to credit-related losses in the event of non-performance by counterparties that issue derivative instruments. The credit
195
Exelon Corporation and Subsidiary Companies
Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, except per share data unless otherwise noted)
exposure of derivatives contracts is represented by the fair value of contracts at the reporting date. For energy-related derivative instruments, Generation has entered into payment netting agreements or enabling agreements that allow for payment netting with the majority of its large counterparties, which reduce Generation’s exposure to counterparty risk by providing for the offset of amounts payable to the counterparty against amounts receivable from the counterparty. The notional amount of derivatives does not represent amounts that are exchanged by the parties and, thus, is not a measure of Exelon’s exposure. The amounts exchanged are calculated on the basis of the notional or contract amounts, as well as on the other terms of the derivatives, which relate to interest rates and the volatility of these rates.
Nuclear Decommissioning Trust Fund Investments
Investments as of December 31, 2004 and 2003. Exelon classifies investments in trust accounts for decommissioning nuclear plants as available-for-sale and estimates their fair value based on quoted market prices for the securities held in trust funds. These investments are held to fund Exelon’s decommissioning obligation for its nuclear plants. Decommissioning expenditures are expected to occur primarily after the plants are retired. Based on current licenses and anticipated renewals, decommissioning expenditures for plants in operation are currently estimated to begin in 2029. See Note 14—Nuclear Decommissioning and Spent Fuel Storage for further information regarding the decommissioning of Generation’s nuclear plants.
The following tables show the fair values, gross unrealized gains and losses and amortized cost bases of the securities held in these trust accounts as of December 31, 2004 and 2003.
| December 31, 2004 | |||||||||||||
| Amortized Cost |
Gross Unrealized |
Gross Unrealized Losses |
Estimated Fair Value | ||||||||||
| Cash and cash equivalents |
$ | 184 | $ | — | $ | — | $ | 184 | |||||
| Equity securities |
2,194 | 538 | (37 | ) | 2,695 | ||||||||
| Debt securities |
|||||||||||||
| Federal government obligations |
1,447 | 51 | (4 | ) | 1,494 | ||||||||
| Other debt securities |
855 | 37 | (3 | ) | 889 | ||||||||
| Total debt securities |
2,302 | 88 | (7 | ) | 2,383 | ||||||||
| Total available-for-sale securities |
$ | 4,680 | $ | 626 | $ | (44 | ) | $ | 5,262 | ||||
| December 31, 2003 | |||||||||||||
| Amortized Cost |
Gross Unrealized Gains |
Gross Unrealized Losses |
Estimated Fair Value | ||||||||||
| Cash and cash equivalents |
$ | 84 | $ | — | $ | — | $ | 84 | |||||
| Equity securities |
2,402 | 300 | (294 | ) | 2,408 | ||||||||
| Debt securities |
|||||||||||||
| Federal government obligations |
1,574 | 65 | (4 | ) | 1,635 | ||||||||
| Other debt securities |
567 | 29 | (2 | ) | 594 | ||||||||
| Total debt securities |
2,141 | 94 | (6 | ) | 2,229 | ||||||||
| Total available-for-sale securities |
$ | 4,627 | $ | 394 | $ | (300 | ) | $ | 4,721 | ||||
196
Exelon Corporation and Subsidiary Companies
Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, except per share data unless otherwise noted)
The fixed-income available-for-sale securities held at December 31, 2004 have an average maturity range of six to thirteen years. The cost of these securities was determined on the basis of specific identification.
Impairment Evaluation in 2004. At December 31, 2004, Exelon had gross unrealized gains of $626 million and gross unrealized losses of $44 million related to the nuclear decommissioning trust fund investments. At December 31, 2003, Exelon had gross unrealized gains of $394 million and gross unrealized losses of $300 million related to the nuclear decommissioning trust fund investments. With the exception of the portion of these amounts primarily related to AmerGen, as a result of ComEd’s and PECO’s regulatory arrangements for decommissioning costs, approximately $469 million of these net unrealized gains were recorded as an increase to regulatory liabilities.
Exelon evaluates decommissioning trust fund investments for other-than-temporary impairments by analyzing the historical performance, cost basis and market value of securities in unrealized loss positions in comparison to related market indices. During 2004, Exelon concluded that certain trust fund investments were other-than-temporarily impaired based on various factors assessed in the aggregate, including the duration and severity of the impairment, the anticipated recovery of the securities and considerations of Exelon’s ability and intent to hold the investments until the recovery of their cost basis. This determination resulted in an $8 million impairment charge recorded in other income and deductions associated with the trust funds for the decommissioning of the AmerGen plants. Also, Exelon realized $260 million of the previously unrealized losses associated with the trust investments for the decommissioning of the former ComEd and PECO plants. As both realized and unrealized losses are included as a reduction in the fair value of the investments and in the fair value of the regulatory liability, realization of these losses associated with the former ComEd and PECO plants had no net income impact on Exelon’s results of operations or financial position.
Unrealized Gains and Losses. Net unrealized gains of $582 million were included in regulatory assets, regulatory liabilities or accumulated other comprehensive income in Exelon’s Consolidated Balance Sheet at December 31, 2004. Net unrealized gains of $94 million were included in accumulated depreciation, regulatory assets and accumulated other comprehensive income in Exelon’s Consolidated Balance Sheet at December 31, 2003.
The following table provides information regarding Exelon’s available-for-sale securities held in nuclear decommissioning trust funds in an unrealized loss position that were not considered other-than-temporarily impaired. The following tables show the investments’ gross unrealized losses and fair value, aggregated by investment category and length of time that individual securities have been in a continuous unrealized loss position, at December 31, 2004 and 2003.
| December 31, 2004 | ||||||||||||||||||
| Less than 12 months |
12 months or more |
Total | ||||||||||||||||
| Gross Unrealized Losses |
Fair Value |
Gross Unrealized Losses |
Fair Value |
Gross Unrealized Losses |
Fair Value | |||||||||||||
| Equity securities |
$ | 16 | $ | 197 | $ | 21 | $ | 278 | $ | 37 | $ | 475 | ||||||
| Debt securities |
||||||||||||||||||
| Government obligations |
2 | 207 | 2 | 68 | 4 | 275 | ||||||||||||
| Other debt securities |
2 | 182 | 1 | 22 | 3 | 204 | ||||||||||||
| Total debt securities |
4 | 389 | 3 | 90 | 7 | 479 | ||||||||||||
| Total temporarily impaired securities |
$ | 20 | $ | 586 | $ | 24 | $ | 368 | $ | 44 | $ | 954 | ||||||
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(Dollars in millions, except per share data unless otherwise noted)
| December 31, 2003 | ||||||||||||||||||
| Less than 12 months |
12 months or more |
Total | ||||||||||||||||
| Gross Unrealized Losses |
Fair Value |
Gross Unrealized Losses |
Fair Value |
Gross Unrealized Losses |
Fair Value | |||||||||||||
| Equity securities |
$ | 33 | $ | 231 | $ | 261 | $ | 775 | $ | 294 | $ | 1,006 | ||||||
| Debt securities |
||||||||||||||||||
| Government obligations |
4 | 232 | — | 11 | 4 | 243 | ||||||||||||
| Other debt securities |
2 | 117 | — | 2 | 2 | 119 | ||||||||||||
| Total debt securities |
6 | 349 | — | 13 | 6 | 362 | ||||||||||||
| Total temporarily impaired securities |
$ | 39 | $ | 580 | $ | 261 | $ | 788 | $ | 300 | $ | 1,368 | ||||||
Exelon evaluates the historical performance, cost basis and market value of securities in unrealized loss positions in comparison to related market indices to assess whether or not the securities are other-than-temporarily impaired. Exelon concluded that the trending of the related market indices, the historical performance of these securities over a long-term time horizon and the level of insignificance of the unrealized loss as a percentage of the cost of the individual securities indicates that the securities are not other-than-temporarily impaired.
Sale of Nuclear Decommissioning Trust Fund Investments. Proceeds from the sale of decommissioning trust fund investments and gross realized gains and losses on those sales for the years ended December 31, 2004, 2003 and 2002 were as follows:
| For the Years Ended December 31, |
||||||||||||
| 2004 |
2003 |
2002 |
||||||||||
| Proceeds from sales |
$ | 2,320 | $ | 2,341 | $ | 1,612 | ||||||
| Gross realized gains |
115 | 219 | 56 | |||||||||
| Gross realized losses |
(43 | ) | (235 | ) | (86 | ) | ||||||
Net realized gains of $72 million and net realized losses of $16 million and $32 million were recognized in other income and deductions in Exelon’s Consolidated Statements of Income for the years ended December 31, 2004, 2003 and 2002, respectively. Additionally, net realized gains $2 million were recognized in accumulated depreciation and regulatory assets in Exelon’s Consolidated Balance Sheets at December 31, 2002. Prior to January 1, 2003, realized gains and losses related to the former PECO units were included in accumulated depreciation. See Note 14—Nuclear Decommissioning and Spent Fuel for further information regarding the nuclear decommissioning trusts.
17. Preferred Securities
At December 31, 2004 and 2003, Exelon was authorized to issue up to 100,000,000 shares of preferred stock, none of which was outstanding.
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(Dollars in millions, except per share data unless otherwise noted)
Preferred and Preference Stock of Subsidiaries
At December 31, 2004 and 2003, cumulative preferred stock of PECO, no par value, consisted of 15,000,000 shares authorized and the outstanding amounts set forth below:
| Current Redemption Price (a) |
December 31, | ||||||||||||
| 2004 |
2003 |
2004 |
2003 | ||||||||||
| Shares Outstanding |
Dollar Amount | ||||||||||||
| Series (without mandatory redemption) |
|||||||||||||
| $4.68 (Series D) |
$ | 104.00 | 150,000 | 150,000 | $ | 15 | $ | 15 | |||||
| $4.40 (Series C) |
112.50 | 274,720 | 274,720 | 27 | 27 | ||||||||
| $4.30 (Series B) |
102.00 | 150,000 | 150,000 | 15 | 15 | ||||||||
| $3.80 (Series A) |
106.00 | 300,000 | 300,000 | 30 | 30 | ||||||||
| Total preferred stock |
874,720 | 874,720 | $ | 87 | $ | 87 | |||||||
| (a) | Redeemable, at the option of PECO, at the indicated dollar amounts per share, plus accrued dividends. |
At December 31, 2004 and 2003, ComEd prior preferred stock and ComEd preference stock consisted of 850,000 shares and 6,810,451 shares authorized, respectively, none of which was outstanding.
18. Common Stock
At December 31, 2004 and 2003, common stock without par value consisted of 1,200,000,000 shares authorized and 664,187,996 and 656,365,044 shares outstanding, respectively.
Stock Split
On January 27, 2004, the Board of Directors of Exelon approved a 2-for-1 stock split of Exelon’s common stock. The distribution date was May 5, 2004. The share and per-share amounts have been adjusted for all periods presented to reflect the stock split.
Share Repurchases
Share Repurchase Program. In April 2004, Exelon’s Board of Directors approved a discretionary share repurchase program that allows Exelon to repurchase shares of its common stock on a periodic basis in the open market. The share repurchase program is intended to mitigate, in part, the dilutive effect of shares issued under Exelon’s employee stock option plan and Exelon’s Employee Stock Purchase Plan (ESPP). The aggregate value of the shares of common stock repurchased pursuant to the program cannot exceed the economic benefit received after January 1, 2004 due to stock option exercises and share purchases pursuant to Exelon’s ESPP. The economic benefit consists of the direct cash proceeds from purchases of stock and the tax benefits associated with exercises of stock options. The share repurchase program has no specified limit on the number of shares that may be repurchased and no specified termination date. Any shares repurchased are held as treasury shares unless cancelled or reissued at the discretion of Exelon’s management. Treasury shares are recorded at cost. During 2004, 2.3 million shares of common stock were purchased under the share repurchase program for $75 million.
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Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, except per share data unless otherwise noted)
Other Share Repurchases. In November 2004, Exelon repurchased 0.2 million shares of common stock from a retired executive for $7 million. These shares are held as treasury shares and recorded at cost.
Stock-Based Compensation Plans
Exelon maintains Long-Term Incentive Plans (LTIPs) for certain full-time salaried employees. The types of long-term incentive awards that have been granted under the LTIPs are non-qualified options to purchase shares of Exelon’s common stock and common stock awards. At December 31, 2004, there were options for approximately 14,770,078 shares remaining for issuance under the LTIPs.
The exercise price of the stock options is equal to the fair market value of the underlying stock on the date of option grant. Options granted under the LTIPs become exercisable upon attainment of a target share value and/or specified vesting date. All options expire 10 years from the date of grant. The vesting period of options outstanding as of December 31, 2004 generally ranged from 3 years to 4 years.
Information with respect to the LTIPs at December 31, 2004 and changes for the three years then ended, is as follows:
| Shares 2004 |
Weighted Average Exercise Price (per share) 2004 |
Shares 2003 |
Weighted Average Exercise Price (per share) 2003 |
Shares 2002 |
Weighted Average Exercise Price (per share) 2002 | |||||||||||||
| Balance at January 1 |
28,307,386 | $ | 24.51 | 31,773,980 | $ | 22.90 | 28,079,992 | $ | 21.98 | |||||||||
| Options granted/assumed |
6,994,288 | 32.57 | 6,346,400 | 24.85 | 7,877,264 | 23.56 | ||||||||||||
| Options exercised |
(9,373,662 | ) | 24.20 | (9,017,390 | ) | 19.03 | (3,642,678 | ) | 16.69 | |||||||||
| Options canceled |
(722,727 | ) | 27.34 | (795,604 | ) | 25.09 | (540,598 | ) | 26.81 | |||||||||
| Balance at December 31 |
25,205,285 | $ | 26.78 | 28,307,386 | $ | 24.51 | 31,773,980 | $ | 22.90 | |||||||||
| Exercisable at December 31 |
13,097,192 | $ | 24.88 | 18,032,696 | $ | 24.33 | 20,982,368 | $ | 21.98 | |||||||||
| Weighted average fair value of options granted during year |
$ | 9.58 | $ | 5.52 | $ | 6.81 | ||||||||||||
The fair value of each option is estimated on the date of grant using the Black-Scholes option-pricing model with the following weighted average assumptions used for grants in 2004, 2003 and 2002, respectively:
| 2004 |
2003 |
2002 |
|||||||
| Dividend yield |
3.3 | % | 3.3 | % | 3.3 | % | |||
| Expected volatility |
19.7 | % | 30.5 | % | 36.8 | % | |||
| Risk-free interest rate |
3.25 | % | 3.0 | % | 4.6 | % | |||
| Expected life (years) |
5.0 | 5.0 | 5.0 |
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Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, except per share data unless otherwise noted)
At December 31, 2004, the options outstanding, based on ranges of exercise prices, were as follows:
| Options Outstanding |
Options Exercisable | |||||||||||
| Range of Exercise Prices |
Number Outstanding |
Weighted Average Remaining Contractual (years) |
Weighted Average Exercise Price |
Number Exercisable |
Weighted Average Exercise Price | |||||||
| $6.97-$10.46 |
49,050 | 3.0 | $ | 9.84 | 49,050 | $ | 9.84 | |||||
| $10.47-$13.95 |
383,064 | 1.9 | 12.46 | 383,064 | 12.46 | |||||||
| $13.96-$17.44 |
114,628 | 2.3 | 15.07 | 114,628 | 15.07 | |||||||
| $17.45-$20.93 |
3,472,093 | 4.4 | 19.28 | 3,472,093 | 19.28 | |||||||
| $20.94-$24.42 |
4,022,670 | 6.5 | 23.43 | 2,373,736 | 23.41 | |||||||
| $24.43-$27.91 |
5,204,363 | 7.7 | 24.86 | 1,293,402 | 24.91 | |||||||
| $27.92-$31.40 |
4,545,548 | 5.7 | 29.74 | 4,531,898 | 29.74 | |||||||
| $31.41-$34.90 |
7,413,869 | 8.6 | 32.66 | 879,321 | 33.37 | |||||||
| Total |
25,205,285 | 6.8 | $ | 26.78 | 13,097,192 | $ | 24.88 | |||||
Exelon common share awards of 1,813,874, 901,958 and 1,180,148 shares were granted under Exelon’s LTIPs and board compensation plans during 2004, 2003 and 2002, respectively. Compensation costs related to these awards are accrued and expensed over the vesting period, typically up to 5 years from the grant date. Exelon recognized stock-based compensation expense of $65 million, $31 million and $20 million during 2004, 2003 and 2002, respectively. At December 31, 2004, Exelon had a liability of $81 million related to outstanding awards not yet settled through cash payments or share issuances.
In June 2001, the Board of Directors of Exelon approved the ESPP. The purpose of the ESPP is to provide employees of Exelon and its subsidiary companies the right to purchase shares of Exelon’s common stock at below-market prices. A total of 5,357,745 shares of Exelon’s common stock have been reserved for issuance under the ESPP. Employees’ purchases are limited to no more than 155 shares per quarter and no more than $25,000 in fair market value in any plan year. Employees purchased 309,492, 418,652, and 514,910 shares of Exelon common stock under the ESPP in 2004, 2003 and 2002, respectively.
Fund Transfer Restrictions
Under applicable law, Exelon is precluded from borrowing or receiving any extension of credit or indemnity from its subsidiaries and can lend to, but not borrow from, Exelon’s intercompany money pool. Additionally, under applicable Federal law, Exelon, ComEd, PECO and Generation can pay dividends only from retained, undistributed or current earnings. Under Illinois law, ComEd may not pay any dividend on its stock unless, among other things, “its earnings and earned surplus are sufficient to declare and pay same after provision is made for reasonable and proper reserves,” or unless it has specific authorization from the ICC. At December 31, 2004 and 2003, Exelon had retained earnings of $3.4 billion and $2.3 billion, respectively, which included ComEd retained earnings of $1,102 million and $883 million (all which has been appropriated for future dividends at December 31, 2004), PECO retained earnings of $607 million and $546 million, and Generation undistributed earnings of $761 million and $602 million, respectively. At December 31, 2004 and 2003, Exelon’s common equity to total capitalization ratio was 41% and 35%, respectively.
Undistributed Losses of Equity Method Investments
Exelon had undistributed losses of equity method investments of $106 million and $55 million at December 31, 2004 and 2003, respectively.
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Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, except per share data unless otherwise noted)
19. Earnings Per Share
Diluted earnings per share are calculated by dividing net income by the weighted average number of shares of common stock outstanding, including shares to be issued upon exercise of stock options outstanding under Exelon’s stock option plans considered to be common stock equivalents. The following table sets forth the computation of basic and diluted earnings per share and shows the effect of these stock options on the weighted average number of shares outstanding used in calculating diluted earnings per share:
| 2004 |
2003 |
2002 |
||||||||
| Income before cumulative effect of changes in accounting principles |
$ | 1,841 | $ | 793 | $ | 1,670 | ||||
| Cumulative effect of changes in accounting principles |
23 | 112 | (230 | ) | ||||||
| Net income |
$ | 1,864 | $ | 905 | $ | 1,440 | ||||
| Average common shares outstanding—basic |
661 | 651 | 645 | |||||||
| Assumed exercise of stock options |
8 | 6 | 4 | |||||||
| Average common shares outstanding—diluted |
669 | 657 | 649 | |||||||
| Earnings per average common share—Basic: |
||||||||||
| Income before cumulative effect of changes in accounting principles |
$ | 2.79 | $ | 1.22 | $ | 2.59 | ||||
| Cumulative effect of changes in accounting principles |
0.03 | 0.17 | (0.36 | ) | ||||||
| Net income |
$ | 2.82 | $ | 1.39 | $ | 2.23 | ||||
| Earnings per average common share—Diluted: |
||||||||||
| Income before cumulative effect of changes in accounting principles |
$ | 2.75 | $ | 1.21 | $ | 2.57 | ||||
| Cumulative effect of changes in accounting principles |
0.03 | 0.17 | (0.35 | ) | ||||||
| Net income |
$ | 2.78 | $ | 1.38 | $ | 2.22 | ||||
The number of stock options not included in the calculation of diluted common shares outstanding due to their antidilutive effect was approximately nine million and ten million for 2003 and 2002, respectively. There were no stock options excluded for 2004.
20. Commitments and Contingencies
Nuclear Insurance
The Price-Anderson Act limits the liability of nuclear reactor owners for claims that could arise from a single incident. As of December 31, 2004, the limit is $10.76 billion and is subject to change to account for the effects of inflation and changes in the number of licensed reactors. Through its subsidiaries, Exelon carries the maximum available commercial insurance of $300 million for each operating site and the remaining $10.46 billion is provided through mandatory participation in a financial protection pool. Under the Price-Anderson Act, all nuclear reactor licensees can be assessed a maximum charge per reactor per incident. The maximum assessment for all nuclear operators per reactor per incident (including a 5% surcharge) is $100.6 million, payable at no more than $10 million per reactor per incident per year. This assessment is subject to inflation and state premium taxes.
In addition, the U.S. Congress could impose revenue-raising measures on the nuclear industry to pay claims. The Price-Anderson Act expired on August 1, 2002 and was subsequently extended to the
202
Exelon Corporation and Subsidiary Companies
Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, except per share data unless otherwise noted)
end of 2003 by the U.S. Congress. Only facilities applying for NRC licenses subsequent to the expiration of the Price-Anderson Act are affected. Existing commercial generating facilities, such as those owned by Generation, remain subject to the provisions of the Price-Anderson Act and are unaffected by its expiration. However, new licenses are not covered under the Price-Anderson Act and any new plant initiatives would need to address this exposure.
Generation is a member of an industry mutual insurance company, Nuclear Electric Insurance Limited (NEIL), which provides property damage, decontamination and premature decommissioning insurance for each station for losses resulting from damage to its nuclear plants. In the event of an accident, insurance proceeds must first be used for reactor stabilization and site decontamination. If the decision is made to decommission the facility, a portion of the insurance proceeds will be allocated to a fund, which Generation is required by the NRC to maintain, to provide for decommissioning the facility. Generation is unable to predict the timing of the availability of insurance proceeds to Generation and the amount of such proceeds that would be available. Under the terms of the various insurance agreements, Generation could be assessed up to $168 million for losses incurred at any plant insured by the insurance companies. In the event that one or more acts of terrorism cause accidental property damage within a twelve-month period from the first accidental property damage under one or more policies for all insureds, the maximum recovery for all losses by all insureds will be an aggregate of $3.2 billion plus such additional amounts as the insurer may recover for all such losses from reinsurance, indemnity, and any other source, applicable to such losses. The $3.2 billion maximum recovery limit is not applicable, however, in the event of a “certified act of terrorism” as defined in the Terrorism Risk Insurance Act of 2002, as a result of government indemnity. Generally, a “certified act of terrorism” is defined in the Terrorism Risk Insurance Act to be any act, certified by the U.S. government, to be an act of terrorism committed on behalf of a foreign person or interest.
Additionally, NEIL provides replacement power cost insurance in the event of a major accidental outage at a nuclear station. The premium for this coverage is subject to assessment for adverse loss experience. Generation’s maximum share of any assessment is $48 million per year. Recovery under this insurance for terrorist acts is subject to the $3.2 billion aggregate limit and secondary to the property insurance described above. This limit would also not apply in cases of certified acts of terrorism under the Terrorism Risk Insurance Act as described above.
In addition, Generation participates in the American Nuclear Insurers Master Worker Program, which provides coverage for worker tort claims filed for bodily injury caused by a nuclear energy accident. This program was modified, effective January 1, 1998, to provide coverage to all workers whose “nuclear-related employment” began on or after the commencement date of reactor operations. Generation will not be liable for a retrospective assessment under this new policy; however, in the event losses incurred under the small number of policies in the old program exceed accumulated reserves, a maximum retroactive assessment of up to $50 million could apply.
For its insured losses, Exelon is self-insured to the extent that losses are within the policy deductible or exceed the amount of insurance maintained. Such losses could have a material adverse effect on Exelon’s financial condition, results of operations and liquidity.
Energy Commitments
Generation’s wholesale operations include the physical delivery and marketing of power obtained through its generation capacity, and long-, intermediate- and short-term contracts. Generation
203
Exelon Corporation and Subsidiary Companies
Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, except per share data unless otherwise noted)
maintains a net positive supply of energy and capacity, through ownership of generation assets and power purchase and lease agreements, to protect it from the potential operational failure of one of its owned or contracted power generating units. Generation has also contracted for access to additional generation through bilateral long-term purchase power agreements (PPAs). These agreements are firm commitments related to power generation of specific generation plants and/or are dispatchable in nature. Generation enters into power purchase agreements with the objective of obtaining low-cost energy supply sources to meet its physical delivery obligations to its customers. Generation has also purchased firm transmission rights to ensure that it has reliable transmission capacity to physically move its power supplies to meet customer delivery needs. The primary intent and business objective for the use of its capital assets and contracts is to provide Generation with physical power supply to enable it to deliver energy to meet customer needs. Generation primarily uses financial contracts in its wholesale marketing activities for hedging purposes. Generation also uses financial contracts to manage the risk surrounding trading for profit activities.
Generation has entered into bilateral long-term contractual obligations for sales of energy to load-serving entities, including electric utilities, municipalities, electric cooperatives, and retail load aggregators. Generation also enters into contractual obligations to deliver energy to wholesale market participants who primarily focus on the resale of energy products for delivery. Generation provides delivery of its energy to these customers through access to its transmission assets or rights for firm transmission.
At December 31, 2004, Generation had long-term commitments, relating to the purchase from and sale to unaffiliated utilities and others of energy, capacity and transmission rights as indicated in the following tables:
| Net Capacity Purchases (a) |
Power Only Sales |
Power Only Purchases |
Transmission Rights Purchases (b) | |||||||||
| 2005 |
$ | 578 | $ | 2,551 | $ | 1,446 | $ | 31 | ||||
| 2006 |
581 | 961 | 605 | 3 | ||||||||
| 2007 |
533 | 167 | 254 | — | ||||||||
| 2008 |
462 | 9 | 195 | — | ||||||||
| 2009 |
437 | 9 | 194 | — | ||||||||
| Thereafter |
3,664 | 343 | 548 | — | ||||||||
| Total (c) |
$ | 6,255 | $ | 4,040 | $ | 3,242 | $ | 34 | ||||
| (a) | Net capacity purchases include tolling agreements that are accounted for as operating leases. Amounts presented in the commitments represent Generation’s expected payments under these arrangements at December 31, 2004. Expected payments include certain capacity charges which are contingent on plant availability. |
| (b) | Transmission rights purchases include estimated commitments in 2005 and 2006 for additional transmission rights that will be required to fulfill firm sales contracts. |
| (c) | Included in the totals are $395 million of power only sales commitments related to Sithe, which were not retained by Generation following the sale of Sithe. See Note 3 – Sithe and Note 25 – Subsequent Events for further discussion of these transactions. |
Generation has a PPA with ComEd under which Generation has agreed to supply all of ComEd’s load requirements through 2006. Prices for this energy vary depending upon the time of day and month of delivery. Subsequent to 2006, ComEd expects to procure all of its supply from market sources, which could include Generation. Additionally, Generation has entered into a PPA with PECO under which PECO obtains substantially all of its electric supply from Generation through 2010. Prices for this
204
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Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, except per share data unless otherwise noted)
energy vary depending upon month of delivery. Subsequent to 2010, PECO expects to procure all of its supply from market sources, which could include Generation.
Other Purchase Obligations
In addition to Generation’s energy commitments as described above, Exelon has commitments to purchase fuel supplies for nuclear generation and various other purchase commitments related to the normal day-to-day operations of its business. As of December 31, 2004, these commitments were as follows:
| Expiration within | |||||||||||||||
| Total |
2005 |
2006-2007 |
2008-2009 |
2010 and beyond | |||||||||||
| Fuel purchase agreements (a) |
$ | 3,639 | $ | 639 | $ | 985 | $ | 616 | $ | 1,399 | |||||
| Other purchase commitments (b) |
463 | 241 | 134 | 57 | 31 | ||||||||||
| (a) | Fuel purchase agreements – Commitments to purchase fuel supplies for nuclear and fossil generation. |
| (b) | Other purchase commitments – Commitments for services and materials, minimum spend requirements related to the sale of InfraSource (see Note 2 – Acquisitions and Dispositions) and amounts committed for information technology services. |
Commercial Commitments
Exelon’s commercial commitments as of December 31, 2004, representing commitments potentially triggered by future events, were as follows:
| Expiration within | |||||||||||||||
| Total |
2005 |
2006-2007 |
2008-2009 |
2010 and beyond | |||||||||||
| Letters of credit (non-debt) (a) |
$ | 240 | $ | 239 | $ | 1 | $ | — | $ | — | |||||
| Letters of credit (long-term debt)—interest coverage (b) |
15 | 15 | — | — | — | ||||||||||
| Surety bonds (c) |
458 | 84 | 4 | — | 370 | ||||||||||
| Performance guarantees (d) |
201 | — | — | — | 201 | ||||||||||
| Energy marketing contract guarantees (e) |
261 | 156 | 65 | — | 40 | ||||||||||
| Nuclear insurance guarantees (f) |
1,710 | — | — | 1,710 | |||||||||||
| Lease guarantees (g) |
10 | — | 1 | — | 9 | ||||||||||
| Midwest Generation Capacity Reservation Agreement guarantee (h) |
29 | 4 | 7 | 8 | 10 | ||||||||||
| Exelon New England guarantees (i) |
17 | — | — | — | 17 | ||||||||||
| Total commercial commitments |
$ | 2,941 | $ | 498 | $ | 78 | $ | 8 | $ | 2,357 | |||||
| (a) | Letters of credit (non-debt) – Exelon and certain of its subsidiaries maintain non-debt letters of credit to provide credit support for certain transactions as requested by third parties. As of December 31, 2004, Exelon had $240 million of outstanding letters of credit (non-debt) issued under its $1.5 billion credit agreements. Guarantees of $67 million have been issued to provide support for certain letters of credit as required by third parties. Includes letters of credit of $95 million that will be eliminated upon sale of Sithe to Dynegy. See Note 25—Subsequent Events for further information regarding the sale of Sithe. |
| (b) | Letters of credit (long-term debt) interest coverage – Reflects the interest coverage portion of letters of credit supporting floating-rate pollution control bonds. The principal amount of the floating-rate pollution control bonds of $520 million is reflected in long-term debt in Exelon’s Consolidated Balance Sheet. |
| (c) | Surety bonds – Guarantees issued related to contract and commercial surety bonds, excluding bid bonds. |
205
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Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, except per share data unless otherwise noted)
| (d) | Performance guarantees – Guarantees issued to ensure execution under specific contracts. |
| (e) | Energy marketing contract guarantees – Guarantees issued to ensure performance under energy commodity contracts. Includes guarantees of $30 million that will be eliminated upon the sale of Sithe to Dynegy. See Note 25—Subsequent Events for further information regarding the sale of Sithe. |
| (f) | Nuclear insurance guarantees – Guarantees of nuclear insurance required under the Price-Anderson Act. $1.0 billion of this total exposure is exempt from the $6.0 billion PUHCA guarantee limit by SEC rule. |
| (g) | Lease guarantees – Guarantees issued to ensure payments on building leases. |
| (h) | Midwest Generation Capacity Reservation Agreement guarantee – In connection with ComEd’s agreement with the City of Chicago (Chicago) entered into on February 20, 2003, Midwest Generation assumed from Chicago a Capacity Reservation Agreement that Chicago had entered into with Calumet Energy Team, LLC. ComEd has agreed to reimburse Chicago for any nonperformance by Midwest Generation under the Capacity Reservation Agreement. Under FIN 45, $3 million is included as a liability on Exelon’s Consolidated Balance Sheets at December 31, 2004. |
| (i) | Exelon New England guarantees – Mystic Development LLC (Mystic), a former affiliate of Exelon New England, has a long-term agreement through January 2020 with Distrigas of Massachusetts Corporation (Distrigas) for gas supply, primarily for the Boston Generating units. Under the agreement, gas purchase prices from Distrigas are indexed to the New England gas markets. Exelon New England has guaranteed Mystic’s financial obligations to Distrigas under the long-term supply agreement. Exelon New England’s guarantee to Distrigas remained in effect following the transfer of ownership interest in Boston Generating in May 2004. Under FIN 45, approximately $16 million is included as a liability within the Consolidated Balance Sheet of Exelon as of December 31, 2004 related to this guarantee. The terms of the guarantee do not limit the potential future payments that Exelon New England could be required to make under the guarantee. Other guarantees associated with Exelon New England total less than $1 million. |
Environmental Issues
General. Exelon’s operations have in the past and may in the future require substantial expenditures in order to comply with environmental laws. Additionally, under Federal and state environmental laws, Exelon, through its subsidiaries, is generally liable for the costs of remediating environmental contamination of property now or formerly owned by Exelon and of property contaminated by hazardous substances generated by Exelon. Exelon’s subsidiaries own or lease a number of real estate parcels, including parcels on which their operations or the operations of others may have resulted in contamination by substances that are considered hazardous under environmental laws. Exelon has identified 69 sites where former manufactured gas plant (MGP) activities have or may have resulted in actual site contamination. Of these 69 sites, the Illinois Environmental Protection Agency has approved the clean up of four sites and the Pennsylvania Department of Environmental Protection has approved the cleanup of nine sites, and of the remaining sites, 56 are currently under some degree of active study and/or remediation. In addition, Exelon’s subsidiaries are currently involved in a number of proceedings relating to sites where hazardous substances have been deposited and may be subject to additional proceedings in the future.
As of December 31, 2004 and 2003, Exelon had accrued $124 million and $129 million, respectively, for environmental investigation and remediation costs, including $96 million and $105 million, respectively, for MGP investigation and remediation that currently can be reasonably estimated. Included in the environmental investigation and remediation cost obligations as of December 31, 2004 and 2003 are $96 million and $105 million, respectively, that have been recorded on a discounted basis (reflecting discount rates of 4.3% in 2004 and from 5.0% in 2003). Such estimates before the effects of discounting were $109 million and $138 million at December 31, 2004 and 2003, respectively (reflecting inflation rates of 2.3% in 2004 and 2.5% in 2003). Exelon cannot reasonably estimate whether it will incur other significant liabilities for additional investigation and remediation costs at these or additional sites identified by Exelon, environmental agencies or others, or whether such costs will be recoverable from third parties, including ratepayers. However, PECO is currently recovering through regulated gas rates costs associated with the remediation of the MGP sites.
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Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, except per share data unless otherwise noted)
As of December 31, 2004, Exelon anticipates that payments related to the discounted environmental investigation and remediation costs, disclosed below on an undiscounted basis, will be:
| 2005 |
$ | 16 | |
| 2006 |
21 | ||
| 2007 |
17 | ||
| 2008 |
14 | ||
| 2009 |
7 | ||
| Remaining years |
34 | ||
| Total payments |
$ | 109 | |
In December 2003, PECO updated its accounting estimate related to the reserve for environmental remediation. Based on an update of an independently prepared environmental remediation study on 27 MGP sites, PECO increased the environmental reserve by $18 million, with an offsetting increase to the MGP regulatory asset. See Note 21—Supplemental Financial Information for further discussion of the MGP regulatory asset.
Section 316(b) of the Clean Water Act. In July 2004, the EPA issued the final Phase II rule implementing Section 316(b) of the Clean Water Act. This rule establishes national requirements for reducing the adverse environmental impacts from the entrainment and impingement of aquatic organisms at existing power plants. The rule identifies particular standards of performance with respect to entrainment and impingement and requires each facility to monitor and validate this performance in future years. The requirements will be implemented through state-level National Pollutant Discharge Elimination System (NPDES) permit programs. All of Generation’s power generation facilities with cooling water systems are subject to the regulations. Facilities without closed-cycle recirculating systems are potentially most affected. Those facilities are Clinton, Cromby, Dresden, Eddystone, Fairless Hills, Handley, Mountain Creek, New Boston, Oyster Creek, Peach Bottom, Quad Cities, and Salem. Generation is currently evaluating compliance options at its affected plants. At this time, Generation cannot estimate the effect that compliance with the Phase II rule requirements will have on the operation of its generating facilities and its future results of operations, financial condition and cash flows. There are many factors to be considered and evaluated to determine how Generation will comply with the Phase II rule requirements and the extent to which such compliance may result in financial and operational impacts. The considerations and evaluations include, but are not limited to obtaining clarifying interpretations of the requirements from state regulators, resolving outstanding litigation proceedings concerning the requirements, completing studies to establish biological baselines for each facility, and performing environmental and economic cost benefit evaluation of the potential compliance alternatives in accordance with the requirements.
Cotter Corporation. The EPA has advised Cotter Corporation (Cotter), a former ComEd subsidiary, that it is potentially liable in connection with radiological contamination at a site known as the West Lake Landfill in Missouri. On February 18, 2000, ComEd sold Cotter to an unaffiliated third party. As part of the sale, ComEd agreed to indemnify Cotter for any liability incurred by Cotter as a result of any liability arising in connection with the West Lake Landfill. In connection with Exelon’s 2001 corporate restructuring, this responsibility to indemnify Cotter was transferred to Generation. Cotter is alleged to have disposed of approximately 39,000 tons of soils mixed with 8,700 tons of leached barium sulfate at the site. Cotter, along with three other companies identified by the EPA as potentially responsible parties (PRPs), has submitted a draft feasibility study addressing options for remediation of
207
Exelon Corporation and Subsidiary Companies
Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, except per share data unless otherwise noted)
the site. The PRPs are also engaged in discussions with the State of Missouri and the EPA. The estimated costs of the anticipated remediation strategy for the site range up to $22 million. Once a remedy is selected, it is expected that the PRPs will agree on an allocation of responsibility for the costs. Generation has accrued what it believes to be an adequate amount to cover its anticipated share of the liability.
Leases
Minimum future operating lease payments, including lease payments for vehicles, real estate, computers, rail cars and office equipment, as of December 31, 2004 were:
| 2005 |
$ | 73 | |
| 2006 |
71 | ||
| 2007 |
63 | ||
| 2008 |
59 | ||
| 2009 |
55 | ||
| Remaining years |
588 | ||
| Total minimum future lease payments (a) |
$ | 909 | |
| (a) | Generation’s tolling agreements are accounted for as operating leases and are reflected as net capacity purchases in the energy commitments table above. |
Rental expense under operating leases totaled $64 million, $57 million and $85 million in 2004, 2003, and 2002, respectively.
For information regarding Exelon’s capital lease obligations, see Note 12—Long Term Debt.
Litigation
Retail Rate Law. In 1996, three developers of non-utility generating facilities filed litigation against various Illinois officials claiming that the enforcement against those facilities of an amendment to Illinois law removing the entitlement of those facilities to state-subsidized payments for electricity sold to ComEd after March 15, 1996 violated their rights under Federal and state constitutions. The developers also filed suit against ComEd for a declaratory judgment that their rights under their contracts with ComEd were not affected by the amendment and for breach of contract. On November 25, 2002, the court granted the developers’ motions for summary judgment. The judge also entered a permanent injunction enjoining ComEd from refusing to pay the retail rate on the grounds of the amendment and Illinois from denying ComEd a tax credit on account of such purchases. On March 9, 2004, the Illinois Appellate Court reversed the trial court. The Appellate Court held that the 1996 law does apply to the developers’ facilities and, therefore, they are not entitled to subsidized payments. The Court expressly ruled that the breach of contract claims against ComEd are dismissed with prejudice. Two of the developers sought review of the Appellate Court’s decision by the Illinois Supreme Court. On May 26, 2004, the Supreme Court declined to hear the earlier-filed of the two appeals. On October 6, 2004, the Supreme Court declined to hear the final appeal. The time for further appeals has now passed. Related claims remain pending in the trial court.
Real Estate Tax Appeals. PECO and Generation each have been challenging real estate taxes assessed on nuclear plants. PECO is involved in litigation in which it is contesting taxes assessed in 1997 under the Pennsylvania Public Utility Realty Tax Act of March 4, 1971, as amended (PURTA),
208
Exelon Corporation and Subsidiary Companies
Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, except per share data unless otherwise noted)
and has appealed local real estate assessments for 1998 and 1999 on the Limerick Generating Station (Montgomery County, PA) (Limerick) and Peach Bottom Atomic Power Station (York County, PA) (Peach Bottom) plants. Generation is involved in real estate tax appeals for 2000 through 2004, also regarding the valuation of its Limerick and Peach Bottom plants, Quad Cities Station (Rock Island County, IL), Three Mile Island Nuclear Station (Dauphin County, PA) and Oyster Creek Nuclear Generating Station (Forked River, NJ).
During 2003, upon completion of updated nuclear plant appraisal studies, Exelon recorded reductions of $74 million to reserves recorded for exposures associated with the real estate taxes. Exelon believes its reserve balances for exposures associated with the real estate taxes as of December 31, 2004 reflect the probable expected outcome of the litigation and appeals proceedings in accordance with SFAS No. 5, “Accounting for Contingencies.” The ultimate outcome of such matters, however, could result in unfavorable or favorable adjustments to the consolidated financial statements of Exelon and such adjustments could be material.
General. Exelon is involved in various other litigation matters that are being defended and handled in the ordinary course of business. Exelon maintains accruals for such costs that are probable of being incurred and subject to reasonable estimation. The ultimate outcomes of such matters, as well as the matters discussed above, are uncertain and may have a material adverse effect on Exelon’s financial condition, results of operations or cash flows.
Capital Commitments
SCEP. Generation has a 71% interest in SCEP, which owns a peaking facility in Chicago. SCEP is obligated to make total equity distributions of $49 million through 2022 to the party, which is not affiliated with Exelon, that owns the remaining 29% interest. This amount reflects a return of that party’s investment in SCEP. Generation has the right to purchase, generally at a premium, and the other party has the right to require Generation to purchase, generally at a discount, the 29% interest in SCEP. Additionally, Generation may be required to purchase the remaining 29% interest upon the occurrence of certain events, including Generation’s failure to maintain an investment grade rating. As a result of the adoption of SFAS No. 150 on July 1, 2003, Exelon reclassified the minority interest associated with SCEP to a long-term liability. The total long-term liability related to SCEP was $49 million and $51 million as of December 31, 2004 and 2003, respectively.
Sithe Call Option. On September 29, 2004, Generation exercised its call option and entered into an agreement to acquire Reservoir’s 50% interest in Sithe for $97 million. The closing of the call required state and Federal regulatory approvals, which were received in January 2005, and the transaction was completed on January 31, 2005. See Note 3—Sithe and Note 25—Subsequent Events for additional information.
Credit Contingencies
Dynegy. As previously disclosed, Generation is counterparty to Dynegy in various energy transactions and had financial and credit risk associated with Dynegy through Generation’s investment in Sithe at December 31, 2004. On January 31, 2005, Generation sold its investment in Sithe and, accordingly, is no longer subject to potential financial risk associated with Dynegy’s performance under the financial swap arrangement that Dynegy had with Sithe. See Note 25—Subsequent Events for further discussion of Generation’s sale of Sithe.
209
Exelon Corporation and Subsidiary Companies
Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, except per share data unless otherwise noted)
Income Taxes
Refund Claims. ComEd and PECO have entered into several agreements with a tax consultant related to the filing of refund claims with the IRS. ComEd and PECO previously made refundable prepayments to the tax consultants of $11 million and $5 million, respectively. The fees for these agreements are contingent upon a successful outcome of the claims and are based upon a percentage of the refunds recovered from the IRS, if any. The ultimate net cash outflows to ComEd and PECO related to these agreements will either be positive or neutral depending upon the outcome of the refund claim with the IRS. These potential tax benefits and associated fees could be material to the financial position, results of operations and cash flows of ComEd and PECO. A portion of ComEd’s tax benefits, including any associated interest for periods prior to the PECO / Unicom Merger, would be recorded as a reduction of goodwill pursuant to a reallocation of the PECO / Unicom Merger purchase price. Exelon cannot predict the timing of the final resolution of these refund claims.
In 2004, the IRS granted preliminary approval for one of ComEd’s refund claims. As such, ComEd believes that it is probable that a fee will ultimately be paid to the tax consultant. Therefore, ComEd recorded an expense of $5 million (pre-tax), which resulted in a decrease to the prepayment from $11 million to $6 million. The charge represents an estimate of the fee to the tax consultant which may be adjusted upward or downward depending on the IRS’ final calculation of the tax and interest benefit. As of December 31, 2004, ComEd had not reflected the tax benefit associated with the refund claim pending final approval of the IRS; however, as described above, the net income statement impact for ComEd is anticipated to be neutral or positive.
See Note 25—Subsequent Events for information regarding the final approval of ComEd’s refund claim.
Other. Exelon, through its ComEd subsidiary, has taken certain tax positions, which have been disclosed to the IRS to defer the tax gain on the 1999 sale of its fossil generating assets. See Note 13—Income Taxes for further information.
210
Exelon Corporation and Subsidiary Companies
Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, except per share data unless otherwise noted)
21. Supplemental Financial Information
Supplemental Income Statement Information
The following tables provide additional information about Exelon’s Consolidated Statements of Income for the years ended December 31, 2004, 2003 and 2002.
| For the Years Ended December 31, | |||||||||
| 2004 |
2003 |
2002 | |||||||
| Depreciation, amortization and accretion |
|||||||||
| Property, plant and equipment (a) |
$ | 835 | $ | 736 | $ | 729 | |||
| Regulatory assets |
418 | 386 | 472 | ||||||
| Nuclear fuel (b) |
380 | 395 | 374 | ||||||
| Asset retirement obligation accretion (c) |
210 | 160 | 126 | ||||||
| Amortization of intangible assets (d) |
90 | 4 | — | ||||||
| Total depreciation, amortization and accretion |
$ | 1,933 | $ | 1,681 | $ | 1,701 | |||
| (a) | Includes amortization of capitalized software costs. |
| (b) | Included in fuel expense in the Consolidated Statements of Income. |
| (c) | Prior to the adoption of SFAS No. 143 on January 1, 2003, these amounts were recorded in depreciation expense. Upon adoption of SFAS No. 143, these amounts were recorded in operating and maintenance expense in Exelon’s Consolidated Statements of Income. See Note 14—Nuclear Decommissioning and Spent Fuel Storage for further discussion of the adoption of SFAS No. 143. |
| (d) | $38 million was reflected as a reduction in revenues in the Consolidated Statements of Income, of which $32 million related to the amortization of Sithe assets. See Note 3—Sithe and Note 25—Subsequent Events for a description of Sithe’s intangible assets that are reflected in Exelon’s Consolidated Balance Sheets at December 31, 2004 and a description of the sale of Sithe that was completed on January 31, 2005. |
| For the Years Ended December 31, |
||||||||||||
| 2004 |
2003 |
2002 |
||||||||||
| Income (loss) in equity method investments |
||||||||||||
| Financing trusts of ComEd and PECO (a) |
$ | (44 | ) | $ | — | $ | — | |||||
| AmerGen (b) |
— | 47 | 64 | |||||||||
| Sithe (c) |
(11 | ) | 2 | 23 | ||||||||
| Synfuel |
(84 | ) | — | — | ||||||||
| Affordable housing projects (d) |
(9 | ) | (10 | ) | (10 | ) | ||||||
| Communications joint ventures and other investments |
(5 | ) | (6 | ) | 3 | |||||||
| Total |
$ | (153 | ) | $ | 33 | $ | 80 | |||||
| (a) | Financing trusts were deconsolidated as of December 31, 2003. |
| (b) | Prior to the acquisition of British Energy’s 50% interest in December 2003. |
| (c) | Includes losses incurred prior to Sithe’s consolidation as of March 31, 2004 and losses from Sithe’s investments in TEG and TEP prior to their sale in October 2004. See Note 3—Sithe for additional information. |
| (d) | Prior to the sale of investments on October 15, 2004 and November 12, 2004. |
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Exelon Corporation and Subsidiary Companies
Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, except per share data unless otherwise noted)
| For the Years Ended December 31, | ||||||||||
| 2004 |
2003 |
2002 | ||||||||
| Taxes other than income |
||||||||||
| Utility (a) |
$ | 439 | $ | 440 | $ | 439 | ||||
| Real estate |
151 | 65 | (b) | 149 | ||||||
| Payroll |
100 | 92 | 98 | |||||||
| Other |
29 | (16 | )(c) | 23 | ||||||
| Total |
$ | 719 | $ | 581 | $ | 709 | ||||
| (a) | Municipal and state utility taxes are also recorded in revenues on Exelon’s Consolidated Statements of Income. |
| (b) | Includes the reduction of $74 million of property tax accruals during 2003 as described in Note 20—Commitments and Contingencies. |
| (c) | Includes a credit of $25 million in 2003 due to a favorable settlement of coal use tax issues at ComEd related to periods prior to the PECO / Unicom Merger. |
| For the Years Ended December 31, |
||||||||||||
| 2004 |
2003 |
2002 |
||||||||||
| Other, net |
||||||||||||
| Investment income |
$ | 14 | $ | 21 | $ | 33 | ||||||
| Net loss on early extinguishment of debt |
(130 | ) | — | — | ||||||||
| Gain (loss) on disposition of assets, net (a) |
167 | (3 | ) | 201 | ||||||||
| Decommissioning-related activities |
||||||||||||
| Decommissioning trust fund income (b) |
194 | 79 | 77 | |||||||||
| Decommissioning trust fund income—AmerGen (b) |
43 | — | — | |||||||||
| Other-than-temporary impairment of decommissioning trust funds (c) |
(268 | ) | — | — | ||||||||
| Regulatory offset to non-operating decommissioning—related |
66 | (79 | ) | — | ||||||||
| Interest associated with Federal income taxes |
— | (14 | ) | — | ||||||||
| Impairment of investment in Sithe |
— | (255 | ) | — | ||||||||
| Impairment of investments and other assets |
(19 | ) | (38 | ) | (47 | ) | ||||||
| Net direct financing lease income |
21 | 20 | 18 | |||||||||
| Gain on settlement of note receivable (e) |
18 | — | — | |||||||||
| AFUDC |
4 | 9 | 19 | (f) | ||||||||
| Reserve for potential plant disallowance |
— | 12 | (12 | ) | ||||||||
| Other |
30 | (13 | ) | 15 | ||||||||
| Total |
$ | 140 | $ | (261 | ) | $ | 304 | |||||
| (a) | See Note 2—Acquisitions and Dispositions for further discussion. |
| (b) | Includes investment income and realized gains (losses). |
| (c) | Includes other-than-temporary impairments totaling $255 million, $5 million and $8 million on nuclear decommissioning trust funds for the former ComEd units, the former PECO units and the AmerGen units, respectively. |
| (d) | Includes the elimination of non-operating decommissioning-related activity for those units that are subject to regulatory accounting, including the elimination of decommissioning trust fund income and other-than-temporary impairments for certain nuclear units. See Note 14—Nuclear Decommissioning and Spent Fuel Storage and Note 16—Fair Value of Financial Assets and Liabilities for more information regarding the regulatory accounting applied for certain nuclear units. |
| (e) | Reflects the collection of a note related to the sale of Infrasource. See Note 2—Acquisitions and Dispositions for further information. |
| (f) | In 2002, the debt portion of AFUDC of $8 million was recorded as a non-cash credit to other, net. Subsequent to 2002, the debt portion of AFUDC was recorded as a non-cash credit to interest expense. |
212
Exelon Corporation and Subsidiary Companies
Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, except per share data unless otherwise noted)
Supplemental Cash Flow Information
The following table provides additional information about Exelon’s Consolidated Statements of Cash Flows for the years ended December 31, 2004, 2003 and 2002.
| For the Years Ended December 31, | |||||||||
| 2004 |
2003 |
2002 | |||||||
| Cash paid during the year |
|||||||||
| Interest (net of amount capitalized) |
$ | 888 | $ | 801 | $ | 905 | |||
| Income taxes (net of refunds) |
205 | 728 | 614 | ||||||
| Non-cash investing and financing activities |
|||||||||
| Increase in asset retirement cost |
829 | — | — | ||||||
| Disposition of Boston Generating(a) |
102 | — | — | ||||||
| Note cancelled in conjunction with the acquisition of Sithe International from Sithe |
92 | — | — | ||||||
| Consolidation of Sithe pursuant to FIN 46-R |
85 | — | — | ||||||
| Purchase accounting estimate adjustments |
36 | 59 | — | ||||||
| Non-cash issuance of common stock |
26 | 16 | 3 | ||||||
| Issuance of note payable to acquire synthetic fuel interests |
22 | 238 | — | ||||||
| Resolution of certain tax matters and PECO / Unicom Merger severance adjustment |
14 | — | 14 | ||||||
| Capital lease obligations |
1 | — | 52 | ||||||
| Note received in connection with the sale of Sithe to Reservoir |
— | 92 | — | ||||||
| Note issued to Sithe in the Exelon New England acquisition |
— | 2 | 534 | ||||||
| Contribution of land from minority interest of consolidated subsidiary |
— | — | 12 | ||||||
| (a) | See Note 2 – Acquisitions and Dispositions for additional information regarding the disposition of Boston Generating. |
Supplemental Balance Sheet Information
The following tables provide additional information about assets recorded within Exelon’s Consolidated Balance Sheets as of December 31, 2004 and 2003.
| December 31, 2004 | Energy Delivery |
Generation |
Enterprises |
Exelon | ||||||||
| Investments |
||||||||||||
| Equity method investments: |
||||||||||||
| Direct financing leases |
$ | — | $ | — | $ | — | $ | 486 | ||||
| Financing trusts (a) |
139 | — | — | 139 | ||||||||
| TEG and TEP (b) |
— | 79 | — | 79 | ||||||||
| Energy services and other ventures |
2 | 10 | 2 | 14 | ||||||||
| Total equity method investments |
141 | 89 | 2 | 718 | ||||||||
| Other investments: |
||||||||||||
| Employee benefit trusts and investments |
59 | 14 | 2 | 85 | ||||||||
| Energy services and other ventures |
— | — | 1 | 1 | ||||||||
| Total other investments |
59 | 14 | 3 | 86 | ||||||||
| Total investments |
$ | 200 | $ | 103 | $ | 5 | $ | 804 | ||||
| (a) | Includes investments in financing trusts which were not consolidated within the financial statements of Exelon at December 31, 2004 pursuant to the provisions of FIN 46-R. See Note 1- Significant Accounting Policies for further discussion of the effects of FIN 46-R. |
| (b) | Generation acquired 49.5% interests in two facilities in Mexico on October 13, 2004. See Note 3–Sithe for further information on this transaction. |
213
Exelon Corporation and Subsidiary Companies
Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, except per share data unless otherwise noted)
| December 31, 2003 |
Energy Delivery |
Generation |
Enterprises |
Exelon | ||||||||
| Investments |
||||||||||||
| Equity method investments: |
||||||||||||
| Direct financing leases |
$ | — | $ | — | $ | — | $ | 465 | ||||
| Financing trusts (a) |
196 | — | — | 196 | ||||||||
| Affordable housing projects |
— | — | — | 77 | ||||||||
| Investment in EXRES SHC. Inc. (b) |
— | 47 | — | 47 | ||||||||
| Energy services and other ventures |
2 | 11 | 30 | 44 | ||||||||
| Communications ventures |
1 | — | 28 | 29 | ||||||||
| Total equity method investments |
199 | 58 | 58 | 858 | ||||||||
| Other investments: |
||||||||||||
| Employee benefit trusts and investments |
53 | 7 | — | 72 | ||||||||
| Energy services and other ventures |
— | — | 25 | 25 | ||||||||
| Total other investments |
53 | 7 | 25 | 97 | ||||||||
| Total investments |
$ | 252 | $ | 65 | $ | 83 | $ | 955 | ||||
| (a) | Includes investments in financing trusts which were not consolidated within the financial statements of Exelon at December 31, 2004 pursuant to the provisions of FIN 46-R. See Note 1- Significant Accounting Policies for further discussion of the effects of FIN 46-R. |
| (b) | On November 25, 2003, Generation, Reservoir and Sithe completed a series of transactions that restructured the ownership of Sithe, with Generation continuing to own a 50% interest in Sithe through EXRES SHC, Inc. See Note 3—Sithe and Note 25—Subsequent Events for further information on these transactions and the sale of Sithe in 2005. |
Like-Kind Exchange Transaction. Prior to the PECO / Unicom Merger, UII, LLC (formerly Unicom Investments, Inc.) (UII), a wholly owned subsidiary of Exelon, entered into a like-kind exchange transaction pursuant to which approximately $1.6 billion was invested in passive generating station leases with two separate entities unrelated to Exelon. The generating stations were leased back to such entities as part of the transaction. For financial accounting purposes, the investments are accounted for as direct financing lease investments. UII holds the leasehold interests in the generating stations in several separate bankruptcy remote, special purpose companies it directly or indirectly wholly owns. Under the terms of the lease agreements, UII received a prepayment of $1.2 billion in the fourth quarter of 2000, which reduced the investment in the lease. The remaining payments are payable at the end of the thirty-year lease and there are no minimum scheduled lease payments to be received over the next five years. The components of the net investment in the direct financing leases were as follows:
| December 31, | ||||||
| 2004 |
2003 | |||||
| Total minimum lease payments |
$ | 1,492 | $ | 1,492 | ||
| Less: unearned income |
1,006 | 1,027 | ||||
| Net investment in direct financing leases |
$ | 486 | $ | 465 | ||
214
Exelon Corporation and Subsidiary Companies
Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, except per share data unless otherwise noted)
| December 31, | ||||||
| 2004 |
2003 | |||||
| Other deferred debits and other assets |
||||||
| Intangible assets (a) |
$ | 804 | $ | 429 | ||
| Long-term prepaid state income taxes (b) |
201 | 208 | ||||
| Long-term emission allowances |
82 | 81 | ||||
| Chicago agreement (c) |
59 | 63 | ||||
| Chicago arbitration settlement (d) |
55 | 59 | ||||
| Other |
217 | 151 | ||||
| Total |
$ | 1,418 | $ | 991 | ||
| (a) | See Note 9—Intangible Assets for further information. |
| (b) | Long-term prepaid state income taxes relate to ComEd’s overpayment of state income taxes. The overpayment will be applied towards future state income tax payments. |
| (c) | On February 20, 2003, ComEd entered into separate agreements with Chicago and with Midwest Generation. Under the terms of the agreement with Chicago, ComEd will pay Chicago and other parties a total of $63 million over ten years and be relieved of a requirement, originally transferred to Midwest Generation upon the sale of ComEd’s fossil stations in 1999, to build a 500-MW generation facility. These payments were deferred and are amortized ratably over the life of the franchise agreement with Chicago through 2020. |
| (d) | On March 22, 1999, ComEd reached a settlement agreement with Chicago to end the arbitration proceeding between ComEd and Chicago regarding the January 1, 1992 franchise agreement and a supplement agreement. As part of the settlement agreement, ComEd paid $25 million each year from 1999 to 2002 to help ensure an adequate and reliable electric supply for Chicago. These payments were deferred and are amortized ratably over the life of the franchise agreement with Chicago through 2020. |
The following tables provide information about the regulatory assets and liabilities of ComEd and PECO as of December 31, 2004 and 2003.
| December 31, |
||||||||
| ComEd |
2004 |
2003 |
||||||
| Regulatory assets (liabilities) |
||||||||
| Nuclear decommissioning |
$ | (1,433 | ) | $ | (1,183 | ) | ||
| Removal costs |
(1,011 | ) | (973 | ) | ||||
| Reacquired debt costs and interest-rate swap settlements |
118 | 172 | ||||||
| Recoverable transition costs |
87 | 131 | ||||||
| Deferred income taxes |
4 | (61 | ) | |||||
| Other |
31 | 23 | ||||||
| Total |
$ | (2,204 | ) | $ | (1,891 | ) | ||
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Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, except per share data unless otherwise noted)
| December 31, |
||||||||
| PECO |
2004 |
2003 |
||||||
| Regulatory assets (liabilities) |
||||||||
| Competitive transition charges |
$ | 3,936 | $ | 4,303 | ||||
| Deferred income taxes |
747 | 762 | ||||||
| Non-pension postretirement benefits |
52 | 58 | ||||||
| Reacquired debt costs |
42 | 49 | ||||||
| MGP regulatory asset |
32 | 34 | ||||||
| DOE facility decommissioning |
19 | 26 | ||||||
| Nuclear decommissioning |
(46 | ) | (12 | ) | ||||
| Other |
8 | 6 | ||||||
| Long-term regulatory assets |
4,790 | 5,226 | ||||||
| Deferred energy costs (current asset) |
71 | 81 | ||||||
| Total |
$ | 4,861 | $ | 5,307 | ||||
Nuclear decommissioning. These amounts represent future nuclear decommissioning costs that exceed (regulatory asset) or are less than (regulatory liability) the associated decommissioning trust fund assets. Exelon believes the trust fund assets, including prospective earnings thereon and any future collections from ratepayers, will equal the associated future decommissioning costs at the time of decommissioning. See Note 14—Nuclear Decommissioning and Spent Fuel Storage.
Removal costs. These amounts represent funds received from ratepayers to cover the future removal of property, plant and equipment. See Note 7—Property, Plant and Equipment for further information.
Reacquired debt costs and interest-rate swap settlements. The reacquired debt costs represent premiums paid for the early extinguishment and refinancing of long-term debt, which is amortized over the life of the new debt issued to finance the debt redemption. Interest-rate swap settlements are deferred and amortized over the period that the related debt is outstanding.
Recoverable transition costs. These charges, related to amounts that would have been unrecoverable but for the recovery mechanism, such as the CTC allowed under the Illinois restructuring act, are amortized based on the expected return on equity of ComEd in any given year. ComEd expects to fully recover and amortize these charges by the end of 2006, but may increase or decrease its annual amortization to maintain its earnings within the earnings cap provisions established by Illinois legislation. See Note 5—Regulatory Issues for discussion of recoverable transition cost amortization.
Deferred income taxes. These costs represent the difference between the method by which the regulator allows for the recovery of income taxes and how income taxes would be recorded by unregulated entities. Regulatory assets and liabilities associated with deferred income taxes, recorded in compliance with SFAS No. 71 and SFAS No. 109, include the deferred tax effects associated principally with liberalized depreciation accounted for in accordance with the rate-making policies of the ICC and PUC, as well as the revenue impacts thereon, and assume continued recovery of these costs in future rates. See Note 13—Income Taxes.
216
Exelon Corporation and Subsidiary Companies
Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, except per share data unless otherwise noted)
Competitive transition charges. These charges represent PECO’s stranded costs that the PUC determined would be recoverable through regulated rates. These costs are related to the deregulation of the generation portion of the electric utility business in Pennsylvania. The CTC includes intangible transition property sold to PETT, an unconsolidated subsidiary of PECO, in connection with the securitization of PECO’s stranded cost recovery. These charges are being amortized through December 31, 2010 with a return on the unamortized balance of 10.75%.
Non-pension postretirement benefits. These costs are the result of transitioning to SFAS No. 106 in 1993, which are recoverable in rates through 2012.
MGP regulatory asset. These costs represent estimated MGP-related environmental remediation costs at PECO which are recoverable through regulated gas rates.
DOE facility decommissioning. These costs represent PECO’s share of recoverable decommissioning and decontamination costs of the DOE nuclear fuel enrichment facilities established by the National Energy Policy Act of 1992.
Deferred energy costs (current asset). These costs represent fuel costs recoverable under the purchase gas adjustment clause.
Recovery of regulatory assets. The regulatory assets related to deferred income taxes and non-pension post retirement benefits did not require a cash outlay of investor supplied funds; consequently, these costs are not earning a rate of return. Recovery of the regulatory assets for loss on reacquired debt, recoverable transition costs, MGP remediation costs and deferred energy costs is provided for through regulated revenue sources. Therefore, these costs are earning a rate of return.
The following tables provide additional information about liabilities recorded within Exelon’s Consolidated Balance Sheets as of December 31, 2004 and 2003.
| December 31, | ||||||
| 2004 |
2003 | |||||
| Accrued expenses |
||||||
| Compensation-related accruals (a) |
$ | 346 | $ | 329 | ||
| Taxes accrued |
312 | 336 | ||||
| Interest accrued |
252 | 247 | ||||
| Severance accrued |
69 | 139 | ||||
| Other accrued expenses |
164 | 209 | ||||
| Total |
$ | 1,143 | $ | 1,260 | ||
| (a) | Primarily includes accrued payroll, bonuses and other incentives, vacation and benefits. |
217
Exelon Corporation and Subsidiary Companies
Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, except per share data unless otherwise noted)
The following tables provide additional information about accumulated other comprehensive income recorded within Exelon’s Consolidated Balance Sheets as of December 31, 2004 and 2003.
| December 31, |
||||||||
| 2004 |
2003 |
|||||||
| Accumulated other comprehensive loss |
||||||||
| Minimum pension liability |
$ | (1,372 | ) | $ | (980 | ) | ||
| Net unrealized loss on cash-flow hedges |
(138 | ) | (140 | ) | ||||
| Unrealized gain on marketable securities |
61 | 10 | ||||||
| Foreign currency translation adjustment |
3 | 1 | ||||||
| Total accumulated other comprehensive loss |
$ | (1,446 | ) | $ | (1,109 | ) | ||
22. Segment Information
Exelon operates in three business segments: Energy Delivery (ComEd and PECO), Generation and Enterprises. Exelon evaluates the performance of its business segments based on net income.
Energy Delivery’s business consists of the purchase and regulated sale of electricity and distribution and transmission services by ComEd in northern Illinois, including the City of Chicago, and by PECO in southeastern Pennsylvania, including the City of Philadelphia, and the purchase and regulated sale of natural gas and distribution services by PECO in the Pennsylvania counties surrounding the City of Philadelphia. Generation consists principally of the electric generating facilities and wholesale energy marketing operations of Generation, the competitive retail sales business of Exelon Energy Company, Generation’s interest in Sithe and certain other generation projects. Enterprises consists primarily of the remaining infrastructure and electric contracting businesses of F&M Holdings. See Note 2—Acquisitions and Dispositions for information regarding dispositions within the Generation and Enterprises segments in 2004 and 2003 and Note 3—Sithe and Note 25—Subsequent Events regarding the sale of Sithe in 2005.
Effective January 1, 2004, Enterprises’ competitive retail sales business, Exelon Energy Company, was transferred to Generation. Segment information for 2003 and 2002 included in the table below has been adjusted to reflect Exelon Energy Company as part of the Generation segment.
218
Exelon Corporation and Subsidiary Companies
Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, except per share data unless otherwise noted)
An analysis and reconciliation of Exelon’s business segment information to the respective information in the consolidated financial statements are as follows:
| Energy Delivery |
Generation (a) |
Enterprises (a) |
Corporate |
Intersegment Eliminations |
Consolidated |
||||||||||||||||||
| Total revenues: |
|||||||||||||||||||||||
| 2004 |
$ | 10,290 | $ | 7,938 | $ | 155 | $ | 669 | $ | (4,537 | ) | $ | 14,515 | ||||||||||
| 2003 |
10,202 | 8,760 | 923 | 402 | (4,475 | ) | 15,812 | ||||||||||||||||
| 2002 |
10,457 | 7,320 | 1,336 | 346 | (4,504 | ) | 14,955 | ||||||||||||||||
| Intersegment revenues: |
|||||||||||||||||||||||
| 2004 |
$ | 27 | $ | 3,841 | — | $ | 669 | $ | (4,537 | ) | $ | — | |||||||||||
| 2003 |
76 | 3,920 | 81 | 398 | (4,475 | ) | — | ||||||||||||||||
| 2002 |
76 | 4,000 | 89 | 341 | (4,506 | ) | — | ||||||||||||||||
| Depreciation and amortization: |
|||||||||||||||||||||||
| 2004 |
$ | 928 | $ | 294 | $ | 1 | $ | 82 | $ | — | $ | 1,305 | |||||||||||
| 2003 |
873 | 201 | 24 | 28 | — | 1,126 | |||||||||||||||||
| 2002 |
978 | 292 | 39 | 31 | — | 1,340 | |||||||||||||||||
| Operating expenses: |
|||||||||||||||||||||||
| 2004 |
$ | 7,659 | $ | 6,908 | $ | 217 | $ | 836 | $ | (4,538 | ) | $ | 11,082 | ||||||||||
| 2003 |
7,579 | 8,898 | 1,062 | 472 | (4,476 | ) | 13,535 | ||||||||||||||||
| 2002 |
7,597 | 6,814 | 1,347 | 402 | (4,504 | ) | 11,656 | ||||||||||||||||
| Interest expense: |
|||||||||||||||||||||||
| 2004 |
$ | 672 | $ | 167 | $ | 13 | $ | 61 | $ | (8 | ) | $ | 905 | ||||||||||
| 2003 |
747 | 89 | 9 | 45 | (9 | ) | 881 | ||||||||||||||||
| 2002 |
854 | 79 | 10 | 74 | (51 | ) | 966 | ||||||||||||||||
| Income taxes: |
|||||||||||||||||||||||
| 2004 |
$ | 706 | $ | 372 | $ | 6 | $ | (392 | ) | $ | — | $ | 692 | ||||||||||
| 2003 |
718 | (190 | ) | (70 | ) | (127 | ) | — | 331 | ||||||||||||||
| 2002 |
765 | 233 | 53 | (53 | ) | — | 998 | ||||||||||||||||
| Cumulative effect of changes in accounting principles: |
|||||||||||||||||||||||
| 2004 |
$ | — | $ | 32 | $ | (9 | ) | $ | — | $ | — | $ | 23 | ||||||||||
| 2003 |
5 | 108 | (1 | ) | — | — | 112 | ||||||||||||||||
| 2002 |
— | 2 | (232 | ) | — | — | (230 | ) | |||||||||||||||
| Net income (loss): |
|||||||||||||||||||||||
| 2004 |
$ | 1,128 | $ | 673 | $ | (22 | ) | $ | 85 | $ | — | $ | 1,864 | ||||||||||
| 2003 |
1,175 | (151 | ) | (118 | ) | (1 | ) | — | 905 | ||||||||||||||
| 2002 |
1,268 | 367 | (145 | ) | (50 | ) | — | 1,440 | |||||||||||||||
| Capital expenditures: |
|||||||||||||||||||||||
| 2004 |
$ | 946 | $ | 960 | $ | — | $ | 15 | $ | — | $ | 1,921 | |||||||||||
| 2003 |
962 | 953 | 14 | 25 | — | 1,954 | |||||||||||||||||
| 2002 |
1,041 | 991 | 43 | 75 | — | 2,150 | |||||||||||||||||
| Total assets: |
|||||||||||||||||||||||
| 2004 |
$ | 27,574 | $ | 16,438 | $ | 274 | $ | (1,516 | ) | $ | — | $ | 42,770 | ||||||||||
| 2003 |
28,369 | 14,765 | 697 | (1,895 | ) | — | 41,936 | ||||||||||||||||
| 2002 |
27,036 | 11,059 | 1,124 | (1,350 | ) | — | 37,869 | ||||||||||||||||
| (a) | Effective January 1, 2004, Enterprises’ competitive retail sales business, Exelon Energy Company, was transferred to Generation. Segment information for 2003 and 2002 included in the table above has been adjusted to reflect Exelon Energy Company as part of the Generation segment. |
219
Exelon Corporation and Subsidiary Companies
Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, except per share data unless otherwise noted)
23. Related Party Transactions
Exelon’s financial statements reflect related-party transactions with unconsolidated affiliates as reflected in the tables below. Exelon accounted for its investment in AmerGen as an equity investment prior to the acquisition of the remaining 50% interest in December 2003 and its investment in Sithe as an equity method investment prior to its consolidation as of March 31, 2004.
| For the Years Ended December 31, | ||||||||||
| 2004 |
2003 |
2002 | ||||||||
| Operating revenues from PETT |
$ | 10 | $ | — | $ | — | ||||
| Operating revenues from ComEd Transitional Funding Trust |
3 | — | — | |||||||
| Purchased power from AmerGen (a) |
— | 382 | 273 | |||||||
| Interest income from AmerGen (b) |
— | 1 | 2 | |||||||
| Interest expense to financing affiliates (c) |
||||||||||
| ComEd Transitional Funding Trust |
85 | — | — | |||||||
| ComEd Financing II |
13 | — | — | |||||||
| ComEd Financing III |
13 | — | — | |||||||
| PETT |
235 | — | — | |||||||
| PECO Trust III |
6 | — | — | |||||||
| PECO Trust IV |
6 | 3 | — | |||||||
| Interest expense to Sithe (d) |
— | 9 | 2 | |||||||
| Services provided to AmerGen (e) |
— | 111 | 70 | |||||||
| Services provided to Sithe (f) |
— | — | 1 | |||||||
| Services provided by Sithe (g) |
— | — | 13 | |||||||
| Equity in earnings (losses) from unconsolidated affiliates |
||||||||||
| ComEd Funding LLC |
(20 | ) | — | — | ||||||
| ComEd Financing III |
1 | — | — | |||||||
| PETT |
(25 | ) | — | — | ||||||
220
Exelon Corporation and Subsidiary Companies
Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, except per share data unless otherwise noted)
| December 31, | ||||||
| 2004 |
2003 | |||||
| Receivables from affiliates (current) |
||||||
| ComEd Transitional Funding Trust |
$ | 9 | $ | 9 | ||
| Investment in subsidiaries |
||||||
| ComEd Funding LLC |
36 | 56 | ||||
| ComEd Financing II |
10 | 11 | ||||
| ComEd Financing III |
6 | 6 | ||||
| PETT |
77 | 104 | ||||
| PECO Energy Capital Corp |
4 | 16 | ||||
| PECO Trust IV |
6 | 3 | ||||
| Receivables from affiliates (noncurrent) |
||||||
| ComEd Transitional Funding Trust |
10 | 9 | ||||
| PECO Trust IV |
— | 1 | ||||
| Payables to affiliates (current) |
||||||
| ComEd Financing II |
6 | 6 | ||||
| ComEd Financing III |
4 | 4 | ||||
| PECO Energy Capital Corp |
— | 1 | ||||
| PECO Trust III |
1 | 10 | ||||
| Long-term debt to financing trusts (including due within one year) |
||||||
| ComEd Transitional Funding Trust |
1,341 | 1,676 | ||||
| ComEd Financing II |
155 | 155 | ||||
| ComEd Financing III |
206 | 206 | ||||
| PETT |
3,456 | 3,849 | ||||
| PECO Trust III |
81 | 81 | ||||
| PECO Trust IV |
103 | 103 | ||||
| December 31, | ||||||
| 2004 |
2003 | |||||
| Note receivable from Sithe (h) |
$ | — | $ | 3 | ||
| Note payable to Sithe (d) |
— | 90 | ||||
| Note receivable from EXRES SHC, Inc. (i) |
— | 92 | ||||
| (a) | Prior to Generation’s purchase of British Energy’s 50% interest in AmerGen in December 2003, AmerGen was an unconsolidated affiliate of Exelon and Generation and was considered to be a related party of Exelon and Generation. Generation entered into PPAs dated June 26, 2003, December 18, 2001 and November 22, 1999 with AmerGen. Generation agreed to purchase 100% of the energy generated by Oyster Creek through April 9, 2009. Generation agreed to purchase from AmerGen all the energy from Unit No. 1 at Three Mile Island Nuclear Station from January 1, 2002 through December 31, 2014. Generation agreed to purchase all of the residual energy from Clinton not sold to Illinois Power through December 31, 2002. Currently, the residual output is approximately 31% of the total output of Clinton. See Note 2 – Acquisitions and Dispositions for a description of Generation’s purchase of British Energy’s interest in AmerGen in December 2003. |
| (b) | In February 2002, Generation entered into an agreement to loan AmerGen up to $75 million at an interest rate equal to the 1-month London Interbank Offering Rate plus 2.25%. In July 2002, the limit of the loan agreement was increased to $100 million and the maturity date was extended to July 1, 2003. The principal balance of the loan was repaid in full in 2003. |
| (c) | In conjunction with the adoption of FIN 46, PECO Trust IV was deconsolidated from Exelon’s financial statements as of July 1, 2003. Additionally, in conjunction with the adoption of FIN 46-R, effective December 31, 2003, the financing trusts of ComEd, namely ComEd Financing II, ComEd Financing III, ComEd Funding LLC and ComEd Transitional Funding Trust, and the other financing trusts of PECO, namely PECO Trust III and PETT, were deconsolidated from Exelon’s financial statements. As a result, $5.3 billion and $6.1 billion of debt was recorded as a debt to financing trusts within the Consolidated Balance Sheets as of December 31, 2004 and 2003, respectively. Prior periods were not restated. |
| (d) | Under the terms of the agreement to acquire Exelon New England dated November 1, 2002, Generation issued a $534 million note to be paid in full on June 18, 2003 to Sithe. In June 2003, the principal of the note was increased $2 million, and |
221
Exelon Corporation and Subsidiary Companies
Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, except per share data unless otherwise noted)
| the payment terms of the note were changed. During 2003, Generation paid $446 million on this note. In the first quarter of 2004, Generation paid $27 million prior to consolidation of Sithe in accordance with the provisions of FIN 46-R. The balance of the note, which bore interest at the rate of LIBOR plus 0.875%, was paid upon the completion of a series of transactions that resulted in Generation’s exit from its investment in Sithe on January 31, 2005. See Note 25 – Subsequent Events regarding the sale of Generation’s investment in Sithe. |
| (e) | Under a service agreement dated March 1, 1999, Generation provides AmerGen with certain operation and support services to the nuclear facilities owned by AmerGen. Generation is compensated for these services at cost. |
| (f) | Under a service agreement dated December 18, 2000, Generation provides certain engineering and environmental services for fossil facilities owned by Sithe and for certain developmental projects. Generation is compensated for these services at cost. |
| (g) | Under a service agreement dated December 18, 2000, Sithe provides Generation certain fuel and project development services. Sithe is compensated for these services at cost. Under a service agreement dated November 1, 2002, Sithe provides Generation certain transition services related to the transition of the Exelon New England asset acquisition, which occurred in November 2002. |
| (h) | In December 2003, Sithe received letter of credit proceeds of $3 million, which Generation was billed on behalf of Sithe. |
| (i) | In connection with a series of transactions in November 2003 that restructured the ownership of Sithe (see Note 3 – Sithe for additional information), Exelon received a $92 million note receivable from EXRES SHC, Inc, which holds the common stock of Sithe. Exelon owns 50% of EXRES SHC, Inc. and consolidated its investment pursuant to FIN 46-R effective March 31, 2004. Prior to the consolidation of EXRES SHC, Inc. in connection with FIN 46-R, EXRES SHC, Inc. was an unconsolidated affiliate of Exelon and was considered to be a related party to Exelon. This note was cancelled in connection with the purchase of Sithe International. See Note 3 – Sithe for additional information. |
24. Quarterly Data (Unaudited)
The data shown below include all reclassifications which Exelon considers necessary for a fair presentation of such amounts:
| Operating Revenues |
Operating Income |
Income (Loss) Accounting Principles |
Net Income (Loss) |
|||||||||||||||||||||||
| 2004 |
2003 |
2004 (a) |
2003 (b) |
2004 |
2003 |
2004 |
2003 |
|||||||||||||||||||
| Quarter ended: |
||||||||||||||||||||||||||
| March 31 (c) |
$ | 3,722 | $ | 4,074 | $ | 752 | $ | 788 | $ | 380 | $ | 249 | $ | 412 | $ | 361 | ||||||||||
| June 30 |
3,550 | 3,721 | 811 | 822 | 521 | 372 | 521 | 372 | ||||||||||||||||||
| September 30 |
3,865 | 4,441 | 1,228 | 6 | 577 | (102 | ) | 568 | (102 | ) | ||||||||||||||||
| December 31 |
3,378 | 3,576 | 641 | 661 | 363 | 274 | 363 | 274 | ||||||||||||||||||
| (a) | Operating income has been adjusted to reflect a reclassification from operating and maintenance expense to other, net of $30 million and $28 million, for the three months ended March 31, 2004 and June 30, 2004, respectively, for comparison purposes related to decommissioning accounting presentation. These reclassifications had no impact on net income as reported. |
| (b) | Operating income has been adjusted to reflect a reclassification from operating and maintenance expense to other, net of $31 million, $22 million, $23 million and $3 million for the three months ended March 31, 2003, June 30, 2003, September 30, 2004 and December 31, 2004 respectively, for comparison purposes related to decommissioning accounting presentation. These reclassifications had no impact on net income as reported. |
| (c) | Operating income, income before the cumulative effect of changes in accounting principles and net income for the three months ended March 31, 2004 have been adjusted to reflect a reduction in net periodic postretirement benefit cost of $6 million due to the adoption of FSP FAS 106-2. See Note 1—Significant Accounting Policies for additional information. |
222
Exelon Corporation and Subsidiary Companies
Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, except per share data unless otherwise noted)
| Average Basic Shares Outstanding |
Earnings (Loss) Changes in |
Net Income (Loss) per Basic Share |
||||||||||||||||
| 2004 |
2003 |
2004 |
2003 |
2004 |
2003 |
|||||||||||||
| Quarter ended: |
||||||||||||||||||
| March 31 (a) |
659 | 648 | $ | 0.57 | $ | 0.39 | $ | 0.63 | $ | 0.56 | ||||||||
| June 30 |
661 | 650 | 0.79 | 0.57 | 0.79 | 0.57 | ||||||||||||
| September 30 |
661 | 652 | 0.87 | (0.16 | ) | 0.86 | (0.16 | ) | ||||||||||
| December 31 |
664 | 655 | 0.55 | 0.42 | 0.55 | 0.42 | ||||||||||||
| (a) | Earnings per basic share before the cumulative effect of changes in accounting principles and net income per basic share for the three months ended March 31, 2004 have been increased by $0.01 to reflect a reduction in net periodic postretirement benefit cost due to the adoption of FSP FAS 106-2. See Note 1—Significant Accounting Policies for additional information. |
| Average Diluted Shares Outstanding (in millions) |
Earnings (Loss) per Diluted Share Cumulative Effect of Changes in Accounting Principles |
Net Income (Loss) per Diluted Share |
||||||||||||||||
| 2004 |
2003 |
2004 |
2003 |
2004 |
2003 |
|||||||||||||
| Quarter ended: |
||||||||||||||||||
| March 31 (a) |
665 | 652 | $ | 0.56 | $ | 0.38 | $ | 0.62 | $ | 0.55 | ||||||||
| June 30 |
667 | 655 | 0.78 | 0.57 | 0.78 | 0.57 | ||||||||||||
| September 30 |
669 | 652 | 0.86 | (0.16 | ) | 0.85 | (0.16 | ) | ||||||||||
| December 31 |
672 | 661 | 0.54 | 0.41 | 0.54 | 0.41 | ||||||||||||
| (a) | Earnings per diluted share before the cumulative effect of changes in accounting principles and net income per diluted share for the three months ended March 31, 2004 have been increased by $0.01 to reflect a reduction in net periodic postretirement benefit cost due to the adoption of FSP FAS 106-2. See Note 1—Significant Accounting Policies for additional information. |
The following table presents the New York Stock Exchange—Composite Common Stock Prices and dividends by quarter on a per share basis:
| 2004 |
2003 | |||||||||||||||||||||||
| Fourth Quarter |
Third Quarter |
Second Quarter |
First Quarter |
Fourth Quarter |
Third Quarter |
Second Quarter |
First Quarter | |||||||||||||||||
| High price |
$ | 44.90 | $ | 37.90 | $ | 34.89 | $ | 34.43 | $ | 33.31 | $ | 31.98 | $ | 30.46 | $ | 27.60 | ||||||||
| Low price |
36.73 | 32.69 | 30.92 | 32.18 | 30.48 | 27.09 | 24.83 | 23.04 | ||||||||||||||||
| Close |
44.07 | 36.69 | 33.29 | 34.43 | 33.18 | 31.75 | 29.91 | 25.21 | ||||||||||||||||
| Dividends |
0.400 | 0.305 | 0.275 | 0.275 | 0.250 | 0.250 | 0.230 | 0.230 | ||||||||||||||||
223
Exelon Corporation and Subsidiary Companies
Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, except per share data unless otherwise noted)
25. Subsequent Events
ComEd
In the first quarter 2005, ComEd received final approval of the income tax refund described in Note 20—Commitments and Contingencies; however the calculation of the claim, including interest has not been finalized. As a portion of the refund will be recorded against goodwill under the provisions of EITF Issue No. 93-7, “Uncertainties Related to Income Taxes in a Purchase Business Combination,” the net result is not anticipated to have a material impact on Exelon’s results of operations.
Generation
On January 31, 2005, subsidiaries of Generation completed a series of transactions that resulted in Generation’s exit from its investment in Sithe. Specifically, subsidiaries of Generation closed on the acquisition of Reservoir’s 50% interest in Sithe and the sale of 100% of Sithe to Dynegy. Prior to closing on the sale to Dynegy, subsidiaries of Generation received from Sithe approximately $65 million in cash distributions. As a result of the sale, Exelon will deconsolidate from its balance sheet approximately $820 million of debt and will be released from approximately $125 million of credit support associated with the Independence project. Additionally, Exelon issued certain guarantees to Dynegy that will be taken into account in the final determination of the gain or loss on the sale. See further information regarding Generation’s investment in Sithe at Note 3—Sithe.
224
| ITEM 7. | MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATION |
Executive Overview
During 2004, ComEd has focused on living up to its reliability and safety commitments while pursuing greater productivity, quality and innovation. Highlights for the year included the following:
Financial Results. ComEd experienced an overall decline in net income of 4% in 2004. This decline was primarily due to charges of $130 million recorded in connection with the early retirement of long-term debt, lower operating revenues as a result of lower CTC collections, unfavorable weather and customers purchasing energy from an alternative electric supplier or the PPO and higher purchased power expense. ComEd’s 2004 results were favorably affected by lower operating and maintenance and lower interest expense.
Investment Strategy. ComEd continued to invest in its infrastructure, spending approximately $720 million in 2004 and expects to invest over $740 million in 2005.
Financing Activities. ComEd met its capital resource commitments primarily with internally generated cash, a return of contributions to the intercompany money pool and the satisfaction of receivables. When necessary, ComEd obtains funds from external sources, including the capital markets, the intercompany money pool and through bank borrowings. ComEd repaid $1.2 billion of outstanding debt, including $1.0 billion prior to its maturity and $206 million at maturity, which is expected to result in annual interest savings of approximately $70 million in 2005, and repaid approximately $335 million of its long-term payable to ComEd Transitional Funding Trust in 2004.
Regulatory Developments. PJM Integration. On June 2, 2003, ComEd began receiving electric transmission reservation services from PJM and transferred control of ComEd’s Open Access Same Time Information System to PJM. On April 27, 2004 the FERC issued its order approving ComEd’s application, subject to certain stipulations, including a provision to hold certain utilities in Michigan and Wisconsin harmless from the associated impacts for ComEd to join PJM. ComEd agreed to these stipulations and fully integrated its transmission facilities into PJM on May 1, 2004. In the fourth quarter of 2004, ComEd entered into settlement agreements with all such Michigan and Wisconsin utilities requiring a total payment of approximately $4 million by ComEd. FERC has approved these agreements and payment is expected to be made in the first quarter of 2005.
PECO and ComEd’s membership in PJM supports Exelon’s commitment to competitive wholesale electric markets and will provide Exelon the benefits of more transparent, liquid and competitive markets for the sale and purchase of electric energy and capacity. Upon joining PJM, ComEd began incurring administrative fees, which are expected to approximate $25 million annually. ComEd believes such costs will ultimately be offset by the benefits of full access to a wholesale competitive marketplace and increased revenue requirements, particularly after ComEd’s regulatory transition period ends in 2006; however, changes in market dynamics could affect the ultimate financial impact on ComEd.
Through and Out Rates. In November 2004, the FERC issued two orders authorizing ComEd to recover from various entities revenue representing amounts ComEd will lose as a result of the elimination of through and out (T&O) charges, for energy flowing across ComEd’s transmission system, that were terminated pursuant to the FERC orders effective December 1, 2004. The collection of this revenue will be over a transitional period of December 1, 2004 through March 31, 2006. Several parties have sought rehearing of the FERC orders and there likely will be appeals filed in the matter after the rehearing order is issued. During 2004 prior to the termination of the net T&O charges,
225
ComEd collected T&O charges of approximately $50 million. As a result of this proceeding, ComEd may see reduced net collections of these charges. The ultimate outcome of this proceeding is uncertain and may have a material adverse effect on ComEd’s financial condition, results of operations or cash flows.
Rate Design Proceeding. Certain PJM transmission owners, including ComEd, are subject to a rate design proceeding before the FERC. The issues in this proceeding involve the methodology by PJM to charge customers for each PJM transmission owner’s regulated revenue requirement associated with its electric transmission facilities. On January 31, 2005, certain PJM transmission owners, including ComEd, made two separate filings in which the transmission owners jointly proposed to retain the present modified zonal rate design applicable within PJM and to implement three separate rate options for recovery of the revenue requirement associated with their new and existing facilities. As part of the group of PJM transmission owners, ComEd proposed to retain the present rate design through January 2008, at which time the FERC could reevaluate the continuation of the rate design in PJM. The ultimate outcome of this proceeding is uncertain and may have a material adverse effect on ComEd’s financial condition, results of operations or cash flows.
Open Access Transmission Tariff. On November 10, 2003, the FERC issued an order allowing ComEd to put into effect, subject to refund and rehearing, new transmission rates designed to reflect nearly $500 million of infrastructure investments made since 1998; however, because of the Illinois retail rate freeze and the method for calculating CTCs, the increase is not expected to significantly increase operating revenues until December 31, 2006. During the third quarter 2004, a settlement was reached, which was approved by the FERC in the fourth quarter of 2004, which established new rates that became effective May 1, 2004.
Regulatory Outlook. Restructuring in the U.S. electric industry is at a crossroads at both the Federal and state levels, with continuing debate at the FERC on regional transmission organizations (RTO) and standard market platform issues and in many states on the “post-transition” format. Some states abandoned failed transition plans (like California), some states are adjusting or have adjusted current transition plans (like Ohio) and the State of Illinois (by 2007) is considering options to preserve choice for large customers and rate stability for mass market customers, while ensuring the financial returns needed for continuing investments in reliability. ComEd will continue to be an active participant in these policy debates, while continuing to focus on improving operations and controlling costs.
As ComEd nears the end of the restructuring transition period and related rate freeze in Illinois, ComEd will also continue to work with Federal and state regulators, state and local governments, customer representatives and other interested parties to develop appropriate processes for establishing future rates in restructured electricity markets. ComEd will strive to ensure that future rate structures recognize the substantial improvements ComEd has made, and will continue to make, in its transmission and distribution systems. ComEd will also work to ensure that its rates are adequate to cover its costs of obtaining electric power and energy from its suppliers, which could include Generation, for the costs associated with procuring full-requirements power given ComEd’s Provider of Last Resort (POLR) obligations.
In 2004, the ICC initiated and conducted a workshop process to consider issues related to retail electric service in the post-transition period (i.e., post-2006). Issues addressed included utility wholesale supply procurement methodology, rates, competition and utility service obligations. All interested parties were invited to participate. The end result was a report to the Illinois General Assembly which was generally supportive of continuing under the existing regulatory framework and of utilities procuring supply through a full-requirements, vertical tranche, descending clock auction process with full recovery of the supply costs from retail customers. In 2005, utilities, including ComEd, are expected to begin to seek regulatory approval of structures that implement the methodologies
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supported by the report or such other proposals as they may choose to make. ComEd intends to make various filings during 2005 to begin the process to establish rates for the post-transition period. These filings will include a proposal consistent with the auction process described above. All such methodologies and proposals will be subject to regulatory approval. ComEd cannot predict which particular proposals will be approved.
Outlook for 2005 and Beyond. On December 20, 2004, Exelon entered into a merger agreement with PSEG, a holding company for an electric and gas utility company primarily located and serving customers in New Jersey. The transaction, which has been unanimously approved by the Boards of Directors of both companies, is expected to close in the first quarter of 2006. However, the transaction is contingent upon, among other things, the approval by shareholders of PSEG of the merger and shareholders of Exelon of the shares to be issued in the merger, antitrust clearance and a number of regulatory approvals and reviews. Exelon and ComEd are in the process of evaluating the impacts of the merger.
ComEd’s financial results will be affected by a number of factors, including weather conditions and the continued successful implementation of operational improvement initiatives. If weather is warmer than normal in the summer months or colder than normal in the winter months, operating revenues at ComEd generally will be favorably affected. In addition, ComEd is required annually to assess its goodwill to determine if it is impaired. Based on certain anticipated reductions to cash flows subsequent to the transition period (primarily competitive transition charges), ComEd believes there is a reasonable possibility that goodwill may be impaired in 2005 or future periods, and such impairment may be significant.
While the U.S. economic recovery appears underway, ComEd’s current plans are based on moderate kilowatthour sales growth (1% to 2%). Continued implementation of cost reduction initiatives is needed to offset labor and material cost escalation, especially the double digit increases in health care costs. ComEd’s stable base of over three million customers will provide a solid platform with which to meet these challenges.
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Results of Operations
Year Ended December 31, 2004 Compared to Year Ended December 31, 2003
| 2004 |
2003 |
Favorable (unfavorable) variance |
||||||||||
| OPERATING REVENUES |
$ | 5,803 | $ | 5,814 | $ | (11 | ) | |||||
| OPERATING EXPENSES |
||||||||||||
| Purchased power |
2,588 | 2,501 | (87 | ) | ||||||||
| Operating and maintenance |
897 | 1,093 | 196 | |||||||||
| Depreciation and amortization |
410 | 386 | (24 | ) | ||||||||
| Taxes other than income |
291 | 267 | (24 | ) | ||||||||
| Total operating expense |
4,186 | 4,247 | 61 | |||||||||
| OPERATING INCOME |
1,617 | 1,567 | 50 | |||||||||
| OTHER INCOME AND DEDUCTIONS |
||||||||||||
| Interest expense |
(369 | ) | (423 | ) | 54 | |||||||
| Distributions on mandatorily redeemable preferred securities |
— | (26 | ) | 26 | ||||||||
| Equity in losses of unconsolidated affiliates |
(19 | ) | — | (19 | ) | |||||||
| Net loss on extinguishment of long-term debt |
(130 | ) | — | (130 | ) | |||||||
| Other, net |
34 | 49 | (15 | ) | ||||||||
| Total other income and deductions |
(484 | ) | (400 | ) | (84 | ) | ||||||
| INCOME BEFORE INCOME TAXES AND CUMULATIVE EFFECT OF A CHANGE IN ACCOUNTING PRINCIPLE |
1,133 | 1,167 | (34 | ) | ||||||||
| INCOME TAXES |
457 | 465 | 8 | |||||||||
| INCOME BEFORE CUMULATIVE EFFECT OF A CHANGE IN ACCOUNTING PRINCIPLE |
676 | 702 | (26 | ) | ||||||||
| CUMULATIVE EFFECT OF A CHANGE IN ACCOUNTING PRINCIPLE, (net of income taxes) |
— | 5 | (5 | ) | ||||||||
| NET INCOME |
$ | 676 | $ | 707 | $ | (31 | ) | |||||
Net Income
Net income was affected by losses due to the extinguishment of long-term debt, lower operating revenues primarily due to unfavorable weather and customers purchasing energy from an alternative electric supplier or PPO and higher purchased power expense, partially offset by lower operating and maintenance expense and lower interest expense.
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Operating Revenues
ComEd’s electric sales statistics and revenue detail are as follows:
| Retail Deliveries—(in GWhs) (a) |
2004 |
2003 |
Variance |
% Change |
||||||
| Full service (b) |
||||||||||
| Residential |
26,463 | 26,206 | 257 | 1.0 | % | |||||
| Small commercial & industrial |
20,186 | 21,541 | (1,355 | ) | (6.3 | %) | ||||
| Large commercial & industrial |
6,061 | 5,921 | 140 | 2.4 | % | |||||
| Public authorities & electric railroads |
4,221 | 5,125 | (904 | ) | (17.6 | %) | ||||
| Total full service |
56,931 | 58,793 | (1,862 | ) | (3.2 | %) | ||||
| Delivery only (c) |
||||||||||
| Small commercial & industrial |
7,107 | 6,006 | 1,101 | 18.3 | % | |||||
| Large commercial & industrial |
12,422 | 9,909 | 2,513 | 25.4 | % | |||||
| Public authorities & electric railroads |
1,410 | 1,402 | 8 | 0.6 | % | |||||
| 20,939 | 17,317 | 3,622 | 20.9 | % | ||||||
| PPO |
||||||||||
| Small commercial & industrial |
3,594 | 3,318 | 276 | 8.3 | % | |||||
| Large commercial & industrial |
4,223 | 4,348 | (125 | ) | (2.9 | %) | ||||
| Public authorities & electric railroads |
1,670 | 1,925 | (255 | ) | (13.2 | %) | ||||
| 9,487 | 9,591 | (104 | ) | (1.1 | %) | |||||
| Total delivery only and PPO |
30,426 | 26,908 | 3,518 | 13.1 | % | |||||
| Total retail deliveries |
87,357 | 85,701 | 1,656 | 1.9 | % | |||||
| (a) | One GWh is the equivalent of one million kilowatthours (kWh). |
| (b) | Full service reflects deliveries to customers taking electric service under tariffed rates. |
| (c) | Delivery only revenue reflects revenue from customers electing to receive generation service from an alternative energy supplier, which includes a distribution charge and a CTC. |
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| Electric Revenue |
2004 |
2003 |
Variance |
% Change |
|||||||||
| Full service (a) |
|||||||||||||
| Residential |
$ | 2,295 | $ | 2,272 | $ | 23 | 1.0 | % | |||||
| Small commercial & industrial |
1,604 | 1,667 | (63 | ) | (3.8 | %) | |||||||
| Large commercial & industrial |
290 | 304 | (14 | ) | (4.6 | %) | |||||||
| Public authorities & electric railroads |
261 | 316 | (55 | ) | (17.4 | %) | |||||||
| Total full service |
4,450 | 4,559 | (109 | ) | (2.4 | %) | |||||||
| Delivery only (b) |
|||||||||||||
| Small commercial & industrial |
134 | 139 | (5 | ) | (3.6 | %) | |||||||
| Large commercial & industrial |
170 | 175 | (5 | ) | (2.9 | %) | |||||||
| Public authorities & electric railroads |
28 | 33 | (5 | ) | (15.2 | %) | |||||||
| 332 | 347 | (15 | ) | (4.3 | %) | ||||||||
| PPO (c) |
|||||||||||||
| Small commercial & industrial |
246 | 225 | 21 | 9.3 | % | ||||||||
| Large commercial & industrial |
240 | 240 | — | — | |||||||||
| Public authorities & electric railroads |
92 | 103 | (11 | ) | (10.7 | %) | |||||||
| 578 | 568 | 10 | 1.8 | % | |||||||||
| Total delivery only and PPO |
910 | 915 | (5 | ) | (0.5 | %) | |||||||
| Total electric retail revenues |
5,360 | 5,474 | (114 | ) | (2.1 | %) | |||||||
| Wholesale and miscellaneous revenue (d) |
443 | 340 | 103 | 30.3 | % | ||||||||
| Total electric revenue |
$ | 5,803 | $ | 5,814 | $ | (11 | ) | (0.2 | %) | ||||
| (a) | Full service revenue reflects deliveries to customers taking electric service under tariffed rates, which include the cost of energy and the delivery cost of the transmission and the distribution of the energy. |
| (b) | Delivery only revenues reflect revenue under tariff rates from customers electing to receive electric generation service from an alternative electric supplier, which includes a distribution charge and a CTC. Prior to ComEd’s full integration into PJM on May 1, 2004, ComEd’s transmission charges received from alternative electric suppliers are included in wholesale and miscellaneous revenue. |
| (c) | Revenues from customers choosing the PPO include an energy charge at market rates, transmission and distribution charges, and a CTC. |
| (d) | Wholesale and miscellaneous revenues include transmission revenue (including revenue from PJM), sales to municipalities and other wholesale energy sales. |
The changes in electric retail revenues for 2004 compared to 2003 consisted of the following:
| Variance |
||||
| Weather |
$ | (113 | ) | |
| Customer choice |
(104 | ) | ||
| Rate changes and mix |
(75 | ) | ||
| Volume |
178 | |||
| Electric retail revenue |
(114 | ) | ||
| PJM transmission |
164 | |||
| T&O charges |
(41 | ) | ||
| Other effects |
(20 | ) | ||
| Wholesale and miscellaneous revenue |
103 | |||
| Total decrease in electric revenue |
$ | (11 | ) | |
Weather. The demand for electricity is affected by weather conditions. Very warm weather in summer months and very cold weather in other months are referred to as “favorable weather conditions” because these weather conditions result in increased sales of electricity. Conversely, mild
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weather reduces demand. The weather impact for the year ended December 31, 2004 was unfavorable compared to the same period in 2003 as a result of milder weather in 2004. Cooling degree-days decreased 12% and heating degree-days decreased 6% in the year ended December 31, 2004 compared to the same period in 2003.
Customer Choice. All ComEd customers have the choice to purchase energy from an alternative electric supplier. This choice generally does not impact the volume of deliveries, but affects revenue collected from customers related to energy supplied by ComEd; however, as of December 31, 2004, no alternative electric supplier had approval from the ICC, and no electric utilities had chosen, to enter the ComEd residential market for the supply of electricity.
The decrease in revenues reflects increased non-residential customers in Illinois electing to purchase energy from an alternative electric supplier or the PPO. As of December 31, 2004 and 2003, the number of retail customers that had elected to purchase energy from an alternative electric supplier or the ComEd PPO was approximately 22,100 and 20,300, respectively, representing less than 1% of total customers in each year. Deliveries to such customers increased from 26,908 GWhs for the year ended December 31, 2003 to 30,426 GWhs for the year ended December 31, 2004, or from 31% to 35% of total annual retail deliveries.
For the year ended December 31, 2004, the energy provided by alternative electric suppliers was 20,939 GWhs, or 24% of total retail deliveries, as compared to 17,317 GWhs, or 20% for the year ended December 31, 2003.
Rate Changes and Mix. In addition to a change in revenue from the change in rate mix due to changes in monthly usage patterns in all customer classes during 2004 compared to 2003, revenue changed as a result of rate changes. Starting in the June 2003 billing cycle, the increased wholesale market price of electricity and other adjustments to the energy component, decreased the collection of CTCs as compared to the respective prior year period. ComEd’s CTC revenues decreased by $135 million for the year ended December 31, 2004 as compared to the same period in 2003. This decrease was partially offset by increased wholesale market prices which increased energy revenue received under the ComEd PPO and by increased average rates paid by small and large commercial and industrial customers totaling $53 million. For the years ended December 31, 2004 and December 31, 2003, ComEd collected $169 million and $304 million, respectively, of CTC revenue. As a result of increasing mitigation factors, changes in energy prices and the ability of certain customers to establish fixed, multi-year CTC rates beginning in 2003, ComEd anticipates that this revenue source will range from $90 million to $110 million annually in 2005 and 2006. Under the current restructuring statute, no CTCs will be collected after 2006.
Volume. ComEd’s electric revenues from higher delivery volume, exclusive of effects of weather and customer choice, increased due to an increased number of customers and increased usage per customer, generally across all customer classes.
PJM Transmission. ComEd’s transmission revenues and purchased power expense each increased by $164 million in the year ended December 31, 2004 relative to 2003 due to ComEd’s May 1, 2004 entry into PJM.
T&O charges. Prior to FERC orders issued in November 2004, ComEd collected through and out (T&O) charges for energy flowing across ComEd’s transmission system. Charges collected as the transmission owner were recorded in operating revenues. In addition after ComEd joined PJM on May 1, 2004, PJM allocated T&O collections to ComEd as a load serving entity. The collections received as a load serving entity were recorded as a decrease to purchased power expense. See Note 2 of ComEd’s Notes to Consolidated Financial Statements for more information on T&O charges.
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Purchased Power
The changes in purchased power expense for 2004 compared to 2003 consisted of the following:
| Increase (decrease) |
||||
| PJM transmission (a) |
$ | 164 | ||
| Higher volume |
94 | |||
| PJM administrative fees (b) |
15 | |||
| Customers choosing to purchase energy from an alternative electric supplier |
(87 | ) | ||
| Weather |
(57 | ) | ||
| T&O charges (c) |
(22 | ) | ||
| Pricing related to ComEd’s PPA with Generation |
(7 | ) | ||
| Other |
(13 | ) | ||
| Increase in purchased power expense |
$ | 87 | ||
| (a) | ComEd’s transmission revenues and purchased power expense each increased by $164 million due to ComEd’s May 1, 2004 entry into PJM. See “Operating Revenues” above. |
| (b) | ComEd fully integrated into PJM on May 1, 2004. |
| (c) | Prior to FERC orders issued in November 2004, ComEd collected through and out (T&O) charges for energy flowing across ComEd’s transmission system. Charges collected as the transmission owner were recorded in operating revenues. In addition after ComEd joined PJM on May 1, 2004, PJM allocated T&O collections to ComEd as a load serving entity. The collections received as a load serving entity were recorded as a decrease to purchased power expense. See Note 2 of ComEd’s Notes to Consolidated Financial Statements for more information on T&O charges. |
Operating and Maintenance
The changes in operating and maintenance expense for 2004 compared to 2003 consisted of the following:
| Increase (decrease) |
||||
| Severance and severance-related expenses |
$ | (115 | ) | |
| Charge recorded at ComEd in 2003 (a) |
(41 | ) | ||
| Payroll expense (b) |
(25 | ) | ||
| Contractors |
(18 | ) | ||
| FERC annual fees (c) |
(11 | ) | ||
| Environmental charges |
(10 | ) | ||
| Allowance for uncollectible accounts expense |
(9 | ) | ||
| Incremental storm costs |
(7 | ) | ||
| Corporate allocations (d) |
43 | |||
| Tax consultant fees (e) |
5 | |||
| Employee fringe benefits (f) |
3 | |||
| Other |
(11 | ) | ||
| Decrease in operating and maintenance expense |
$ | (196 | ) | |
| (a) | In 2003, ComEd reached an agreement with various Illinois retail market participants and other interested parties. See Note 2 of ComEd’s Notes to Consolidated Financial Statements, Delivery Service Rates. |
| (b) | ComEd had fewer employees in 2004 compared to 2003. |
| (c) | After joining PJM on May 1, 2004, ComEd is no longer charged annual fees by the FERC. PJM pays the annual FERC fees. This represents the reversal of annual FERC fees. |
| (d) | Higher corporate allocations primarily result from centralization of information technology, supply, human resources, communications, and finance functions into BSC from all of the Exelon operating companies, and changes in the corporate governance allocation calculation. Corporate governance allocations increased overall as a result of higher centralized costs distributed out of BSC, the sale of the Enterprises companies resulting in ComEd comprising a greater base percentage of Exelon, and an SEC-mandated change to the methodology used to allocate Exelon’s corporate governance costs. |
| (e) | ComEd recorded a $5 million charge for contingent fees paid to a tax consultant. See Note 15 of ComEd’s Notes to Consolidated Financial Statements for more information. |
| (f) | Employee fringe benefits include a $6 million reduction in net periodic postretirement benefit cost due to the adoption of FSP FAS 106-2, which was adopted during the second quarter of 2004. |
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Depreciation and Amortization
Depreciation and amortization expense increased for 2004 compared to 2003 as follows:
| 2004 |
2003 |
Variance | |||||||
| Depreciation expense |
$ | 329 | $ | 308 | $ | 21 | |||
| Recoverable transition costs amortization |
44 | 44 | — | ||||||
| Other amortization expense |
37 | 34 | 3 | ||||||
| Total depreciation and amortization |
$ | 410 | $ | 386 | $ | 24 | |||
The increase in depreciation expense is primarily due to capital additions.
Recoverable transition costs amortization remained constant in 2004 as compared to 2003. ComEd expects to fully recover its recoverable transition costs regulatory asset balance of $87 million by 2006. Consistent with the provision of the Illinois legislation, regulatory assets may be recovered at amounts that provide ComEd an earned return on common equity within the Illinois legislation earnings threshold.
Taxes Other Than Income
Taxes other than income increased in 2004 primarily as a result of a $25 million credit in 2003 for use tax payments for periods prior to the PECO / Unicom Merger and a refund of $5 million for Illinois Electricity Distribution taxes in 2003 partially offset by a refund of $8 million for the Illinois Electricity Distribution taxes in 2004.
Interest Expense and Distributions on Mandatorily Redeemable Preferred Securities
The aggregate of interest expense and distributions on mandatorily redeemable preferred securities decreased as a result of scheduled principal payments, debt retirements and prepayments, and refinancings at lower rates. Effective December 31, 2003, upon the adoption of FIN 46-R, ComEd deconsolidated its financing trusts (see Note 2 of ComEd’s Notes to Consolidated Financial Statements). ComEd no longer records distributions on mandatorily redeemable preferred securities, but records interest expense to affiliates related to ComEd’s obligations to the financing trusts. This decrease was offset by $4 million of less allowance for funds used during construction (AFUDC) debt recorded during the year ended December 31, 2004 as a result of lower construction work in process balances.
Equity in Losses of Unconsolidated Affiliates
During the year ended December 31, 2004, ComEd recorded $19 million of equity in net losses of subsidiaries as a result of deconsolidating its financing trusts.
Net Loss on Extinguishment of Long-Term Debt
In 2004, Exelon initiated an accelerated liability management plan at ComEd that resulted in the retirement of approximately $1.2 billion of long-term debt, including $1.0 billion prior to its maturity and $206 million at maturity. During 2004, ComEd recorded charges of $130 million associated with the retirement of debt under the plan. The components of these charges included the following: $86 million of prepayment premiums; $12 million of net unamortized premiums, discounts and debt issuance costs; $24 million of losses on reacquired debt previously deferred as regulatory assets; and $12 million of settled cash-flow interest-rate swaps previously deferred as regulatory assets partially offset by $4 million of unamortized gain on settled fair value interest-rate swaps.
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Other, Net
The change in other, net primarily results from the reversal of a $12 million reserve for potential plant disallowance in 2003 as a result of the Agreement (see “Operating and Maintenance” above), a reduction in AFUDC equity of $5 million during 2004 as a result of lower construction work in process balances and a $5 million decrease in interest income on the long-term receivable from UII, LLC (formerly Unicom Investments, Inc.) as a result of a lower principal balance.
Income Taxes
The effective income tax rate was 40% in 2004 and in 2003. See Note 9 of ComEd’s Notes to the Consolidated Financial Statements for further discussion of the effective income tax rate.
Due to revenue needs of the states in which ComEd operates, various state income tax and fee increases have been proposed or are being contemplated. If these changes are enacted, they could increase ComEd’s state income tax expense. At this time, however, ComEd cannot predict whether legislation or regulation will be introduced, the form of any legislation or regulation, whether any such legislation or regulation will be passed by the state legislatures or regulatory bodies, and, if enacted, whether any such legislation or regulation would be effective retroactively or prospectively. As a result, ComEd cannot currently estimate the effect of these potential changes in tax laws or regulation.
Cumulative Effect of a Change in Accounting Principle
On January 1, 2003, ComEd adopted SFAS No. 143, resulting in income of $5 million, net of tax. See Note 10 of ComEd’s Notes to Consolidated Financial Statements for further discussion of the adoption of SFAS No. 143.
Year Ended December 31, 2003 Compared to Year Ended December 31, 2002
| 2003 |
2002 |
Favorable (unfavorable) variance |
||||||||||
| OPERATING REVENUES |
$ | 5,814 | $ | 6,124 | $ | (310 | ) | |||||
| OPERATING EXPENSES |
||||||||||||
| Purchased power |
2,501 | 2,585 | 84 | |||||||||
| Operating and maintenance |
1,093 | 964 | (129 | ) | ||||||||
| Depreciation and amortization |
386 | 522 | 136 | |||||||||
| Taxes other than income |
267 | 287 | 20 | |||||||||
| Total operating expense |
4,247 | 4,358 | 111 | |||||||||
| OPERATING INCOME |
1,567 | 1,766 | (199 | ) | ||||||||
| OTHER INCOME AND DEDUCTIONS |
||||||||||||
| Interest expense |
(423 | ) | (484 | ) | 61 | |||||||
| Distributions on mandatorily redeemable preferred securities |
(26 | ) | (30 | ) | 4 | |||||||
| Other, net |
49 | 44 | 5 | |||||||||
| Total other income and deductions |
(400 | ) | (470 | ) | 70 | |||||||
| INCOME BEFORE INCOME TAXES AND CUMULATIVE EFFECT OF A CHANGE IN ACCOUNTING PRINCIPLE |
1,167 | 1,296 | (129 | ) | ||||||||
| INCOME TAXES |
465 | 506 | 41 | |||||||||
| INCOME BEFORE CUMULATIVE EFFECT OF A CHANGE IN ACCOUNTING PRINCIPLE |
702 | 790 | (88 | ) | ||||||||
| CUMULATIVE EFFECT OF A CHANGE IN ACCOUNTING PRINCIPLE, (net of income taxes) |
5 | — | 5 | |||||||||
| NET INCOME |
$ | 707 | $ | 790 | $ | (83 | ) | |||||
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Net Income
Net income was affected by lower operating revenues primarily due to unfavorable weather and customers purchasing energy from an alternative electric supplier or PPO and higher operating and maintenance expense, partially offset by lower depreciation and amortization expense, lower purchased power expense and lower interest expense.
Operating Revenues
ComEd’s electric sales statistics are as follows:
| Retail Deliveries—(in GWhs) (a) |
2003 |
2002 |
Variance |
% Change |
||||||
| Full service (b) |
||||||||||
| Residential |
26,206 | 27,474 | (1,268 | ) | (4.6 | %) | ||||
| Small commercial & industrial |
21,541 | 22,365 | (824 | ) | (3.7 | %) | ||||
| Large commercial & industrial |
5,921 | 7,885 | (1,964 | ) | (24.9 | %) | ||||
| Public authorities & electric railroads |
5,125 | 6,480 | (1,355 | ) | (20.9 | %) | ||||
| Total full service |
58,793 | 64,204 | (5,411 | ) | (8.4 | %) | ||||
| Delivery only |
||||||||||
| Small commercial & industrial |
6,006 | 5,219 | 787 | 15.1 | % | |||||
| Large commercial & industrial |
9,909 | 7,095 | 2,814 | 39.7 | % | |||||
| Public authorities & electric railroads |
1,402 | 912 | 490 | 53.7 | % | |||||
| 17,317 | 13,226 | 4,091 | 30.9 | % | ||||||
| PPO |
||||||||||
| Small commercial & industrial |
3,318 | 3,152 | 166 | 5.3 | % | |||||
| Large commercial & industrial |
4,348 | 5,131 | (783 | ) | (15.3 | %) | ||||
| Public authorities & electric railroads |
1,925 | 1,347 | 578 | 42.9 | % | |||||
| 9,591 | 9,630 | (39 | ) | (0.4 | %) | |||||
| Total delivery only and PPO |
26,908 | 22,856 | 4,052 | 17.7 | % | |||||
| Total retail deliveries |
85,701 | 87,060 | (1,359 | ) | (1.6 | %) | ||||
| (a) | One GWh is the equivalent of one million kWhs. |
| (b) | Full service reflects deliveries to customers taking electric service under tariffed rates. |
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| Electric Revenue |
2003 |
2002 |
Variance |
% Change |
|||||||||
| Full service (a) |
|||||||||||||
| Residential |
$ | 2,272 | $ | 2,381 | $ | (109 | ) | (4.6 | %) | ||||
| Small commercial & industrial |
1,667 | 1,736 | (69 | ) | (4.0 | %) | |||||||
| Large commercial & industrial |
304 | 410 | (106 | ) | (25.9 | %) | |||||||
| Public authorities & electric railroads |
316 | 377 | (61 | ) | (16.2 | %) | |||||||
| Total full service |
4,559 | 4,904 | (345 | ) | (7.0 | %) | |||||||
| Delivery only (b) |
|||||||||||||
| Small commercial & industrial |
139 | 138 | 1 | 0.7 | % | ||||||||
| Large commercial & industrial |
175 | 154 | 21 | 13.6 | % | ||||||||
| Public authorities & electric railroads |
33 | 28 | 5 | 17.9 | % | ||||||||
| 347 | 320 | 27 | 8.4 | % | |||||||||
| PPO (c) |
|||||||||||||
| Small commercial & industrial |
225 | 204 | 21 | 10.3 | % | ||||||||
| Large commercial & industrial |
240 | 278 | (38 | ) | (13.7 | %) | |||||||
| Public authorities & electric railroads |
103 | 71 | 32 | 45.1 | % | ||||||||
| 568 | 553 | 15 | 2.7 | % | |||||||||
| Total delivery only and PPO |
915 | 873 | 42 | 4.8 | % | ||||||||
| Total electric retail revenues |
5,474 | 5,777 | (303 | ) | (5.2 | %) | |||||||
| Wholesale and miscellaneous revenue (d) |
340 | 347 | (7 | ) | (2.0 | %) | |||||||
| Total electric revenue |
$ | 5,814 | $ | 6,124 | $ | (310 | ) | (5.1 | %) | ||||
| (a) | Full service reflects deliveries to customers taking electric service under tariffed rates, which include the cost of energy and the delivery cost of the transmission and the distribution of the energy. |
| (b) | Delivery only revenues from customers choosing an alternative electric supplier include a distribution charge and a CTC. Transmission charges received from an alternative electric supplier are included in wholesale and miscellaneous revenue. |
| (c) | Revenues from customers choosing the PPO include an energy charge at market rates, transmission and distribution charges, and a CTC. |
| (d) | Wholesale and miscellaneous revenues include transmission revenue, sales to municipalities and other wholesale energy sales. |
The changes in electric retail revenues for 2003 compared to 2002 consisted of the following:
| Variance |
||||
| Weather |
$ | (232 | ) | |
| Customer choice |
(155 | ) | ||
| Rate changes |
(33 | ) | ||
| Volume |
105 | |||
| Other effects |
12 | |||
| Retail revenue |
$ | (303 | ) | |
Weather. The demand for electricity is affected by weather conditions. The weather impact for 2003 was unfavorable compared to 2002 as a result of cooler summer weather in 2003. Cooling degree-days decreased 36% in 2003 as compared to 2002 and were partially offset by a 5% increase in heating degree-days in 2003 as compared to the same period in 2002.
Customer Choice. All ComEd customers have the choice to purchase energy from other suppliers. This choice generally does not impact the volume of deliveries, but affects revenue collected from customers related to energy supplied by ComEd; however, as of December 31, 2003, no alternative
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electric supplier had approval from the ICC, and no electric utilities had chosen, to enter the ComEd residential market for the supply of electricity. The decrease in revenues reflects increased non-residential customers in Illinois electing to purchase energy from an alternative electric supplier or the PPO.
In 2003, the energy provided by alternative electric generation suppliers was 17,317 GWhs, or 20% of total retail deliveries, as compared to 13,226 GWhs, or 15%, in 2002.
As of December 31, 2003 and 2002, the number of retail customers that had elected to purchase energy from an alternative electric supplier or the ComEd PPO was approximately 20,300 and 22,700, respectively, representing less than 1% of total customers in each year. Deliveries to such customers increased from 22,856 GWhs in 2002 to 26,908 GWhs in 2003, or from 26% to 31% of total annual retail deliveries.
Rate Changes. The decrease in revenues attributable to rate changes reflects lower wholesale market prices in the first six months of 2003, which were partially offset by higher wholesale market prices in the last six months of 2003, decreasing revenue received under ComEd’s PPO by $31 million. Starting in the June 2003 billing cycle, the increased wholesale market price of electricity, net of increased mitigation factors, as a result of the Agreement described in Note 2 of ComEd’s Notes to Consolidated Financial Statements, decreased the collection of CTCs as compared to the respective period in 2002; however, for the two-year period, CTC revenues were consistent.
Volume. Revenues from higher delivery volume, exclusive of the effects of weather and customer choice, increased due to an increased number of customers and increased usage per customer, primarily large and small commercial and industrial.
Wholesale and miscellaneous revenue for 2003 as compared to 2002 decreased $7 million primarily due to a 2002 reimbursement from Generation of $12 million.
Purchased Power
Purchased power expense decreased in 2003 primarily due to a $135 million decrease as a result of customers choosing to purchase energy from an alternative electric supplier, a $115 million decrease due to unfavorable weather and a $20 million decrease due to additional energy billed in 2002 under the PPA with Generation, partially offset by an increase of $74 million due to pricing changes related to ComEd’s PPA with Generation, an increase of $62 million under the PPA related to decommissioning collections associated with the adoption of SFAS No. 143 that were not included in purchased power in 2002 and an increase of $59 million due to higher volume. The $62 million increase in purchased power expense related to SFAS No. 143 had no impact on net income as it was offset by lower regulatory asset amortization expense (see Depreciation and Amortization below).
Operating and Maintenance
Operating and maintenance expense increased in 2003 reflecting $137 million due to The Exelon Way severance and related postretirement health and welfare benefits accruals and pension and postretirement curtailment costs, a net charge of $41 million in 2003 as the result of the Agreement as more fully described in Note 2 of ComEd’s Notes to Consolidated Financial Statements, $14 million of additional storm-related costs and $7 million increase in employee fringe benefits partially offset by $78 million decrease in payroll expenses due to fewer employees and $6 million lower net MGP investigation and remediation reserve charges.
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Depreciation and Amortization
Depreciation and amortization expense decreased for 2003 compared to 2002 as follows:
| 2003 |
2002 |
Variance |
||||||||
| Depreciation expense |
$ | 308 | $ | 334 | $ | (26 | ) | |||
| Recoverable transition costs amortization |
44 | 102 | (58 | ) | ||||||
| Other amortization expense |
34 | 86 | (52 | ) | ||||||
| Total depreciation and amortization |
$ | 386 | $ | 522 | $ | (136 | ) | |||
The decrease in depreciation expense is primarily due to lower depreciation rates effective July 1, 2002, partially offset by higher property, plant and equipment balances. The lower rates followed completion of a depreciation study and reflect ComEd’s significant construction program in recent years, changes in and development of new technologies, and changes in estimated plant service lives since the last depreciation study. The reduction in depreciation expense was $48 million ($29 million, net of income taxes) in 2003 compared to 2002.
Recoverable transition costs amortization decreased in the year ended December 31, 2003 compared to the same period in 2002. The decrease is a result of additional amortization in 2002. ComEd expects to fully recover its recoverable transition costs regulatory asset balance of $131 million by 2006. Consistent with the provision of the Illinois legislation, regulatory assets may be recovered at amounts that provide ComEd an earned return on common equity within the Illinois legislation earnings threshold.
The decrease in other amortization primarily relates to the reclassification of a regulatory asset for nuclear decommissioning as a result of the adoption of SFAS No. 143 in 2003 (see Note 10 of ComEd’s Notes to Consolidated Financial Statements). This decrease had no impact on net income as it was offset by increased purchased power from Generation (see Purchased Power above).
Taxes Other Than Income
Taxes other than income decreased in 2003 primarily as a result of a $25 million credit in 2003 for use tax payments for periods prior to the PECO / Unicom Merger and a $5 million refund in 2003 of Illinois Electricity Distribution taxes, partially offset by $8 million in Illinois Public Utility Fund taxes in 2003 that were not charged in 2002 and a $5 million real estate tax refund in 2002.
Interest Charges
Interest charges consist of interest expense and distributions on mandatorily redeemable preferred securities. Interest charges decreased in 2003 as a result of refinancing existing debt at lower interest rates for 2003 as compared to 2002 and the pay down of $340 million in ComEd Transitional Trust Notes.
Other, Net
Other, net increased in 2003 as compared to 2002. In 2002, ComEd recorded a $12 million reserve accrual for a potential plant disallowance from an audit performed in conjunction with ComEd’s delivery services rate case. This $12 million was reversed in March 2003 as a result of the Agreement—as more fully described in Note 2 to ComEd’s Notes to Consolidated Financial Statements. These items were partially offset by a $9 million reduction in intercompany interest income from UII, LLC (formerly Unicom Investments Inc.), reflecting a lower principal balance, and a $10 million decrease in various other income and deduction items.
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Income Taxes
The effective income tax rate was 39.8% in 2003 as compared to 39.0% in 2002.
Due to revenue needs of the states in which ComEd operates, various state income tax and fee increases have been proposed or are being contemplated. If these changes are enacted, they could increase ComEd’s state income tax expense. At this time, however, ComEd cannot predict whether legislation or regulation will be introduced, the form of any legislation or regulation, whether any such legislation or regulation will be passed by the state legislatures or regulatory bodies, and, if enacted, whether any such legislation or regulation would be effective retroactively or prospectively. As a result, ComEd cannot currently estimate the effect of these potential changes in tax laws or regulation.
Cumulative Effect of a Change in Accounting Principle
On January 1, 2003, ComEd adopted SFAS No. 143, resulting in income of $5 million, net of tax. See Note 10 of ComEd’s Notes to Consolidated Financial Statements for further discussion of the adoption of SFAS No. 143.
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Liquidity and Capital Resources
ComEd’s business is capital intensive and requires considerable capital resources. ComEd’s capital resources are primarily provided by internally generated cash flows from operations and, to the extent necessary, external financing, including the issuance of commercial paper, participation in the intercompany money pool or capital contributions from Exelon. ComEd’s access to external financing at reasonable terms is dependent on its credit ratings and general business conditions, as well as that of the utility industry in general. If these conditions deteriorate to the extent that ComEd no longer has access to external financing sources at reasonable terms, ComEd has access to a revolving credit facility that it currently utilizes to support its commercial paper program. See the Credit Issues section of Liquidity and Capital Resources for further discussion. Capital resources, including cash, are used primarily to fund ComEd’s capital requirements, including construction expenditures, repayments of maturing debt, the payment of dividends and contributions to Exelon’s pension plans. ComEd’s construction expenditures utilize a significant amount of cash on projects that have a long-term return on investment. Additionally, ComEd operates in a rate-regulated environment in which recovery of current cash expenditures takes place over an extended period of time. As a result of these factors, ComEd has historically operated with a working capital deficit. However, ComEd expects operating cash flows to be sufficient to meet operating and capital expenditure requirements.
Cash Flows from Operating Activities
ComEd’s cash flow from operating activities primarily results from sales of electricity to a stable and diverse base of retail customers at fixed prices. ComEd’s future cash flows will depend upon the ability to achieve operating cost reductions, and the impact of the economy, weather and customer choice on its revenues. Cash flows from operations have been and are expected to continue to provide a reliable, steady source of cash flow, sufficient to meet operating and capital expenditures requirements. Operating cash flows after 2006 could be negatively affected by changes in ComEd’s rate regulatory environment, although any effects are not expected to hinder ComEd’s ability to fund its business requirements. See Business Outlook and Challenges in Managing our Business.
Cash flows provided by operations for the years 2004 and 2003 were $1,330 million and $948 million, respectively. Changes in ComEd’s cash flows from operations are generally consistent with changes in its results of operations, as further adjusted by changes in working capital in the normal course of business.
In addition to the items mentioned in Results of Operations, ComEd’s operating cash flows in 2004 were affected by the following items:
| • | Payments to Generation in 2003 for amounts owed under the PPA. At December 31, 2004, 2003 and 2002, ComEd had accrued payments due to Generation under the PPA of $189 million, $171 million and $339 million, respectively. |
| • | ComEd participates in Exelon’s defined benefit pension plans. Discretionary contributions by ComEd to the plans were $244 million for 2004 compared to $178 million in 2003. See Note 11 of ComEd’s Notes to Consolidated Financial Statements for further information regarding pension and postretirement benefits. |
| • | During 2004 and 2003, ComEd made Federal and state income tax payments of $356 million and $579 million, respectively. |
| • | During 2004, ComEd paid $86 million for prepayment premiums on the early retirement of debt. See “Cash Flows from Financing Activities” for further information regarding debt retirements pursuant to the accelerated liability management plan. |
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ComEd has taken certain tax positions, which have been disclosed to the Internal Revenue Service (IRS), to defer the tax gain on the 1999 sale of its fossil generating assets. See Note 9 of ComEd’s Notes to Consolidated Financial Statements for additional information regarding these tax positions.
Cash Flows from Investing Activities
Cash flows provided by investing activities were $486 million in 2004 compared to $893 million used in investing activities in 2003. The increase in cash flows was primarily attributable to the net contributions of $502 million to the Exelon intercompany money pool and by the receipt of $1,071 million from UII, LLC (formerly Unicom Investments Inc.) in 2004 related to an intercompany note payable partially offset by the 2003 receipt of $213 million from UII, LLC.
ComEd estimates that it will spend approximately $742 million in total capital expenditures for 2005. Approximately one half of the budgeted 2005 expenditures are for continuing efforts to improve the reliability of its transmission and distribution systems. The remaining amount is for capital additions to support new business and customer growth. ComEd anticipates that it will obtain financing, when necessary, through borrowings, the issuance of debt or preferred securities, or capital contributions from Exelon. ComEd’s proposed capital expenditures and other investments are subject to periodic review and revision to reflect changes in economic conditions and other factors.
Cash Flows from Financing Activities
Cash flows used in financing activities in 2004 were $1,820 million as compared to $37 million in 2003. The increase in cash flows used in financing activities is primarily attributable to the net increase in long-term debt retirements during 2004 of $1,638 million and a decrease of $276 million in contributions received from Exelon. ComEd retired $1.2 billion of long-term debt, including $1.0 billion prior to its maturity and $206 million at maturity, as part of ComEd’s accelerated liability management plan in 2004. Additionally, ComEd paid a $457 million dividend to Exelon during 2004 compared to a $401 million dividend in 2003.
From time to time and as market conditions warrant, ComEd may engage in long-term debt retirements via tender offers, open market repurchases or other viable options to strengthen its balance sheet.
Credit Issues
Credit Facility. A description of Exelon’s credit agreements, and ComEd’s participation therein, is set forth above under “Credit Issues—Exelon Credit Facility” in “Exelon Corporation—Liquidity and Capital Resources.”
Capital Structure. At December 31, 2004, ComEd’s capital structure consisted of 27% long-term debt, 15% long-term debt to financing trusts, and 58% common equity. Long-term debt to financing trusts includes obligations to ComEd Financing II, ComEd Financing III and the ComEd Transitional Funding Trust, which are no longer consolidated within the financial statements due to the adoption of FIN 46-R as of December 31, 2003.
Intercompany Money Pool. A description of the intercompany money pool, and ComEd’s participation therein, is set forth above under “Credit Issues—Intercompany Money Pool” in “Exelon Corporation—Liquidity and Capital Resources.” During 2004, ComEd earned $3 million in
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interest on its contributions to and paid less than $1 million on borrowings from the intercompany money pool.
Security Ratings. A description of ComEd’s security ratings is set forth above under “Credit Issues—Security Ratings” in “Exelon Corporation—Liquidity and Capital Resources.”
Shelf Registration. A description of ComEd’s shelf registration is set forth above under “Credit Issues—Shelf Registration” in “Exelon Corporation—Liquidity and Capital Resources.”
Fund Transfer Restrictions. Under applicable Federal law, ComEd can only pay dividends from retained or current earnings. Under Illinois law, ComEd may not pay any dividend on its stock unless, among other things, “[its] earnings and earned surplus are sufficient to declare and pay same after provision is made for reasonable and proper reserves,” or unless it has specific authorization from the ICC. ComEd has also agreed in connection with financings arranged through ComEd Financing II and ComEd Financing III (the Financing Trusts) that it will not declare dividends on any shares of its capital stock in the event that: (1) it exercises its right to extend the interest payment periods on the subordinated debt securities which were issued to the Financing Trusts; (2) it defaults on its guarantee of the payment of distributions on the preferred trust securities of the Financing Trusts; or (3) an event of default occurs under the Indenture under which the subordinated debt securities are issued. At December 31, 2004, ComEd had retained earnings of $1,102 million (all of which had been appropriated for future dividend payments). ComEd is precluded from lending or extending credit or indemnity to Exelon.
Contractual Obligations and Off-Balance Sheet Obligations
The following table summarizes ComEd’s future estimated cash payments under existing contractual obligations, including payments due by period.
| Total |
Payment due within |
Due 2010 and beyond | |||||||||||||
| 2005 |
2006-2007 |
2008-2009 |
|||||||||||||
| Long-term debt |
$ | 3,165 | $ | 272 | $ | 475 | $ | 434 | $ | 1,984 | |||||
| Long-term debt to financing trusts |
1,702 | 321 | 680 | 340 | 361 | ||||||||||
| Interest payments on long-term debt (a) |
1,412 | 169 | 282 | 217 | 744 | ||||||||||
| Interest payments on long-term debt to financing trusts (a) |
829 | 96 | 134 | 64 | 535 | ||||||||||
| Operating leases |
165 | 20 | 37 | 32 | 76 | ||||||||||
| Other purchase commitments (b) |
20 | 17 | 3 | — | — | ||||||||||
| Chicago agreement (c) |
48 | 6 | 12 | 12 | 18 | ||||||||||
| Regulatory commitments |
20 | 10 | 10 | — | — | ||||||||||
| Total contractual obligations |
$ | 7,361 | $ | 911 | $ | 1,633 | $ | 1,099 | $ | 3,718 | |||||
| (a) | Interest payments are estimated based on final maturity dates of debt securities outstanding at December 31, 2004 and do not reflect anticipated future refinancing, early redemptions or debt issuances. |
| (b) | Commitments for services and materials. |
| (c) | On February 20, 2003, ComEd entered into separate agreements with Chicago and with Midwest Generation (Midwest Agreement). Under the terms of the agreement with Chicago, ComEd will pay Chicago $60 million over ten years to be relieved of a requirement, originally transferred to Midwest Generation upon the sale of ComEd’s fossil stations in 1999, to build a 500-MW generation facility. |
See ITEM 8. Financial Statements and Supplementary Data—ComEd’s Notes to Consolidated Financial Statements for additional information about:
| • | regulatory commitments, see Note 2 |
| • | long-term debt, see Note 8 |
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| • | operating leases, see Note 15 |
| • | Midwest Agreement, see Note 15 |
See Note 15 of ComEd’s Notes to Consolidated Financial Statements for discussion of ComEd’s commercial commitments as of December 31, 2004.
IRS Refund Claims. ComEd entered into several agreements with a tax consultant related to the filing of refund claims with the IRS and previously made refundable prepayments to the tax consultant of $11 million. The fees for these agreements are contingent upon a successful outcome of the claims and are based upon a percentage of the refunds recovered from the IRS, if any. The ultimate net cash outflow from ComEd related to all the agreements will either be positive or neutral depending upon the outcome of the refund claim with the IRS. These potential tax benefits and associated fees could be material to ComEd’s financial position, results of operations and cash flows. ComEd’s tax benefits for periods prior to the PECO / Unicom Merger would be recorded as a reduction of goodwill pursuant to a reallocation of the PECO / Unicom Merger purchase price. See below for a discussion of the final approval of the income tax refund.
During 2004, the IRS granted preliminary approval for one of ComEd’s refund claims. As such, ComEd believes it is probable that a fee will ultimately be paid to the tax consultant. Therefore, ComEd recorded an expense of $5 million (pre-tax), which resulted in a decrease to the prepayment from $11 million to $6 million. The charge represents an estimate of the fee to the tax consultant which may be adjusted upward or downward depending on the IRS’ final calculation of the tax and interest benefit. As of December 31, 2004, ComEd had not reflected the tax benefit associated with the refund claim pending final approval of the IRS; however, as described above, the net income statement impact for ComEd is anticipated to be neutral or positive.
In the first quarter of 2005, ComEd received final approval for the income tax refund described above; however the calculation of the claim, including interest has not been finalized. As a portion of the refund will be recorded against goodwill under the provisions of EITF Issue No. 93-7, “Uncertainties Related to Income Taxes in a Purchase Business Combination,” the net result is not anticipated to have a material impact on ComEd’s results of operations.
Variable Interest Entities. Effective December 31, 2003, ComEd Financing II, ComEd Financing III, ComEd Funding LLC and ComEd Transitional Funding Trust were deconsolidated from the financial statements of ComEd in conjunction with the adoption of FIN 46-R. Approximately $1.7 billion of debt issued by ComEd to these financing trusts was recorded as debt to financing trusts within the Consolidated Balance Sheet as of December 31, 2004.
Critical Accounting Policies and Estimates
See Exelon, ComEd, PECO and Generation—Critical Accounting Policies and Estimates above for a discussion of ComEd’s critical accounting policies and estimates.
Business Outlook and the Challenges in Managing the Business
ComEd conducts business in the electric transmission and distribution industry in the United States. That industry is in the midst of a fundamental and, at this point, uncertain transition from a fully regulated industry offering bundled service to an industry with unbundled services, some of which are regulated and others of which are priced in competitive markets. ComEd’s energy delivery business remains highly regulated and capital intensive.
A description of the business outlook and challenges in managing ComEd’s business is set forth above under “Business Outlook and the Challenges in Managing the Business—Energy Delivery and
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General Business” in “Exelon Corporation—Management’s Discussion and Analysis of Financial Condition and Results of Operation.”
Further discussion of ComEd’s liquidity position and capital resources and related challenges is included in the Liquidity and Capital Resources section.
New Accounting Pronouncements
See Note 1 of ComEd’s Notes to Consolidated Financial Statements for information regarding new accounting pronouncements.
| ITEM 7A. | QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK—ComEd |
ComEd is exposed to market risks associated with credit, interest rates and commodity price. These risks are described above under “Quantitative and Qualitative Disclosures about Market Risk—Exelon.”
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| ITEM 8. | FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA |
Report of Independent Registered Public Accounting Firm
To the Shareholders and Board of Directors of Commonwealth Edison Company:
In our opinion, the consolidated financial statements listed in the index appearing under Item 15(a)(2)(i) present fairly, in all material respects, the financial position of Commonwealth Edison Company and Subsidiary Companies (ComEd) at December 31, 2004 and 2003 and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2004 in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedule listed in the index appearing under Item 15(a)(2)(ii) presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements. These financial statements and the financial statement schedule are the responsibility of ComEd’s management. Our responsibility is to express an opinion on these financial statements and financial statement schedule based on our audits. We conducted our audits of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
As discussed in Note 1 to the consolidated financial statements, ComEd changed its method of accounting for variable interest entities in 2003; and as discussed in Note 10 to the consolidated financial statements, ComEd changed its method of accounting for asset retirement obligations as of January 1, 2003.
PricewaterhouseCoopers LLP
Chicago, Illinois
February 22, 2005
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Commonwealth Edison Company and Subsidiary Companies
Consolidated Statements of Income
| For the Years Ended December 31, |
||||||||||||
| (in millions) |
2004 |
2003 |
2002 |
|||||||||
| Operating revenues |
||||||||||||
| Operating revenues |
$ | 5,782 | $ | 5,749 | $ | 6,061 | ||||||
| Operating revenues from affiliates |
21 | 65 | 63 | |||||||||
| Total operating revenues |
5,803 | 5,814 | 6,124 | |||||||||
| Operating expenses |
||||||||||||
| Purchased power |
214 | 22 | 26 | |||||||||
| Purchased power from affiliate |
2,374 | 2,479 | 2,559 | |||||||||
| Operating and maintenance |
705 | 970 | 828 | |||||||||
| Operating and maintenance from affiliates |
192 | 123 | 136 | |||||||||
| Depreciation and amortization |
410 | 386 | 522 | |||||||||
| Taxes other than income |
291 | 267 | 287 | |||||||||
| Total operating expenses |
4,186 | 4,247 | 4,358 | |||||||||
| Operating income |
1,617 | 1,567 | 1,766 | |||||||||
| Other income and deductions |
||||||||||||
| Interest expense |
(258 | ) | (423 | ) | (480 | ) | ||||||
| Interest expense to affiliates |
(111 | ) | — | (4 | ) | |||||||
| Distributions on mandatorily redeemable preferred securities |
— | (26 | ) | (30 | ) | |||||||
| Equity in losses of unconsolidated affiliates |
(19 | ) | — | — | ||||||||
| Interest income from affiliates |
20 | 25 | 31 | |||||||||
| Net loss on extinguishment of long-term debt |
(130 | ) | — | — | ||||||||
| Other, net |
14 | 24 | 13 | |||||||||
| Total other income and deductions |
(484 | ) | (400 | ) | (470 | ) | ||||||
| Income before income taxes and cumulative effect of a change in accounting principle |
1,133 | 1,167 | 1,296 | |||||||||
| Income taxes |
457 | 465 | 506 | |||||||||
| Income before cumulative effect of a change in accounting principle |
676 | 702 | 790 | |||||||||
| Cumulative effect of a change in accounting principle (net of income taxes of $0) |
— | 5 | — | |||||||||
| Net income |
$ | 676 | $ | 707 | $ | 790 | ||||||
See Notes to Consolidated Financial Statements
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Commonwealth Edison Company and Subsidiary Companies
Consolidated Statements of Cash Flows
| For the Years Ended December 31, |
||||||||||||
| (in millions) |
2004 |
2003 |
2002 |
|||||||||
| Cash flows from operating activities |
||||||||||||
| Net income |
$ | 676 | $ | 707 | $ | 790 | ||||||
| Adjustments to reconcile net income to net cash flows provided by operating activities: |
||||||||||||
| Depreciation and amortization |
410 | 386 | 522 | |||||||||
| Cumulative effect of a change in accounting principle (net of income taxes) |
— | (5 | ) | — | ||||||||
| Deferred income taxes and amortization of investment tax credits |
153 | 7 | 118 | |||||||||
| Provision for uncollectible accounts |
37 | 46 | 50 | |||||||||
| Equity in losses of unconsolidated affiliates |
19 | — | — | |||||||||
| Other non-cash operating activities |
95 | 61 | 103 | |||||||||
| Changes in assets and liabilities: |
||||||||||||
| Accounts receivable |
(82 | ) | 62 | (67 | ) | |||||||
| Inventories |
(4 | ) | 14 | (9 | ) | |||||||
| Other current assets |
7 | (18 | ) | 1 | ||||||||
| Accounts payable, accrued expenses and other current liabilities |
61 | 34 | 16 | |||||||||
| Change in receivables and payables to affiliates |
30 | (155 | ) | 117 | ||||||||
| Income taxes |
109 | (107 | ) | 126 | ||||||||
| Pension and non-pension postretirement benefits obligations |
(147 | ) | (48 | ) | (68 | ) | ||||||
| Other noncurrent assets and liabilities |
(34 | ) | (36 | ) | (35 | ) | ||||||
| Net cash flows provided by operating activities |
1,330 | 948 | 1,664 | |||||||||
| Cash flows from investing activities |
||||||||||||
| Capital expenditures |
(721 | ) | (712 | ) | (780 | ) | ||||||
| Changes in Exelon intercompany money pool contributions |
97 | (405 | ) | — | ||||||||
| Receipt of notes receivable from affiliates |
1,071 | 213 | 14 | |||||||||
| Change in restricted cash |
20 | (15 | ) | (24 | ) | |||||||
| Other investing activities |
19 | 26 | 7 | |||||||||
| Net cash flows provided by (used in) investing activities |
486 | (893 | ) | (783 | ) | |||||||
| Cash flows from financing activities |
||||||||||||
| Issuance of long-term debt |
— | 1,497 | 752 | |||||||||
| Retirement of long-term debt |
(1,231 | ) | (1,425 | ) | (1,551 | ) | ||||||
| Retirement of long-term debt to ComEd Transitional Funding Trust |
(335 | ) | — | — | ||||||||
| Issuance of mandatorily redeemable preferred securities |
— | 200 | — | |||||||||
| Retirement of mandatorily redeemable preferred securities |
— | (200 | ) | — | ||||||||
| Change in short-term debt |
— | (71 | ) | 71 | ||||||||
| Dividends paid on common stock |
(457 | ) | (401 | ) | (470 | ) | ||||||
| Contributions from parent |
175 | 451 | 344 | |||||||||
| Settlement of cash-flow and fair-value hedges |
26 | (45 | ) | (10 | ) | |||||||
| Other financing activities |
2 | (43 | ) | (24 | ) | |||||||
| Net cash flow used in financing activities |
(1,820 | ) | (37 | ) | (888 | ) | ||||||
| Increase (decrease) in cash and cash equivalents |
(4 | ) | 18 | (7 | ) | |||||||
| Cash and cash equivalents at beginning of period |
34 | 16 | 23 | |||||||||
| Cash and cash equivalents at end of period |
$ | 30 | $ | 34 | $ | 16 | ||||||
See Notes to Consolidated Financial Statements
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Commonwealth Edison Company and Subsidiary Companies
Consolidated Balance Sheets
| December 31, |
||||||||
| (in millions) |
2004 |
2003 |
||||||
| Assets |
||||||||
| Current assets |
||||||||
| Cash and cash equivalents |
$ | 30 | $ | 34 | ||||
| Restricted cash |
— | 20 | ||||||
| Accounts receivable, net |
||||||||
| Customer |
726 | 683 | ||||||
| Other |
50 | 68 | ||||||
| Inventories, at average cost |
48 | 43 | ||||||
| Deferred income taxes |
— | 6 | ||||||
| Receivables from affiliates |
10 | 23 | ||||||
| Contributions to Exelon intercompany money pool |
308 | 405 | ||||||
| Other |
24 | 31 | ||||||
| Total current assets |
1,196 | 1,313 | ||||||
| Property, plant and equipment, net |
9,463 | 9,096 | ||||||
| Deferred debits and other assets |
||||||||
| Investments |
39 | 36 | ||||||
| Investments in affiliates |
52 | 73 | ||||||
| Goodwill |
4,705 | 4,719 | ||||||
| Receivables from affiliates |
1,443 | 2,271 | ||||||
| Pension asset |
156 | 4 | ||||||
| Other |
387 | 453 | ||||||
| Total deferred debits and other assets |
6,782 | 7,556 | ||||||
| Total assets |
$ | 17,441 | $ | 17,965 | ||||
| Liabilities and shareholders’ equity |
||||||||
| Current liabilities |
||||||||
| Long-term debt due within one year |
$ | 272 | $ | 236 | ||||
| Long-term debt to ComEd Transitional Funding Trust due within one year |
321 | 317 | ||||||
| Accounts payable |
196 | 170 | ||||||
| Accrued expenses |
589 | 540 | ||||||
| Payables to affiliates |
227 | 207 | ||||||
| Customer deposits |
93 | 78 | ||||||
| Deferred income taxes |
17 | — | ||||||
| Other |
49 | 9 | ||||||
| Total current liabilities |
1,764 | 1,557 | ||||||
| Long-term debt |
2,901 | 4,167 | ||||||
| Long-term debt to ComEd Transitional Funding Trust |
1,020 | 1,359 | ||||||
| Long-term debt to other financing trusts |
361 | 361 | ||||||
| Deferred credits and other liabilities |
||||||||
| Deferred income taxes |
1,890 | 1,686 | ||||||
| Unamortized investment tax credits |
45 | 48 | ||||||
| Non-pension postretirement benefits obligation |
195 | 190 | ||||||
| Payables to affiliates |
17 | 28 | ||||||
| Regulatory liabilities |
2,204 | 1,891 | ||||||
| Other |
304 | 336 | ||||||
| Total deferred credits and other liabilities |
4,655 | 4,179 | ||||||
| Total liabilities |
10,701 | 11,623 | ||||||
| Commitments and contingencies |
||||||||
| Shareholders’ equity |
||||||||
| Common stock |
1,588 | 1,588 | ||||||
| Preference stock |
7 | 7 | ||||||
| Other paid in capital |
4,168 | 4,115 | ||||||
| Receivable from parent |
(125 | ) | (250 | ) | ||||
| Retained earnings |
1,102 | 883 | ||||||
| Accumulated other comprehensive income (loss) |
— | (1 | ) | |||||
| Total shareholders’ equity |
6,740 | 6,342 | ||||||
| Total liabilities and shareholders’ equity |
$ | 17,441 | $ | 17,965 | ||||
See Notes to Consolidated Financial Statements
248
Commonwealth Edison Company and Subsidiary Companies
Consolidated Statements of Changes in Shareholders’ Equity
| (in millions) |
Common Stock |
Preferred and Preference Stock |
Other Paid In Capital |
Receivable from Parent |
Retained Earnings Unappropriated |
Retained Earnings Appropriated |
Accumulated Other Comprehensive Income (Loss) |
Treasury Stock |
Total Shareholders’ Equity |
||||||||||||||||||||||||||
| Balance, December 31, 2001 |
$ | 2,048 | $ | 7 | $ | 5,057 | $ | (937 | ) | $ | 257 | $ | — | $ | (5 | ) | $ | (1,344 | ) | $ | 5,083 | ||||||||||||||
| Net income |
— | — | — | — | 790 | — | — | — | 790 | ||||||||||||||||||||||||||
| Repayment of receivable from parent |
— | — | — | 322 | — | — | — | — | 322 | ||||||||||||||||||||||||||
| Allocation of tax benefit from parent |
— | — | 28 | — | — | — | — | — | 28 | ||||||||||||||||||||||||||
| Retirement of treasury shares |
(460 | ) | — | (884 | ) | — | — | — | — | 1,344 | — | ||||||||||||||||||||||||
| Merger fair value adjustments |
— | — | 38 | — | — | — | — | — | 38 | ||||||||||||||||||||||||||
| Common stock dividends |
— | — | — | — | (470 | ) | — | — | — | (470 | ) | ||||||||||||||||||||||||
| Other comprehensive income, net of income taxes of $(23) |
— | — | — | — | — | — | (33 | ) | — | (33 | ) | ||||||||||||||||||||||||
| Balance, December 31, 2002 |
1,588 | 7 | 4,239 | (615 | ) | 577 | — | (38 | ) | — | 5,758 | ||||||||||||||||||||||||
| Net income |
— | — | — | — | 707 | — | — | — | 707 | ||||||||||||||||||||||||||
| Repayment of receivable from parent |
— | — | — | 365 | — | — | — | — | 365 | ||||||||||||||||||||||||||
| Allocation of tax benefit from parent |
— | — | 86 | — | — | — | — | — | 86 | ||||||||||||||||||||||||||
| Appropriation of Retained Earnings for future dividends |
— | — | — | — | (709 | ) | 709 | — | — | — | |||||||||||||||||||||||||
| Common stock dividends |
— | — | — | — | (401 | ) | — | — | — | (401 | ) | ||||||||||||||||||||||||
| Adoption of SFAS No. 143 |
— | — | (210 | ) | — | — | — | — | — | (210 | ) | ||||||||||||||||||||||||
| Other comprehensive income, net of income taxes of $23 |
— | — | — | — | — | — | 37 | — | 37 | ||||||||||||||||||||||||||
| Balance, December 31, 2003 |
1,588 | 7 | 4,115 | (250 | ) | 174 | 709 | (1 | ) | — | 6,342 | ||||||||||||||||||||||||
| Net income |
— | — | — | — | 676 | — | — | — | 676 | ||||||||||||||||||||||||||
| Repayment of receivable from parent |
— | — | — | 125 | — | — | — | — | 125 | ||||||||||||||||||||||||||
| Allocation of tax benefit from parent |
— | — | 55 | — | — | — | — | — | 55 | ||||||||||||||||||||||||||
| Appropriation of Retained Earnings for future dividends |
— | — | — | — | (676 | ) | 676 | — | — | — | |||||||||||||||||||||||||
| Common stock dividends |
— | — | — | — | (174 | ) | (283 | ) | — | — | (457 | ) | |||||||||||||||||||||||
| Merger fair value adjustments |
— | — | (2 | ) | — | — | — | — | — | (2 | ) | ||||||||||||||||||||||||
| Other comprehensive income, net of income taxes of $2 |
— | — | — | — | — | — | 1 | — | 1 | ||||||||||||||||||||||||||
| Balance, December 31, 2004 |
$ | 1,588 | $ | 7 | $ | 4,168 | $ | (125 | ) | $ | — | $ | 1,102 | $ | — | $ | — | $ | 6,740 | ||||||||||||||||
See Notes to Consolidated Financial Statements.
249
Commonwealth Edison Company and Subsidiary Companies
Consolidated Statements of Comprehensive Income
| For the Years Ended December 31, |
||||||||||
| (in millions) |
2004 |
2003 |
2002 |
|||||||
| Net income |
$ | 676 | $ | 707 | $ | 790 | ||||
| Other comprehensive income (loss) |
||||||||||
| Change in net unrealized gain (loss) on cash-flow hedges, net of income taxes of $0, $21 and $(21), respectively |
— | 31 | (30 | ) | ||||||
| Foreign currency translation adjustment, net of income taxes of $1, $0 and $0, respectively |
— | 3 | — | |||||||
| Unrealized gain (loss) on marketable securities, net of income taxes of $1, $2 and $(1), respectively |
1 | 3 | (3 | ) | ||||||
| Total other comprehensive income (loss) |
1 | 37 | (33 | ) | ||||||
| Total comprehensive income |
$ | 677 | $ | 744 | $ | 757 | ||||
See Notes to Consolidated Financial Statements
250
Commonwealth Edison Company and Subsidiary Companies
Notes to Consolidated Financial Statements
(Dollars in millions, unless otherwise noted)
1. Significant Accounting Policies
Description of Business
Commonwealth Edison Company (ComEd) is a regulated utility engaged principally in the purchase, transmission, distribution and sale of electricity to a diverse base of residential, commercial, industrial and wholesale customers in northern Illinois. ComEd’s retail service territory has an area of approximately 11,300 square miles and an estimated population of eight million. The service territory includes the City of Chicago (Chicago), an area of about 225 square miles with an estimated population of three million. ComEd has approximately 3.7 million customers.
Basis of Presentation
ComEd, a regulated electric utility, is a principal subsidiary of Exelon Corporation (Exelon), which owns 99.9% of ComEd’s common stock.
ComEd’s consolidated financial statements include the accounts of ComEd, Commonwealth Edison Company of Indiana, Inc., Edison Development Canada Inc., and Edison Finance Partnership. Commonwealth Research Corporation and Edison Development Company were consolidated prior to their dissolution in 2004. All intercompany transactions have been eliminated. Effective December 31, 2003, the accounts of ComEd Financing II, ComEd Financing III, ComEd Funding LLC (ComEd Funding) and ComEd Transitional Funding Trust (ComEd Funding Trust) are no longer consolidated. ComEd Funding and ComEd Funding Trust are separate legal entities from ComEd; the debt issued by these subsidiaries is solely their obligation, and their assets, including transitional property, are not available to creditors of ComEd. See “Variable Interest Entities” below. ComEd accounts for its less than 20% owned investments under the cost method of accounting.
Reclassifications
Certain prior year amounts have been reclassified for comparative purposes. The reclassifications had no effect on net income or shareholders’ equity.
Use of Estimates
The preparation of financial statements in conformity with accounting principles generally accepted in the United States (GAAP) requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. Areas in which significant estimates have been made include, but are not limited to, the accounting for unbilled revenue, derivatives, asset and goodwill impairment, environmental costs, allowance for doubtful accounts, fixed asset depreciation, taxes and pension and other postretirement costs.
Accounting for the Effects of Regulation
ComEd is regulated by the Illinois Commerce Commission (ICC) under state public utility laws, the Federal Energy Regulatory Commission (FERC) under various Federal laws and the Securities and Exchange Commission (SEC) under the Public Utility Holding Company Act of 1935 (PUHCA). ComEd
251
Commonwealth Edison Company and Subsidiary Companies
Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, unless otherwise noted)
accounts for its regulated electric operations in accordance with Financial Accounting Standards Board (FASB) Statement of Financial Accounting Standards (SFAS) No. 71, “Accounting for the Effects of Certain Types of Regulation,” (SFAS No. 71) which requires ComEd to record in the financial statements the effects of rate regulation. Use of SFAS No. 71 is applicable to the utility operations of ComEd that meet the following criteria: (1) third-party regulation of rates; (2) cost-based rates; and (3) a reasonable assumption that all costs will be recoverable from customers through rates. ComEd believes that it is probable that regulatory assets and liabilities associated with these operations will be recovered or settled. If a separable portion of ComEd’s business no longer meets the provisions of SFAS No. 71, ComEd would be required to eliminate from its financial statements the effects of regulation for that portion.
Segment Information
ComEd operates in one segment—energy delivery.
Variable Interest Entities
The FASB issued FASB Interpretation No. (FIN) 46 “Consolidation of Variable Interest Entities” in January 2003 and issued its revision in FASB Interpretation No. 46-R “Consolidation of Variable Interest Entities” (FIN 46-R) in December 2003, which addressed the requirements for consolidating certain variable interest entities. FIN 46-R was effective December 31, 2003 for ComEd’s variable interest entities that are considered to be special-purpose entities. FIN 46-R applied to all other variable interest entities as of March 31, 2004.
As of December 31, 2003, the financing trusts of ComEd, namely ComEd Financing II (formed in November 1996), ComEd Financing III (formed in September 2002), ComEd Funding LLC (formed in July 1998), and ComEd Transitional Funding Trust (formed in October 1998) were deconsolidated from the financial statements of ComEd pursuant to the provisions of FIN 46-R. As of December 31, 2004, amounts of $1.7 billion owed to these financing trusts were recorded as debt to other financing trusts and debt to ComEd Transitional Funding Trust within the Consolidated Balance Sheet. ComEd recognized equity in net losses related to these unconsolidated financing subsidiaries of $19 million for the year ended December 31, 2004.
This change in presentation had no significant impact on the results of operations or financial position of ComEd. In accordance with FIN 46-R, prior periods have not been restated. The maximum exposure to loss as a result of ComEd’s involvement with the financing trusts is $62 million at December 31, 2004.
Revenues
Operating revenues are recorded as service is rendered or energy is delivered to customers. At the end of each month, ComEd accrues an estimate for the unbilled amount of energy delivered or services provided to its customers. See Note 3—Accounts Receivable for further discussion.
Stock-Based Compensation
ComEd participates in Exelon’s stock-based compensation plans. Exelon accounts for its stock-based compensation plans under the intrinsic method prescribed by Accounting Principles Board No.
252
Commonwealth Edison Company and Subsidiary Companies
Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, unless otherwise noted)
25, “Accounting for Stock Issued to Employees” and related interpretations and follows the disclosure requirements of SFAS No. 123, “Accounting for Stock-Based Compensation” (SFAS No. 123), and SFAS No. 148, “Accounting for Stock-Based Compensation—Transition and Disclosure—an amendment of FASB Statement No. 123.” Accordingly, no compensation expense for stock options has been recognized within the Consolidated Statements of Income. The table below shows the effect on ComEd’s net income for 2004, 2003 and 2002 had Exelon elected to account for its stock-based compensation plans using the fair-value method under SFAS No. 123:
| 2004 |
2003 |
2002 | |||||||
| Net income—as reported |
$ | 676 | $ | 707 | $ | 790 | |||
| Deduct: Total stock-based compensation expense determined under fair-value method for all awards, net of income taxes (a) |
5 | 5 | 13 | ||||||
| Pro forma net income |
$ | 671 | $ | 702 | $ | 777 | |||
| (a) | The fair value of options granted was estimated using a Black-Scholes option pricing model. |
Income Taxes
Deferred Federal and state income taxes are provided on all significant temporary differences between the book basis and the tax basis of assets and liabilities and for tax carryforwards. Investment tax credits previously used for income tax purposes have been deferred on ComEd’s Consolidated Balance Sheets and are recognized in book income over the life of the related property.
Exelon and its subsidiaries, including ComEd, file a consolidated return for Federal and certain state income tax returns. Income taxes of the Exelon consolidated group are allocated to ComEd based on the separate return method. See Note 9—Income Taxes for further discussion.
ComEd is a party to an agreement (Tax Sharing Agreement) with Exelon and other subsidiaries of Exelon that provides for the allocation of consolidated tax liabilities. The Tax Sharing Agreement generally provides that each party is allocated an amount of tax similar to that which would be owed had the party been separately subject to tax. Any net benefit attributable to the parent is reallocated to other members. That allocation is treated as a contribution to the capital of the party receiving the benefit.
Losses on Reacquired Debt
Recoverable losses on reacquired debt related to regulated operations are deferred and amortized to interest expense over the life of new debt issued to finance the debt redemption consistent with rate recovery for rate-making purposes. Losses on reacquired debt that are not refinanced with new debt are recognized in ComEd’s Consolidated Statements of Income as incurred.
Comprehensive Income
Comprehensive income includes all changes in equity during a period except those resulting from investments by and distributions to shareholders. Comprehensive income is reflected in the Consolidated Statements of Changes in Shareholders’ Equity and the Consolidated Statements of Comprehensive Income.
253
Commonwealth Edison Company and Subsidiary Companies
Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, unless otherwise noted)
Cash and Cash Equivalents
ComEd considers all temporary cash investments purchased with an original maturity of three months or less to be cash equivalents.
Restricted Cash
As of December 31, 2003, ComEd’s restricted cash related to proceeds from a pollution control bond offering in December 2003, which were applied to redeem pollution control bonds that matured in January 2004.
Allowance for Doubtful Accounts
The allowance for doubtful accounts reflects ComEd’s best estimate of probable losses in the accounts receivable balance. The allowance is based on known troubled accounts, historical experience and other currently available evidence. Customer accounts are generally considered delinquent if the amount billed is not received by the time the next bill is issued, typically monthly. Customer accounts are written off based upon approved regulatory or legislative requirements.
Marketable Securities
Marketable securities are classified as available-for-sale securities and are reported at fair value, with the unrealized gains and losses, net of tax, reported in other comprehensive income. At December 31, 2004 and 2003, ComEd had no held-to-maturity or trading securities.
Property, Plant and Equipment
Property, plant and equipment is recorded at cost. ComEd evaluates the carrying value of property, plant and equipment and other long-term assets for impairment whenever circumstances indicate the carrying value of those assets may not be recoverable under the provisions of SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets.” The cost of maintenance, repairs and minor replacements of property is charged to maintenance expense as incurred.
Upon retirement, the cost of regulated property, net of salvage, is charged to accumulated depreciation and removal costs reduce the related regulatory liability in accordance with the composite method of depreciation. See Note 16—Supplemental Financial Information. For unregulated property, the cost and accumulated depreciation of the property, plant and equipment retired or otherwise disposed of are removed from the related accounts and included in the determination of any gain or loss on disposition. See Note 4—Property, Plant and Equipment.
Capitalized Software Costs
Costs incurred during the application development stage of software projects that are developed or obtained for internal use are capitalized. At December 31, 2004 and 2003, net unamortized capitalized software costs totaled $139 million and $150 million, respectively. Such capitalized amounts are amortized ratably over the expected lives of the projects when they become operational, generally not to exceed ten years. Certain capitalized software is being amortized over 15 years pursuant to regulatory approval. During 2004, 2003 and 2002, ComEd amortized capitalized software costs of $34 million, $33 million and $23 million, respectively.
254
Commonwealth Edison Company and Subsidiary Companies
Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, unless otherwise noted)
Depreciation and Amortization
Depreciation, including a provision for estimated removal costs as authorized by the ICC, is provided over the estimated service lives of property, plant, and equipment on a straight-line basis using the composite method. Annual depreciation provisions for financial reporting purposes, expressed as a percentage of average service life for each asset category are presented in the table below:
| Asset Category |
2004 |
2003 |
2002 |
||||||
| Electric—transmission and distribution |
3.16 | % | 3.20 | % | 3.74 | % | |||
| Other property and equipment |
5.77 | % | 7.14 | % | 7.92 | % |
Amortization of regulatory assets is provided over the recovery period specified in the related legislation or regulatory agreement.
Allowance for Funds Used During Construction
Allowance for Funds Used During Construction (AFUDC) is the cost, during the period of construction, of debt and equity funds used to finance construction projects for regulated operations. AFUDC of $3 million, $15 million and $18 million in 2004, 2003 and 2002, respectively, was recorded as a charge to construction work in progress and as a non-cash credit to AFUDC which is included in other income and deductions within the Consolidated Statements of Income. The rates used for capitalizing AFUDC are computed under a method prescribed by regulatory authorities.
Goodwill
Goodwill represents the excess of the purchase price paid over the estimated fair value of the assets acquired and liabilities assumed in the acquisition of a business. As of January 1, 2002, ComEd adopted SFAS No. 142. Pursuant to SFAS No. 142, goodwill is not amortized but is tested for impairment at least annually or on an interim basis if an event occurs or circumstances change that would reduce the fair value of a reporting unit below its carrying value. See Note 5—Goodwill for further information.
Derivative Financial Instruments
ComEd enters into derivatives to manage its exposure to fluctuations in interest rates, changes in interest rates related to planned future debt issuances and changes in the fair value of outstanding debt. ComEd’s derivative activities are in accordance with Exelon’s Risk Management Policy (RMP).
ComEd accounts for derivative financial instruments pursuant to SFAS No. 133, “Accounting for Derivatives and Hedging Activities” (SFAS No. 133). Under the provisions of SFAS No. 133, all derivatives are recognized on the balance sheet at their fair value unless they qualify for a normal purchases and normal sales exception. Derivatives recorded at fair value on the balance sheet are presented as current or noncurrent mark-to-market derivative assets or liabilities. Changes in the fair value of the derivative financial instrument are recognized in earnings unless specific hedge accounting criteria are met, in which case those changes are recorded in earnings as an offset to the changes in fair value of the exposure being hedged or deferred in accumulated other comprehensive income and recognized in earnings as hedged transactions occur. Amounts recorded in earnings are included in other, net on the consolidated statements of income.
255
Commonwealth Edison Company and Subsidiary Companies
Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, unless otherwise noted)
A derivative financial instrument can be designated as a hedge of the fair value of a recognized asset or liability or of an unrecognized firm commitment (fair-value hedge), or a hedge of a forecasted transaction or the variability of cash flows to be received or paid related to a recognized asset or liability (cash-flow hedge). Changes in the fair value of a derivative that is highly effective as, and is designated and qualifies as a fair-value hedge, are recognized in earnings as offsets to the changes in fair value of the exposure being hedged. Changes in the fair value of a derivative that is highly effective as, and is designated as and qualifies as, a cash-flow hedge are deferred in accumulated other comprehensive income and are recognized in earnings as the hedged transactions occur. Any ineffectiveness is recognized in earnings immediately. On an ongoing basis, the Company assesses the hedge effectiveness of all derivatives that are designated as hedges for accounting purposes in order to determine that each derivative continues to be highly effective in offsetting changes in fair values or cash flows of hedged items. If it is determined that the derivative is not highly effective as a hedge, hedge accounting will be discontinued prospectively.
Severance Benefits
ComEd participates in Exelon’s ongoing severance plans, which are accounted for in accordance with SFAS No. 112, “Employer’s Accounting for Postemployment Benefits, an amendment of FASB Statements No. 5 and 43” (SFAS No. 112) and SFAS No. 88, “Employers’ Accounting for Settlements and Curtailments of Defined Benefit Pension Plans and for Termination Benefits.” Amounts associated with severance benefits that are considered probable and can be reasonably estimated are accrued. See Note 6—Severance Accounting for further discussion of ComEd’s accounting for severance benefits.
Retirement Benefits
ComEd participates in Exelon’s defined benefit pension plans and postretirement welfare benefit plans. Exelon’s defined benefit pension plans and postretirement welfare benefit plans are accounted for in accordance with SFAS No. 87, “Employer’s Accounting for Pensions” (SFAS No. 87), SFAS No. 106, “Employers’ Accounting for Postretirement Benefits Other than Pensions” (SFAS No. 106) and FASB Staff Position (FSP) FAS 106-2, “Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003” (FSP FAS 106-2), and are disclosed in accordance with SFAS No. 132, “Employers’ Disclosures about Pensions and Other Postretirement Benefits—an Amendment of FASB Statements No. 87, 88, and 106” (revised 2003) (SFAS No. 132). See Note 11—Retirement Benefits for further discussion of retirement benefits.
FSP FAS 106-2. Through Exelon’s postretirement benefit plans, ComEd provides retirees with prescription drug coverage. On December 8, 2003 the Medicare Prescription Drug, Improvement and Modernization Act of 2003 (the Prescription Drug Act) was enacted. The Prescription Drug Act introduced a prescription drug benefit under Medicare as well as a Federal subsidy to sponsors of retiree health care benefit plans that provide a benefit that is at least actuarially equivalent to the Medicare prescription drug benefit. Management believes the prescription drug benefit provided under Exelon’s postretirement benefit plans is at least actuarially equivalent to the Medicare prescription drug benefit. In response to the enactment of the Prescription Drug Act, in May 2004, the FASB issued FSP FAS 106-2, which provided transition guidance for accounting for the effects of the Prescription Drug Act and superseded FSP FAS 106-1, which had been issued in January 2004. FSP FAS 106-1 permitted a plan sponsor of a postretirement health care plan that provides a prescription drug benefit
256
Commonwealth Edison Company and Subsidiary Companies
Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, unless otherwise noted)
to make a one-time election to defer the accounting for the effects of the Prescription Drug Act. ComEd made the one-time election allowed by FSP FAS 106-1 during the first quarter of 2004. During the second quarter of 2004, ComEd early adopted the provisions of FSP FAS 106-2, resulting in a reduction in net periodic postretirement benefit cost. Historical financial information for the three months ended March 31, 2004 has been adjusted in Note 18—Quarterly Data (Unaudited) and will be adjusted when presented for comparative purposes in future periods to reflect a reduction in net periodic postretirement benefit cost due to the adoption of FSP FAS 106-2.
Foreign Currency Translation
The financial statements of ComEd’s foreign subsidiaries, Edison Development Canada, Inc. and Edison Finance Partnership, were prepared in their respective local currencies and translated into U.S. dollars based on the current exchange rates at the end of the periods for the Consolidated Balance Sheets and on weighted-average rates for the periods for the Consolidated Statements of Income. Foreign currency translation adjustments, net of deferred income tax benefits, are reflected as a component of other comprehensive income on the Consolidated Statements of Comprehensive Income and, accordingly, have no effect on net income.
New Accounting Pronouncements
SFAS No. 151. In November 2004, the FASB issued FASB Statement No. 151, “Inventory Costs—an amendment of ARB No. 43, Chapter 4” (SFAS No. 151), which is the result of its efforts to converge U.S. accounting standards for inventories with International Accounting Standards. SFAS No. 151 requires abnormal amounts of idle facility expense, freight, handling costs and wasted material or spoilage to be recognized as current-period charges. It also requires that allocation of fixed production overheads to the costs of conversion be based on the normal capacity of the production facilities. SFAS No. 151 will be effective for inventory costs incurred during fiscal years beginning after June 15, 2005. ComEd is assessing the impact SFAS No. 151 will have on its consolidated financial statements.
SFAS No. 123-R. In December 2004, the FASB issued FASB Statement No. 123 (revised 2004), “Share-Based Payment” (SFAS No. 123-R). SFAS No. 123-R replaces SFAS No. 123 and supersedes APB No. 25. SFAS No. 123-R requires that the compensation cost relating to share-based payment transactions be recognized in the financial statements. That cost will be measured based on the fair value of the equity or liability instruments issued. Exelon will no longer be permitted to follow the intrinsic value accounting method of APB No. 25, which resulted in no expense being recorded for stock option grants for which the strike price was equal to the fair value of the underlying stock on the date of grant. Exelon has not elected to early adopt SFAS No. 123-R. As a result, SFAS No. 123-R will be effective for Exelon in the third quarter of 2005 and will apply to all of Exelon’s outstanding unvested share-based payment awards as of July 1, 2005 and all prospective awards. Exelon is assessing the impact SFAS No. 123-R will have on its consolidated financial statements and which of three transition methods allowed by SFAS No. 123-R will be elected.
SFAS No. 153. In December 2004, the FASB issued FASB Statement No. 153, “Exchanges of Nonmonetary Assets, an amendment of APB Opinion No. 29, ‘Accounting for Nonmonetary Transactions’” (SFAS No. 153). Previously, APB Opinion No. 29 had required that the accounting for an exchange of a productive asset for a similar productive asset or an equivalent interest in the same or similar productive asset should be based on the recorded amount of the asset relinquished. The
257
Commonwealth Edison Company and Subsidiary Companies
Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, unless otherwise noted)
amendments made by SFAS No. 153 are based on the principle that exchanges of nonmonetary assets should be measured based on the fair value of the assets exchanged. Further, the amendments eliminate the narrow exception for nonmonetary exchanges of similar productive assets and replace it with a broader exception for exchanges of nonmonetary assets that do not have commercial substance. SFAS No. 153 will be effective for ComEd in the third quarter of 2005 and earlier application is permitted for nonmonetary asset exchanges occurring after the issuance of SFAS No. 153. The provisions of SFAS No. 153 are applied prospectively. ComEd is assessing the impact SFAS No. 153 will have on its consolidated financial statements.
FSP FAS 109-1 and FSP FAS 109-2. In December 2004, the FASB issued FSP FAS 109-1, “Application of FASB Statement No. 109, ‘Accounting for Income Taxes,’ to the Tax Deduction on Qualified Production Activities Provided by the American Jobs Creation Act of 2004” (FSP FAS 109-1) and FSP FAS 109-2, “Accounting and Disclosure Guidance for the Foreign Earnings Repatriation Provisions within the American Jobs Creation Act of 2004” (FSP FAS 109-2). FSP FAS 109-1 and FSP FAS 109-2 were effective upon issuance. The American Jobs Creation Act of 2004 (Act), signed into law on October 22, 2004, provided, generally, for a tax deduction for domestic manufacturing activities of up to nine percent (when fully phased-in) of the lesser of “qualified production activities income,” as defined in the Act, or taxable income. FSP FAS 109-1 clarified that the tax deduction for domestic manufacturing activities under the Act should be accounted for as a special deduction in accordance with SFAS No. 109, “Accounting for Income Taxes” (SFAS No. 109). The Act also provided a special limited-time dividends received deduction on the repatriation of certain foreign earnings to a U.S. taxpayer, provided certain criteria are met. FSP FAS 109-2 provides a registrant more time to evaluate the Act’s impact on the registrant’s plan for reinvestment or repatriation of certain foreign earnings for purposes of applying SFAS No. 109. ComEd is assessing the impact, if any, that the Act and these standards may have on its consolidated financial statements in future periods.
2. Regulatory Issues
PJM Integration. On June 2, 2003, ComEd began receiving electric transmission reservation services from PJM Interconnection, LLC (PJM) and transferred control of ComEd’s Open Access Same Time Information System to PJM. On April 27, 2004 the FERC issued its order approving ComEd’s application to complete its integration into PJM, subject to certain stipulations, including a provision to hold certain utilities in Michigan and Wisconsin harmless from the associated impacts for ComEd to join PJM. ComEd agreed to these stipulations and fully integrated its transmission facilities into PJM on May 1, 2004. In the fourth quarter of 2004, ComEd entered into settlement agreements with all such Michigan and Wisconsin utilities requiring a total payment of approximately $4 million by ComEd. FERC has approved these agreements and payment is expected to be made in the first quarter of 2005.
Through and Out Rates. In November 2004, the FERC issued two orders authorizing ComEd to recover from various entities revenue representing amounts that ComEd will lose as a result of the elimination of through and out (T&O) charges, for energy flowing across ComEd’s transmission system, that were terminated pursuant to the FERC orders effective December 1, 2004. The collection of this revenue will be over a transitional period of December 1, 2004 through March 31, 2006. Several parties have sought rehearing of the FERC orders and there likely will be appeals filed in the matter after the rehearing order is issued. During 2004 prior to the termination of T&O charges, ComEd collected net T&O charges of approximately $50 million. As a result of this proceeding, ComEd may
258
Commonwealth Edison Company and Subsidiary Companies
Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, unless otherwise noted)
see reduced net collections of these charges. The ultimate outcome of this proceeding is uncertain and may have a material adverse effect on ComEd’s financial condition, results of operations or cash flows.
Delivery Service Rates. On March 3, 2003, ComEd entered into, and the ICC subsequently entered orders to implement, an agreement (Agreement) with various Illinois retail market participants and other interested parties that settled, among other things, delivery service rates and the market value index proceeding and facilitates competitive service declarations for large-load customers and an extension of the purchase power agreement (PPA) with Exelon Generation Company, LLC (Generation). The effect of the Agreement is lower competitive transition charge (CTC) collections that ComEd receives from customers who take electricity from an alternative electric supplier or under the power purchase option (PPO) through 2006. The Agreement also allows customers to lock in current CTCs for multiple years. In 2004 and 2003, ComEd collected $169 million and $304 million in CTC revenues, respectively.
In 2003, ComEd recorded a charge to earnings associated with the required funding of specified programs and initiatives associated with the Agreement of $51 million (before income taxes) on a present value basis. This amount was partially offset by the reversal of a $12 million (before income taxes) reserve established in the third quarter of 2002 for a potential capital disallowance in ComEd’s delivery services rate proceeding and a credit of $10 million (before income taxes) related to the capitalization of employee incentive payments provided for in the delivery services order. The charge of $51 million and the credit of $10 million were recorded in operating and maintenance expense and the reversal of the $12 million reserve was recorded in other, net within ComEd’s Consolidated Statements of Income. The net charge for these items was $29 million (before income taxes). In accordance with the Agreement, ComEd made payments of $10 million and $23 million during 2004 and 2003, respectively.
Customer Choice. All ComEd’s retail customers are eligible to choose an alternative electric supplier and most non-residential customers can also elect the PPO that allows the purchase of electric energy from ComEd at market-based prices. As of December 31, 2004, no alternative electric supplier had approval from the ICC, and no electric utilities had chosen, to enter the ComEd residential market for the supply of electricity. At December 31, 2004, approximately 22,100 non-residential customers, representing approximately 35% of ComEd’s annual retail kilowatthour sales, had elected to purchase their electric energy from an alternative electric supplier or had chosen the PPO. Customers who receive energy from an alternative supplier continue to pay a delivery charge.
Competitive Service Declarations. On November 14, 2002, the ICC allowed ComEd, by operation of law, to revise its provider of last resort obligation to be the back-up energy supplier at market-based rates for certain customers with energy demands of at least three megawatts (MWs). About 370 of ComEd’s largest energy customers are affected, representing an aggregate supply obligation or load of approximately 2,500 MWs. These customers will not have a right to take bundled service after June 2006 or to return to bundled rates if they choose an alternative supplier prior to June 2006.
On March 28, 2003, the ICC approved changes to ComEd’s real-time pricing tariff for non-residential customers, including those with energy demands of at least three MWs, who choose hourly energy supply for their electric power and energy. These ICC orders were affirmed on appeal.
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Commonwealth Edison Company and Subsidiary Companies
Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, unless otherwise noted)
ComEd cannot predict the long-term impact of customer choice and competitive service declarations on its result of operations.
Rate Reductions and Return on Common Equity Threshold. The Illinois restructuring legislation, as amended, required a 15% residential base rate reduction effective August 1, 1998 and an additional 5% residential base rate reduction effective October 1, 2001. In addition, a base rate freeze, reflecting the residential base rate reductions, is in effect through January 1, 2007. A utility may request a rate increase during the rate freeze period only when necessary to ensure the utility’s financial viability. Under the Illinois legislation, if the two-year average of the earned return on common equity of a utility through December 31, 2006 exceeds an established threshold, one-half of the excess earnings must be refunded to customers. The threshold rate of return on common equity is based on a two-year average of the Monthly Treasury Bond Long-Term Average Rates (20 years and above) plus 8.5% in the years 2000 through 2006. Earnings for purposes of ComEd’s threshold include ComEd’s net income calculated in accordance with GAAP and reflect the amortization of regulatory assets. Under Illinois statute, any impairment of goodwill would have no impact on the determination of the cap on ComEd’s allowed equity return during the transition period. As a result of the Illinois legislation, at December 31, 2004, ComEd had a regulatory asset related to recoverable transition costs with an unamortized balance of $87 million that it expects to fully recover and amortize by the end of 2006. Consistent with the provisions of the Illinois legislation, regulatory assets may be recovered in amounts that provide ComEd an earned return on common equity within the Illinois legislation earnings threshold. ComEd has not triggered the earnings sharing provision through 2004.
Nuclear Decommissioning Costs. In connection with the transfer of ComEd’s nuclear generating stations to Generation, the ICC permitted ComEd to recover $73 million per year from retail customers for decommissioning for the years 2001 through 2004 and, depending upon the portion of the output from those stations taken by ComEd, up to $73 million annually in 2005 and 2006. Because ComEd is not expected to take all of the output of these stations, actual collections are expected to be less than $73 million annually in 2005 and 2006. Subsequent to 2006, there will be no further recoveries of decommissioning costs from customers. Any surplus funds after a nuclear station is decommissioned must be refunded to ComEd’s customers. Amounts collected by ComEd from retail customers are remitted to Generation. See Note 10—Nuclear Decommissioning.
Open Access Transmission Tariff. On November 10, 2003, the FERC issued an order allowing ComEd to put into effect, subject to refund and rehearing, new transmission rates designed to reflect nearly $500 million of infrastructure investments made since 1998; however, because of the Illinois retail rate freeze and the method for calculating CTCs, the increase is not expected to significantly increase operating revenues until December 31, 2006. During the third quarter 2004, a settlement agreement was reached which was approved by the FERC during the fourth quarter of 2004, which established new rates that became effective May 1, 2004.
3. Accounts Receivable
Customer accounts receivable at December 31, 2004 and 2003 included unbilled operating revenues of $275 million and $225 million, respectively. The allowance for uncollectible accounts at December 31, 2004 and 2003 was $16 million.
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Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, unless otherwise noted)
4. Property, Plant and Equipment
A summary of property, plant and equipment by category as of December 31, 2004 and 2003 is as follows:
| 2004 |
2003 | |||||
| Electric—transmission and distribution |
$ | 8,978 | $ | 8,297 | ||
| Construction work in progress |
195 | 365 | ||||
| Other property, plant and equipment |
1,298 | 1,205 | ||||
| Total property, plant and equipment |
10,471 | 9,867 | ||||
| Less accumulated depreciation |
1,008 | 771 | ||||
| Property, plant and equipment, net |
$ | 9,463 | $ | 9,096 | ||
ComEd’s depreciation expense, which is included in cost of service for rate purposes, includes an estimated cost of dismantling and removing plant from service upon retirement. Beginning in 2003, in accordance with new interpretations of regulatory accounting practice, collections for future removal costs are recorded as a regulatory liability. For more information, see Note 16—Supplemental Financial Information.
Effective July 1, 2002, ComEd decreased its depreciation rates based on a new depreciation study reflecting its significant construction program in recent years, changes in and development of new technologies, and changes in estimated plant service lives since the last depreciation study. The annualized reduction in depreciation expense was $96 million.
5. Goodwill
As of December 31, 2004 and 2003, ComEd had recorded goodwill of approximately $4.7 billion. The changes in the carrying amount of goodwill for the years ended December 31, 2003 and 2004 were as follows:
| Balance as of January 1, 2003 |
$ | 4,916 | ||
| Adoption of SFAS No. 143: (a) |
||||
| Reduction of asset retirement obligation |
(210 | ) | ||
| Cumulative effect of change in accounting principles |
5 | |||
| Resolution of certain tax matters |
8 | |||
| Balance as of January 1, 2004 |
4,719 | |||
| Resolution of certain tax matters |
(9 | ) | ||
| Merger severance adjustments |
(5 | ) | ||
| Balance as of December 31, 2004 |
$ | 4,705 | ||
| (a) | See Note 10—Nuclear Decommissioning. |
Effective January 1, 2002, ComEd adopted SFAS No. 142. Pursuant to SFAS No. 142, goodwill is no longer amortized; however, in addition to initial assessment, goodwill is subject to an assessment for impairment at least annually, or more frequently, if events or circumstances indicate that goodwill might be impaired. The impairment assessment is performed using a two-step, fair-value based test.
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Commonwealth Edison Company and Subsidiary Companies
Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, unless otherwise noted)
The first step compares the fair value of the reporting unit to its carrying amount, including goodwill. If the carrying amount of the reporting unit exceeds its fair value, the second step is performed. The second step compares the carrying amount of the goodwill to the estimated fair value of the goodwill. If the fair value of goodwill is less than the carrying amount, an impairment loss is reported as a reduction to goodwill and a charge to operating expense.
ComEd performed its annual assessment of potential ComEd goodwill impairment for 2004 as of November 1, 2004, and determined that goodwill was not impaired. In its assessments to estimate the fair value of the ComEd reporting unit, ComEd used a probability-weighted, discounted cash flow model with multiple scenarios. The determination of the fair value is dependent on many sensitive, interrelated and uncertain variables including changing interest rates, utility sector market performance, ComEd’s capital structure, market prices for power, post-2006 rate regulatory structures, operating and capital expenditure requirements and other factors. Changes in these variables or in how they interrelate could result in future impairments of goodwill at ComEd, which could be material. The actual timing and amounts of goodwill impairments in future years, if any, will depend on the variables discussed above. Illinois legislation provides that reductions to ComEd’s common equity resulting from goodwill impairments will have no impact on the determination of the rate cap on ComEd’s allowed equity return during the electricity industry restructuring transition period through 2006.
6. Severance Accounting
ComEd provides severance and health and welfare benefits to terminated employees pursuant to pre-existing severance plans maintained by Exelon primarily based upon each individual employee’s years of service with ComEd and compensation level.
During the years ended December 31, 2004 and 2003, ComEd identified approximately 80 and 730 positions, respectively, for elimination. As of December 31, 2004, approximately 220 of the identified positions had not been eliminated. ComEd recorded charges for salary continuance severance of $10 million and $61 million (before income taxes) during 2004 and 2003, respectively, which represented salary continuance severance costs that were probable and could be reasonably estimated as of the end of the year. During 2004 and 2003, ComEd recorded a charge of $8 million and $28 million (before income taxes), respectively, associated with special health and welfare severance benefits. Additionally, ComEd incurred curtailment costs in 2004 and 2003 associated with its pension and postretirement benefit plans of $3 million and $48 million (before income taxes), respectively, as a result of personnel reductions. In total, ComEd recorded charges of $21 million and $137 million (before income taxes) in 2004 and 2003, respectively. See Note 11—Retirement Benefits for a description of the curtailment charges for the pension and postretirement benefit plans.
ComEd based its estimate of the number of positions to be eliminated on management’s current plans and its ability to determine the appropriate staffing levels to effectively operate the business. ComEd may incur further severance costs if additional positions are identified for elimination. These costs will be recorded in the period in which the costs can be reasonably estimated.
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Commonwealth Edison Company and Subsidiary Companies
Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, unless otherwise noted)
The following table details ComEd’s total salary continuance severance costs, recorded as an operating and maintenance expense, for the years ended December 31, 2004 and 2003. During 2002, no amounts were recorded as severance expense:
| Salary continuance severance charges |
|||
| Expense recorded - 2004 |
$ | 10 | |
| Expense recorded - 2003 |
61 | ||
| Expense recorded - 2002 |
— | ||
The following table provides a roll forward of ComEd’s salary continuance severance obligation from January 1, 2003 through December 31, 2004. The salary continuance severance obligation as of January 1, 2003 relates to severance associated with the merger of Exelon, Unicom Corporation and PECO on October 20, 2000 (PECO / Unicom Merger).
| Salary continuance severance obligation |
||||
| Balance as of January 1, 2003 |
$ | 15 | ||
| Severance charges recorded |
61 | |||
| Cash payments |
(21 | ) | ||
| Balance as of January 1, 2004 |
55 | |||
| Severance charges recorded |
10 | |||
| Merger severance adjustments |
(3 | ) | ||
| Cash payments |
(34 | ) | ||
| Balance as of December 31, 2004 |
$ | 28 | ||
7. Short-Term Debt
| 2004 |
2003 |
2002 |
||||||||||
| Average borrowings |
$ | 7 | $ | 4 | $ | 14 | ||||||
| Maximum borrowings outstanding |
180 | 123 | 146 | |||||||||
| Average interest rates, computed on a daily basis |
2.11 | % | 1.47 | % | 1.75 | % | ||||||
| Average interest rates, at December 31 |
— | — | 1.69 | % | ||||||||
At December 31, 2003, Exelon, along with ComEd, PECO Energy Company (PECO) and Generation, participated with a group of banks in a $750 million 364-day unsecured revolving credit agreement and a $750 million three-year unsecured revolving credit agreement. On July 16, 2004, the $750 million 364-day facility was replaced with a $1 billion unsecured revolving facility maturing on July 16, 2009 and the $750 million three-year facility was reduced to $500 million maturing on October 31, 2006. Both revolving credit agreements are used principally to support the commercial paper programs at Exelon, ComEd, PECO and Generation and to issue letters of credit.
At December 31, 2004, ComEd’s aggregate sublimit under the credit agreements was $100 million. Sublimits under the credit agreements can change upon written notification to the bank group. ComEd had approximately $74 million of unused bank commitments, net of outstanding letters of credit, under the credit agreements at December 31, 2004. ComEd did not have any commercial paper outstanding at December 31, 2004 or at December 31, 2003. Interest rates on advances under the
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Commonwealth Edison Company and Subsidiary Companies
Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, unless otherwise noted)
credit facilities are based on either prime or the London Interbank Offering Rate (LIBOR) plus an adder based on the credit rating of the borrower as well as the total outstanding amounts under the agreements at the time of borrowing. The maximum adder is 170 basis points.
The credit agreements require ComEd to maintain a minimum cash from operations to interest expense ratio for the twelve-month period ended on the last day of any quarter. The ratio excludes revenues and interest expenses attributable to securitization debt, certain changes in working capital and distributions on preferred securities of subsidiaries. For the twelve-month period ended December 31, 2004, ComEd’s minimum cash from operations to interest expense ratio was 2.25 to 1. At December 31, 2004, ComEd was in compliance with this threshold.
8. Long-Term Debt
| December 31, |
||||||||||||
| Rates |
Maturity Date |
2004 |
2003 |
|||||||||
| Long-term debt |
||||||||||||
| First Mortgage Bonds (a) (b): |
||||||||||||
| Fixed rates |
3.70%-9.875% | 2005-2033 | $ | 2,509 | $ | 3,311 | ||||||
| Floating rates |
1.75%-1.95% | 2013-2020 | 252 | 252 | ||||||||
| Notes payable |
||||||||||||
| Fixed rates |
6.40%-7.625% | 2005-2018 | 392 | 816 | ||||||||
| Sinking fund debentures |
3.875%-4.75% | 2005-2011 | 12 | 17 | ||||||||
| Total long-term debt (c) |
3,165 | 4,396 | ||||||||||
| Unamortized debt discount and premium, net |
(15 | ) | (26 | ) | ||||||||
| Unamortized settled fair value hedge |
14 | — | ||||||||||
| Fair-value hedge carrying value adjustment, net |
9 | 33 | ||||||||||
| Due within one year |
(272 | ) | (236 | ) | ||||||||
| Total long-term debt |
$ | 2,901 | $ | 4,167 | ||||||||
| Long-term debt to financing trusts (d) |
||||||||||||
| Subordinated debentures to ComEd Financing II (e) |
8.50% | 2027 | $ | 155 | $ | 155 | ||||||
| Subordinated debentures to ComEd Financing III (e) |
6.35% | 2033 | 206 | 206 | ||||||||
| Payable to ComEd Transitional Funding Trust (e) |
5.44%-5.74% | 2005-2008 | 1,341 | 1,676 | ||||||||
| Total long-term debt to affiliates (e) |
1,702 | 2,037 | ||||||||||
| Due within one year |
(321 | ) | (317 | ) | ||||||||
| Total long-term debt to financing trusts |
$ | 1,381 | $ | 1,720 | ||||||||
| (a) | Utility plant of ComEd is subject to the liens of its mortgage indenture. |
| (b) | Includes first mortgage bonds issued under ComEd’s mortgage indenture securing pollution control bonds. |
| (c) | Long-term debt maturities in the periods 2005 through 2009 and thereafter are as follows: |
| 2005 |
$ | 272 | |
| 2006 |
328 | ||
| 2007 |
147 | ||
| 2008 |
417 | ||
| 2009 |
17 | ||
| Thereafter |
1,984 | ||
| Total |
$ | 3,165 | |
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Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, unless otherwise noted)
| (d) | Effective December 31, 2003, ComEd Financing II, ComEd Financing III and ComEd Transitional Funding Trust were deconsolidated from the financial statements of ComEd in conjunction with the adoption of FIN 46-R. Amounts owed to these financing trusts are recorded as debt to financing trusts within the Consolidated Balance Sheets. |
| (e) | Long-term debt to financing trusts maturities in the periods 2005 through 2009 and thereafter are as follows: |
| 2005 |
$ | 321 | |
| 2006 |
340 | ||
| 2007 |
340 | ||
| 2008 |
340 | ||
| 2009 |
— | ||
| Thereafter |
361 | ||
| Total |
$ | 1,702 | |
Debt Issuances. During 2004, no long-term debt was issued at ComEd.
Debt Retirements and Redemptions. The following debt was retired, through tender, open market purchases, optional redemption or payment at maturity, during 2004:
| Type |
Interest Rate |
Maturity |
Amount | |||||
| Medium Term Notes |
9.200 | % | October 15, 2004 | $ | 56 | |||
| Notes |
6.400 | % | October 15, 2005 | 128 | ||||
| Notes |
6.950 | % | July 15, 2018 | 85 | ||||
| Notes |
7.375 | % | January 15, 2004 | 150 | ||||
| Notes |
7.625 | % | January 15, 2007 | 5 | ||||
| Pollution Control Revenue Bonds |
5.300 | % | January 15, 2004 | 26 | ||||
| Pollution Control Revenue Bonds |
5.700 | % | January 15, 2009 | 4 | ||||
| Pollution Control Revenue Bonds |
5.850 | % | January 15, 2014 | 3 | ||||
| Sinking Fund Debentures |
3.125 | % | October 1, 2004 | 2 | ||||
| Sinking Fund Debentures |
3.875 | % | January 1, 2008 | 1 | ||||
| Sinking Fund Debentures |
4.625 | % | January 1, 2009 | 1 | ||||
| Sinking Fund Debentures |
4.750 | % | December 1, 2011 | 1 | ||||
| First Mortgage Bonds |
3.700 | % | February 1, 2008 | 55 | ||||
| First Mortgage Bonds |
4.700 | % | April 15, 2015 | 135 | ||||
| First Mortgage Bonds |
4.740 | % | August 15, 2010 | 38 | ||||
| First Mortgage Bonds |
5.875 | % | February 1, 2033 | 96 | ||||
| First Mortgage Bonds |
6.150 | % | March 15, 2012 | 150 | ||||
| First Mortgage Bonds |
7.000 | % | July 1, 2005 | 62 | ||||
| First Mortgage Bonds |
7.500 | % | July 1, 2013 | 20 | ||||
| First Mortgage Bonds |
7.625 | % | April 15, 2013 | 94 | ||||
| First Mortgage Bonds |
8.000 | % | May 15, 2008 | 20 | ||||
| First Mortgage Bonds |
8.250 | % | October 1, 2006 | 5 | ||||
| First Mortgage Bonds |
8.375 | % | October 15, 2006 | 94 | ||||
| Total retirements and redemptions |
$ | 1,231 | ||||||
During 2004, ComEd made payments of $335 million related to its obligation to the ComEd Transitional Funding Trust.
During 2004, ComEd retired $1.2 billion of long-term debt, including $1.0 billion prior to its maturity and $206 million at maturity, pursuant to Exelon’s accelerated liability management plan. ComEd funded the retirements through cash from operations, a return of contributions to the intercompany money pool and collections on an intercompany note receivable from UII, LLC (formerly Unicom Investments, Inc.). ComEd recorded charges of $130 million (before income taxes) in 2004 associated
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Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, unless otherwise noted)
with the retirement of debt under the plan. The components of these charges included the following: $86 million of prepayment premiums; $12 million of net unamortized premiums, discounts and debt issuance costs; $24 million of losses on reacquired debt previously deferred as regulatory assets; and $12 million of settled cash-flow interest-rate swaps previously deferred as regulatory assets partially offset by $4 million of unamortized gain on settled fair value interest-rate swaps.
See Note 12—Fair Value of Financial Assets and Liabilities for additional information regarding interest-rate swaps. See Note 13—Preferred Securities of Subsidiaries for additional information regarding preferred stock.
9. Income Taxes
Income tax expense (benefit) is comprised of the following components:
| For the Year Ended December 31, |
||||||||||||
| 2004 |
2003 |
2002 |
||||||||||
| Included in operations: |
||||||||||||
| Federal |
||||||||||||
| Current |
$ | 231 | $ | 362 | $ | 308 | ||||||
| Deferred |
147 | 19 | 110 | |||||||||
| Investment tax credit, net |
(3 | ) | (3 | ) | (4 | ) | ||||||
| State |
||||||||||||
| Current |
73 | 96 | 80 | |||||||||
| Deferred |
9 | (9 | ) | 12 | ||||||||
| Total income tax expense |
$ | 457 | $ | 465 | $ | 506 | ||||||
The effective income tax rate varies from the U.S. Federal statutory rate principally due to the following:
| For the Year Ended | ||||||
| 2004 |
2003 |
2002 | ||||
| U.S. Federal statutory rate |
35.0% | 35.0% | 35.0% | |||
| Increase (decrease) due to: |
||||||
| State income taxes, net of Federal income tax benefit |
4.8 | 4.8 | 4.6 | |||
| Amortization of regulatory asset |
0.6 | 0.5 | 1.2 | |||
| Amortization of investment tax credit |
(0.3) | (0.3) | (0.3) | |||
| Nontaxable employee benefits |
(0.2) | — | — | |||
| Plant basis differences |
— | (0.2) | (1.3) | |||
| Other, net |
0.4 | — | (0.2) | |||
| Effective income tax rate |
40.3% | 39.8% | 39.0% | |||
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Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, unless otherwise noted)
The tax effect of temporary differences giving rise to significant portions of ComEd’s deferred tax assets and liabilities as of December 31, 2004 and 2003 are presented below:
| 2004 |
2003 |
|||||||
| Deferred tax liabilities: |
||||||||
| Plant basis difference |
$ | 1,921 | $ | 1,851 | ||||
| Deferred debt refinancing costs |
39 | 49 | ||||||
| Total deferred tax liabilities |
1,960 | 1,900 | ||||||
| Deferred tax assets: |
||||||||
| Deferred pension and postretirement obligations |
(30 | ) | (85 | ) | ||||
| Other, net (a) |
(25 | ) | (137 | ) | ||||
| Total deferred tax assets |
(55 | ) | (222 | ) | ||||
| Deferred income tax liabilities (net) |
$ | 1,905 | $ | 1,678 | ||||
| (a) | As of December 31, 2004 and 2003, includes $2 million of deferred income tax assets included in other noncurrent assets in ComEd’s Consolidated Balance Sheets. |
In accordance with regulatory treatment of certain temporary differences, ComEd recorded net regulatory asset and net regulatory liabilities associated with deferred income tax assets (liabilities), pursuant to SFAS No. 71 and SFAS No. 109, “Accounting for Income Taxes,” of $4 million and ($61) million at December 31, 2004 and 2003, respectively. See Note 16—Supplemental Financial Information for more information of regulatory liabilities associated with deferred income taxes.
ComEd has taken certain tax positions, which have been disclosed to the Internal Revenue Service (IRS), to defer the tax gain on the 1999 sale of its fossil generating assets. The majority of the deferred tax liabilities related to the fossil plant sale are reflected in ComEd’s Consolidated Balance Sheets with the remainder allocated to the Consolidated Balance Sheets of Generation in connection with Exelon’s 2001 corporate restructuring. The total 1999 income tax liability deferred as a result of these transactions was approximately $1.1 billion. As of December 31, 2004 and 2003, a deferred tax liability of approximately $944 million and $956 million, respectively, related to the fossil plant sale is reflected on ComEd’s Consolidated Balance Sheets. ComEd’s ability to continue to defer a portion of this liability depends on whether its treatment of a portion of the sales proceeds as having been received in connection with an involuntary conversion is proper pursuant to IRS regulations and interpretations. ComEd’s ability to continue to defer the remainder of this liability may depend in part on whether its tax characterization of a lease transaction it entered into in connection with the sale is proper pursuant to IRS regulations and interpretations. The IRS is likely to argue that the lease transaction is of a type it has recently announced its intention to challenge, and ComEd understands that somewhat similar transactions entered into by other companies have been the subject of review and challenge by the IRS. Changes in IRS interpretations of existing primary tax authority or challenges to ComEd’s positions could have the impact of accelerating future income tax payments and increasing interest expense related to the deferred tax gain that becomes current. ComEd’s management believes ComEd’s reserve for interest, which has been established in the event that such positions are not sustained, has been appropriately recorded in accordance with SFAS No. 5; however, the ultimate outcome of such matters could result in additional unfavorable or favorable adjustments to the results of operations, and such adjustments could be material. Federal tax returns covering the period of the 1999 sale are currently under IRS audit. Final resolution of this matter is not anticipated for several years.
267
Commonwealth Edison Company and Subsidiary Companies
Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, unless otherwise noted)
It is presently unclear the extent to which any IRS challenge to such deferral would be successful. If the deferral was successfully challenged by the IRS, it could have a material adverse impact on ComEd’s operating results.
Certain ComEd tax returns are under review at the audit or appeals level of the IRS and certain state authorities. Except for the tax positions discussed above, these reviews by governmental taxing authorities are not expected to have an adverse impact on the financial condition or result of operations at ComEd.
In 2004 and 2003, ComEd received $55 million and $86 million, respectively, from Exelon related to ComEd’s allocation of tax benefits under the Tax Sharing Agreement.
10. Nuclear Decommissioning
As a result of corporate restructuring in 2001, assets and liabilities associated with nuclear power plants previously owned by ComEd were transferred to Generation. Pursuant to the Nuclear Regulatory Commission regulations, Generation has an obligation to decommission these nuclear power plants. Based on the actual or anticipated extended license lives of the nuclear plants, expenditures are expected to occur primarily during the period 2029 through 2054 for plants currently in operation. Generation currently recovers costs for decommissioning nuclear generating stations, previously owned by ComEd, through regulated rates collected by ComEd. The amounts recovered from customers are deposited in trust accounts by Generation and invested for funding of future decommissioning costs of these nuclear generating stations.
SFAS No. 143, “Accounting for Asset Retirement Obligations” (SFAS No. 143) provides accounting requirements for retirement obligations (whether statutory, contractual or as a result of principles of promissory estoppel) associated with tangible long-lived assets. ComEd was required to adopt SFAS No. 143 as of January 1, 2003.
Generation was required to re-measure the decommissioning liabilities at fair value using the methodology prescribed by SFAS No. 143. The transition provisions of SFAS No. 143 required Exelon to apply this remeasurement back to the historical periods in which asset retirement obligations (ARO) were incurred, resulting in a remeasurement of these obligations at the date the related assets were acquired. Since the nuclear plants previously owned by ComEd were acquired by Exelon on October 20, 2000 (Merger Date) as a result of the PECO / Unicom Merger, Generation’s historical accounting for its ARO has been revised as if SFAS No. 143 had been in effect at the Merger Date.
For the former ComEd nuclear power plants, the calculation of the SFAS No. 143 ARO yielded decommissioning obligations lower than the value of the corresponding trust assets as of January 1, 2003. ComEd has previously collected amounts from customers (which were subsequently transferred to Generation) in advance of Generation’s recognition of decommissioning expense under SFAS No. 143. While it is expected that the trust assets will ultimately be used entirely for the decommissioning of the plants, the current measurement required by SFAS No. 143 results in an excess of assets over related ARO liabilities. As such, in accordance with regulatory accounting practices and a December 2000 ICC Order, amended February 2001 (ICC Order), which required any surplus funds after the nuclear stations are decommissioned to be refunded to ComEd customers, a regulatory liability of $948 million and a corresponding receivable from Generation were recorded at ComEd upon the adoption of SFAS No. 143. At December 31, 2004, this regulatory liability and corresponding receivable from
268
Commonwealth Edison Company and Subsidiary Companies
Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, unless otherwise noted)
Generation totaled $1,433 million. Generation and ComEd believe that all of the decommissioning assets, including prospective earnings thereon and up to $73 million of annual collections from ComEd ratepayers in 2005 and 2006, will be required to decommission the former ComEd plants. Because ComEd is not expected to take all of the output of these stations, actual collections are expected to be less than $73 million annually in 2005 and 2006. Subsequent to 2006, there will be no further recoveries of decommissioning costs from ComEd’s customers. ComEd expects the regulatory liability and corresponding receivable from Generation will be reduced to zero at or before the conclusion of the decommissioning of the former ComEd plants.
As discussed above, Generation re-measured the 2001 decommissioning-related balances associated with the PECO / Unicom Merger purchase price allocation at ComEd and a January 2001 corporate restructuring that transferred ComEd’s generation business to Generation as if SFAS No. 143 had been in effect at the Merger Date. Generation concluded that had SFAS No. 143 been in effect, ComEd would not have recorded an impairment of its regulatory asset for decommissioning of its retired nuclear plants as a purchase price allocation adjustment in 2001 as a result of the December 2000 ICC Order. Increased net assets would have been transferred to Generation by ComEd in the corporate restructuring. Accordingly, ComEd recorded a reduction of $210 million of goodwill and of shareholders’ equity. In addition, ComEd recorded a cumulative effect of a change in accounting principle of $5 million to reverse goodwill amortization that had been recorded in 2001. ComEd also reclassified a regulatory asset related to nuclear decommissioning costs for retired units of $248 million to regulatory liabilities.
11. Retirement Benefits
ComEd participates in defined benefit pension plans and postretirement welfare benefit plans sponsored by Exelon. Substantially all ComEd employees are eligible to participate in these plans. Benefits under these plans generally reflect each employee’s compensation, years of service, and age at retirement.
The prepaid pension asset and non-pension postretirement benefits obligation on ComEd’s Consolidated Balance Sheets reflect ComEd’s obligations from and to the plan sponsor, Exelon. Employee-related assets and liabilities, including both pension and SFAS No. 106, “Employers’ Accounting for Postretirement Benefits Other than Pensions,” postretirement welfare assets and liabilities, were allocated by Exelon to its subsidiaries based on the number of active employees as of January 1, 2001 as part of Exelon’s corporate restructuring. Exelon allocates the components of pension and postretirement expense to the participating employers based upon several factors, including the percentage of active employees in each participating unit.
See Note 15—Retirement Benefits of Exelon’s Notes to Consolidated Financial Statements for pension and other postretirement benefits information for the Exelon plans.
Approximately $86 million, $83 million and $14 million were included in capital and operating and maintenance expense, excluding curtailment and special termination benefit costs, in 2004, 2003 and 2002, respectively, for ComEd’s allocated portion of Exelon’s pension and postretirement benefit expense. The 2004 amounts include a reduction in net periodic post-retirement benefit cost resulting from the adoption of FSP FAS 106-2. ComEd contributed $244 million, $201 million and $89 million to the Exelon-sponsored plans in 2004, 2003 and 2002, respectively. ComEd expects to contribute approximately $800 million to the pension benefit plans in 2005.
269
Commonwealth Edison Company and Subsidiary Companies
Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, unless otherwise noted)
During 2004 and 2003, ComEd recognized curtailment charges of $3 million and $48 million (before income taxes), respectively, associated with an overall reduction in participants in Exelon’s pension and postretirement benefit plans due to employee reductions associated with The Exelon Way. During 2004 and 2003, ComEd recognized special termination benefit costs of $8 million and $28 million (before income taxes), respectively.
ComEd participates in a 401(k) savings plan sponsored by Exelon. The plan allows employees to contribute a portion of their pre-tax income in accordance with specified guidelines. ComEd matches a percentage of the employee contribution up to certain limits. The cost of ComEd’s matching contribution to the savings plan totaled $16 million in 2004 and $19 million in 2003 and 2002.
12. Fair Value of Financial Assets and Liabilities
The carrying amounts and fair values of ComEd’s financial instruments as of December 31, 2004 and 2003 were as follows:
| 2004 |
2003 | |||||||||||
| Carrying Amount |
Fair Value |
Carrying Amount |
Fair Value | |||||||||
| Non-derivatives: |
||||||||||||
| Assets |
||||||||||||
| Note receivable from affiliate (a) |
$ | — | $ | — | $ | 1,071 | $ | 1,077 | ||||
| Liabilities |
||||||||||||
| Long-term debt (including amounts due within one year) (b) |
3,173 | 3,363 | 4,403 | 4,735 | ||||||||
| Long-term debt to ComEd Transitional Trust (including amounts due within one year) (b) |
1,341 | 1,403 | 1,676 | 1,791 | ||||||||
| Long-term debt to other financing trusts (including amounts due within one year) (b) |
361 | 380 | 361 | 378 | ||||||||
| Derivatives: |
||||||||||||
| Fixed-to-floating interest-rate swaps |
$ | 9 | $ | 9 | $ | 33 | $ | 33 | ||||
| (a) | At December 31, 2003, ComEd had a $1,071 million note receivable from UII, LLC (formerly Unicom Investments Inc.) which bore interest at the one month forward LIBOR rate plus 50 basis points. The note was repaid in full in 2004. |
| (b) | Effective December 31, 2003, ComEd Financing II, ComEd Financing III and the ComEd Transitional Funding Trust were deconsolidated from the financial statements of ComEd in conjunction with the adoption of FIN 46-R. Amounts owed to these companies were recorded as long-term debt to financing trusts within the Consolidated Balance Sheets. |
Fair Value of Financial Instruments. As of December 31, 2004 and 2003, ComEd’s carrying amounts of cash and cash equivalents, accounts receivable, accounts payable and accrued liabilities are representative of fair value because of the short-term nature of these instruments. Fair value of the long-term debt is determined by an external valuation model which is based on conventional discounted cash flow methodology and utilizes assumptions of current market pricing curves. The fair value of ComEd’s interest-rate swaps is determined using external dealer prices or internal valuation models which utilize assumptions of available market pricing curves.
Interest-Rate Swaps. At December 31, 2004, ComEd has interest-rate swaps to effectively convert $240 million in fixed-rate debt to floating-rate debt. These swaps have been designated as fair-value hedges, as defined in SFAS No. 133 and, as such, changes in the fair value of the swaps will be recorded in earnings; however, as long as the hedge remains effective and the underlying transaction
270
Commonwealth Edison Company and Subsidiary Companies
Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, unless otherwise noted)
remains probable, changes in the fair value of the swaps will be offset by changes in the fair value of the hedged liabilities. Any change in the fair value of the hedge as a result of ineffectiveness would be recorded immediately in earnings. In 2004, ComEd settled certain interest-rate swaps designated as fair-value hedges in the aggregate amount of $485 million for total proceeds of approximately $32 million, which included the $26 million settlement amount and $6 million of accrued interest. The $26 million settlement amount will be amortized as a reduction to interest expense over the remaining life of the related debt.
During 2004 and 2003, no amounts were reclassified from accumulated other comprehensive income into earnings as a result of forecasted financing transactions no longer being probable.
Credit Risk Associated with Financial Instruments. Non-derivative financial instruments that potentially subject ComEd to concentrations of credit risk consist principally of cash equivalents and customer and affiliate accounts receivable. ComEd places its cash equivalents with high-credit quality financial institutions. Generally, such investments are in excess of the Federal Deposit Insurance Corporation limits. Concentrations of credit risk with respect to customer accounts receivable are limited due to ComEd’s large number of customers and their dispersion across many industries.
ComEd would also be exposed to credit-related losses in the event of non-performance by counterparties that issue derivative instruments. The credit exposure of derivative contracts is represented by the fair value of contracts at the reporting date. The notional amount of derivatives do not represent amounts that are exchanged by the parties and, thus, are not a measure of ComEd’s exposure. The amounts exchanged are calculated on the basis of the notional or contract amounts, as well as on the other terms of the derivatives, which relate to interest rates and the volatility of these rates.
13. Preferred Securities
Preferred and Preference Stock
At December 31, 2004 and 2003, there were 6,810,451 authorized shares of preference stock, cumulative, and 850,000 authorized shares of prior preferred stock, none of which was outstanding. Shares of preference stock have full voting rights, including the right to cumulate votes in the election of directors.
At December 31, 2004 and 2003, ComEd had the following non-cumulative preference stock:
| December 31, | ||||||||||
| 2004 |
2003 |
2004 |
2003 | |||||||
| Shares Outstanding |
Dollar Amount | |||||||||
| Without mandatory redemption |
||||||||||
| Preference stock, non-cumulative, without par value |
1,120 | 1,120 | $ | 7 | $ | 7 | ||||
| Total preferred and preference stock |
1,120 | 1,120 | $ | 7 | $ | 7 | ||||
271
Commonwealth Edison Company and Subsidiary Companies
Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, unless otherwise noted)
14. Common Stock
At December 31, 2004 and 2003, common stock with a $12.50 par value consisted of 250,000,000 and 250,000,000 shares authorized and 127,016,502 and 127,016,484 shares outstanding, respectively.
At December 31, 2004 and 2003, 75,927 and 76,068 warrants, respectively, were outstanding to purchase ComEd common stock. The warrants entitle the holders to convert such warrants into common stock of ComEd at a conversion rate of one share of common stock for three warrants. At December 31, 2004, 25,309 shares of common stock were reserved for the conversion of warrants.
Fund Transfer Restrictions
Under applicable Federal law, ComEd can pay dividends only from retained or current earnings. Under Illinois law, ComEd may not pay any dividend on its stock unless, among other things, “[its] earnings and earned surplus are sufficient to declare and pay same after provision is made for reasonable and proper reserves,” or unless it has specific authorization from the ICC. ComEd has also agreed in connection with financings arranged through ComEd Financing II and ComEd Financing III (the Financing Trusts) that it will not declare dividends on any shares of its capital stock in the event that: (1) it exercises its right to extend the interest payment periods on the subordinated debt securities that were issued to the Financing Trusts; (2) it defaults on its guarantee of the payment of distributions on the preferred trust securities of the Financing Trusts; or (3) an event of default occurs under the Indenture under which the subordinated debt securities are issued. At December 31, 2004, ComEd had retained earnings of $1,102 million (all of which had been appropriated for future dividend payments).
Undistributed Losses of Equity Method Investments
ComEd had undistributed losses of equity method investments of $21 million at December 31, 2004.
15. Commitments and Contingencies
Energy Commitments
In connection with the 2001 Exelon corporate restructuring, ComEd assigned its respective rights and obligations under various purchased power and fuel supply agreements to Generation. Additionally, ComEd entered into a PPA with Generation.
Under the PPA, as amended, between ComEd and Generation, Generation has agreed to supply all of ComEd’s load requirements through 2006. Prices for this energy vary depending upon the time of day and month of delivery. Subsequent to 2006, ComEd expects to procure all of its supply from market sources, which could include Generation.
272
Commonwealth Edison Company and Subsidiary Companies
Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, unless otherwise noted)
Commercial Commitments
ComEd’s commercial commitments as of December 31, 2004, representing commitments potentially triggered by future events, were as follows:
| Expiration within | |||||||||||||||
| Total |
2005 |
2006-2007 |
2008-2009 |
2010 and beyond | |||||||||||
| Letters of credit (non-debt) (a) |
$ | 28 | $ | 27 | $ | 1 | $ | — | $ | — | |||||
| Midwest Generation Capacity Reservation Agreement guarantee (b) |
29 | 4 | 7 | 8 | 10 | ||||||||||
| Surety bonds (c) |
2 | 2 | — | — | — | ||||||||||
| Total commercial commitments |
$ | 59 | $ | 33 | $ | 8 | $ | 8 | $ | 10 | |||||
| (a) | Letters of credit (non-debt)—ComEd maintains non-debt letters of credit to provide credit support for certain transactions as requested by third parties. |
| (b) | Midwest Generation Capacity Reservation Agreement guarantee—In connection with ComEd’s agreement with Chicago entered into on February 20, 2003, Midwest Generation assumed from Chicago a Capacity Reservation Agreement that Chicago had entered into with Calumet Energy Team, LLC. ComEd has agreed to reimburse Chicago for any nonperformance by Midwest Generation under the Capacity Reservation Agreement. Under FIN 45, “Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness to Others” (FIN 45), $3 million is included as a liability on ComEd’s Consolidated Balance Sheets at December 31, 2004. |
| (c) | Surety bonds—Guarantees issued related to contract and commercial surety bonds, excluding bid bonds. |
Environmental Issues
ComEd’s operations have in the past and may in the future require substantial expenditures in order to comply with environmental laws. Additionally, under Federal and state environmental laws, ComEd is generally liable for the costs of remediating environmental contamination of property now or formerly owned by ComEd and of property contaminated by hazardous substances generated by ComEd. ComEd owns or leases a number of real estate parcels, including parcels on which its operations or the operations of others may have resulted in contamination by substances which are considered hazardous under environmental laws. ComEd has identified 42 sites where former manufactured gas plant (MGP) activities have or may have resulted in actual site contamination. Of these 42 sites, the Illinois Environmental Protection Agency has approved the clean-up of four sites. ComEd is currently involved in a number of proceedings relating to sites where hazardous substances have been deposited and may be subject to additional proceedings in the future.
As of December 31, 2004 and 2003, ComEd had accrued $61 million and $69 million, respectively, for environmental investigation and remediation costs, including $55 million and $64 million, respectively (reflecting a discount rate of 4.25% and 5.0% in 2004 and 2003, respectively) for investigation and remediation at its 38 MGP sites, that currently can be reasonably estimated. Such estimates, reflecting the effects of a 2.25% and 2.5% inflation rate in 2004 and 2003, respectively, before the effects of discounting were $60 million and $94 million at December 31, 2004 and 2003, respectively. ComEd cannot reasonably estimate whether it will incur other significant liabilities for additional investigation and remediation costs at these or additional sites identified by ComEd, environmental agencies or others, or whether such costs will be recoverable from third parties.
273
Commonwealth Edison Company and Subsidiary Companies
Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, unless otherwise noted)
As of December 31, 2004, ComEd anticipates that payments related to the discounted environmental investigation and remediation costs, disclosed below on an undiscounted basis, will be:
| 2005 |
$ | 8 | |
| 2006 |
12 | ||
| 2007 |
14 | ||
| 2008 |
8 | ||
| 2009 |
5 | ||
| Remaining years |
13 | ||
| Total payments |
$ | 60 | |
Leases
Minimum future operating lease payments, including lease payments for real estate and vehicles, as of December 31, 2004 were:
| 2005 |
$ | 20 | |
| 2006 |
19 | ||
| 2007 |
18 | ||
| 2008 |
17 | ||
| 2009 |
15 | ||
| Remaining years |
76 | ||
| Total minimum future lease payments |
$ | 165 | |
Rental expense under operating leases totaled $22 million, $17 million and $26 million in 2004, 2003 and 2002, respectively.
Litigation
Retail Rate Law. In 1996, several developers of non-utility generating facilities filed litigation against various Illinois officials claiming that the enforcement against those facilities of an amendment to Illinois law removing the entitlement of those facilities to state-subsidized payments for electricity sold to ComEd after March 15, 1996 violated their rights under the Federal and state constitutions. The developers also filed suit against ComEd for a declaratory judgment that their rights under their contracts with ComEd were not affected by the amendment and for breach of contract. On November 25, 2002, the court granted the developers’ motions for summary judgment. The judge also entered a permanent injunction enjoining ComEd from refusing to pay the retail rate on the grounds of the amendment and Illinois from denying ComEd a tax credit on account of such purchases. On March 9, 2004, the Illinois Appellate Court reversed the trial court. The Appellate Court held that the 1996 law does apply to the developers’ facilities and, therefore, they are not entitled to subsidized payments. The Court expressly ruled that the breach of contract claims against ComEd are dismissed with prejudice. Two of the developers sought review of the Appellate Court’s decision by the Illinois Supreme Court. On May 26, 2004, the Supreme Court declined to hear the earlier-filed of the two appeals. On October 6, 2004, the Supreme Court declined to hear the final appeal. The time for future appeals has now passed. Related claims remain pending in the trial court.
General. ComEd is involved in various other litigation matters that are being defended and handled in the ordinary course of business, and ComEd maintains accruals for such costs that are probable of being incurred and subject to reasonable estimation. The ultimate outcome of such matters, as well as the matters discussed above, are uncertain and may have a material adverse effect on ComEd’s financial condition, results of operations, or cash flows.
274
Commonwealth Edison Company and Subsidiary Companies
Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, unless otherwise noted)
Capital Commitments
ComEd estimates that it will spend approximately $742 million for capital expenditures in 2005.
Income Tax Refund Claims
ComEd has entered into several agreements with a tax consultant related to the filing of refund claims with the IRS. ComEd previously made refundable prepayments to the tax consultant of $11 million. The fees for these agreements are contingent upon a successful outcome of the claims and are based upon a percentage of the refunds recovered from the IRS, if any. The ultimate net cash outflow from ComEd related to all the agreements will either be positive or neutral depending upon the outcome of the refund claim with the IRS. These potential tax benefits and associated fees could be material to the financial position, results of operations and cash flows of ComEd. A portion of ComEd’s tax benefits, including any associated interest for periods prior to the PECO / Unicom Merger, would be recorded as a reduction of goodwill pursuant to a reallocation of the PECO / Unicom Merger purchase price.
In 2004, the IRS granted preliminary approval for one of ComEd’s refund claims. As such, ComEd believes that it is probable that a fee will ultimately be paid to the tax consultant. Therefore, ComEd recorded an expense of $5 million (pre-tax), which resulted in a decrease to the prepayment from $11 million to $6 million. The charge represents an estimate of the fee to the tax consultant which may be adjusted upward or downward depending on the IRS’ final calculation of the tax and interest benefit. As of December 31, 2004, ComEd had not reflected the tax benefit associated with the refund claims pending final approval of the IRS. However, as described above, the net income statement impact for ComEd is anticipated to be neutral or positive.
See Note 19—Subsequent Events for information regarding the final approval of the refund claim.
16. Supplemental Financial Information
Supplemental Income Statement Information
| For the Years Ended December 31, | |||||||||
| 2004 |
2003 |
2002 | |||||||
| Depreciation and amortization |
|||||||||
| Property, plant and equipment (a) |
$ | 366 | $ | 342 | $ | 358 | |||
| Regulatory assets |
44 | 44 | 164 | ||||||
| Total depreciation and amortization |
$ | 410 | $ | 386 | $ | 522 | |||
| (a) | Includes amortization of capitalized software costs. |
| For the Years Ended December 31, | ||||||||||
| 2004 |
2003 |
2002 | ||||||||
| Taxes other than income |
||||||||||
| Utility (a) |
$ | 234 | $ | 233 | $ | 232 | ||||
| Real estate |
29 | 29 | 20 | |||||||
| Payroll |
21 | 24 | 28 | |||||||
| Other |
7 | (19 | )(b) | 7 | ||||||
| Total |
$ | 291 | $ | 267 | $ | 287 | ||||
| (a) | Municipal and state utility taxes are also recorded in revenues on ComEd’s Consolidated Statements of Income. |
| (b) | Includes a credit of $25 million in 2003 due to a favorable settlement of coal use tax issues at ComEd related to periods prior to the PECO / Unicom Merger. |
275
Commonwealth Edison Company and Subsidiary Companies
Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, unless otherwise noted)
| For the Years Ended December 31, |
|||||||||||
| 2004 |
2003 |
2002 |
|||||||||
| Other, net |
|||||||||||
| Investment income |
$ | 3 | $ | 4 | $ | 11 | |||||
| Gain on disposition of assets, net |
3 | 4 | — | ||||||||
| AFUDC |
3 | 9 | 18 | (a) | |||||||
| Reserve for potential plant disallowance |
— | 12 | (12 | ) | |||||||
| Other income (expense) |
5 | (5 | ) | (4 | ) | ||||||
| Total |
$ | 14 | $ | 24 | $ | 13 | |||||
| (a) | In 2002, the debt portion of AFUDC of $8 million was recorded as a non-cash credit to other, net. Subsequent to 2002, the debt portion of AFUDC was recorded as a non-cash credit to interest expense. |
Supplemental Cash Flow Information
| For the Years Ended December 31, | |||||||||
| 2004 |
2003 |
2002 | |||||||
| Cash paid during the year |
|||||||||
| Interest (net of amount capitalized) |
$ | 357 | $ | 352 | $ | 417 | |||
| Income taxes (net of refunds) |
356 | 579 | 264 | ||||||
| Non-cash investing and financing |
|||||||||
| Resolution of certain tax matters and Merger severance adjustments |
$ | 14 | $ | 8 | $ | 14 | |||
| Retirement of treasury shares |
— | — | 1,344 | ||||||
| Adoption of SFAS No. 143—adjustment to other paid in capital and goodwill |
— | 210 | — | ||||||
Supplemental Balance Sheet Information
| December 31, |
||||||||
| 2004 |
2003 |
|||||||
| Regulatory assets (liabilities) |
||||||||
| Nuclear decommissioning |
$ | (1,433 | ) | $ | (1,183 | ) | ||
| Removal costs |
(1,011 | ) | (973 | ) | ||||
| Recoverable transition costs |
87 | 131 | ||||||
| Reacquired debt costs and interest-rate swap settlements |
118 | 172 | ||||||
| Deferred income taxes |
4 | (61 | ) | |||||
| Other |
31 | 23 | ||||||
| Total |
$ | (2,204 | ) | $ | (1,891 | ) | ||
Nuclear decommissioning. Generation is responsible for decommissioning the nuclear plants formerly owned by ComEd. These amounts represent future nuclear decommissioning costs that exceed (regulatory asset) or are less than (regulatory liability) the associated decommissioning trust fund assets. Generation and ComEd believe the trust fund assets, including prospective earnings thereon and any future collections from ratepayers, will equal the associated future decommissioning costs at the time of decommissioning. See Note 10—Nuclear Decommissioning.
276
Commonwealth Edison Company and Subsidiary Companies
Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, unless otherwise noted)
Removal costs. These amounts represent funds received from ratepayers to cover the future removal of property, plant and equipment. See Note 4—Property, Plant and Equipment for further information.
Recoverable transition costs. These charges, related to amounts that would have been unrecoverable but for the recovery mechanisms, such as the CTC allowed under the Illinois restructuring act, are amortized based on the expected return on equity of ComEd in any given year. ComEd expects to fully recover and amortize these charges by the end of 2006, but may increase or decrease its annual amortization to maintain its earnings within the earnings cap provisions established by Illinois legislation. See Note 2—Regulatory Issues for discussion of recoverable transition cost amortization.
Reacquired debt costs and interest-rate swap settlements. The reacquired debt costs represent premiums paid for the early extinguishment and refinancing of long-term debt, which are amortized over the life of the new debt issued to finance the debt redemption. Interest-rate swap settlements are deferred and amortized over the period that the related debt is outstanding.
Deferred income taxes. These costs represent the difference between the method by which the regulator allows for the recovery of income taxes and how income taxes would be recorded by unregulated entities. Regulatory assets and liabilities associated with deferred income taxes, recorded in compliance with SFAS No. 71 and SFAS No. 109, include the deferred tax effects associated principally with excess deferred taxes, asset basis differences caused by the equity portion of AFUDC and unamortized investment tax credits accounted for in accordance with the rate-making policies of the ICC, as well as the revenue impacts thereon, and assume continued recovery or settlement of these costs in future rates. See Note 9—Income Taxes.
Recovery of regulatory assets. The regulatory assets for reacquired debt costs and interest-rate swap settlements relate to ComEd’s transmission and distribution business which is subject to cost-based rate regulation. Therefore, they are earning a rate of return. The regulatory assets for recoverable transition costs represent costs which are recoverable through regulated cash flows. ComEd has performed projections to determine if the revenue streams provided through these regulated cash flows are sufficient to provide for recovery of its regulatory assets during the rate-freeze period and concluded that cash flows were sufficient to provide recovery of its operating costs and net assets, including recovery of regulatory assets and a reasonable regulated rate of return on its net assets. Further, the Illinois Restructuring Act provides for an earnings floor and ceiling, such that if ComEd’s earned rate of return falls below a specified floor, ComEd may request a rate increase and, conversely, if its earnings exceed an established threshold, so-called excess earnings must be shared with ratepayers.
| December 31, | ||||||
| 2004 |
2003 | |||||
| Accrued expenses |
||||||
| Taxes accrued |
$ | 265 | $ | 179 | ||
| Interest accrued |
194 | 213 | ||||
| Other accrued expenses |
130 | 148 | ||||
| Total |
$ | 589 | $ | 540 | ||
277
Commonwealth Edison Company and Subsidiary Companies
Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, unless otherwise noted)
| December 31, |
||||||||
| 2004 |
2003 |
|||||||
| Accumulated other comprehensive loss |
||||||||
| Foreign currency translation adjustment |
$ | 2 | $ | 2 | ||||
| Unrealized loss on marketable securities |
(2 | ) | (3 | ) | ||||
| Total accumulated other comprehensive loss |
$ | — | $ | (1 | ) | |||
17. Related-Party Transactions
Effective December 31, 2003, ComEd Financing II, ComEd Financing III, ComEd Funding and the ComEd Transitional Funding Trust were deconsolidated from the financial statements of ComEd in conjunction with the adoption of FIN 46-R. Prior periods were not restated.
ComEd’s financial statements include related-party transactions with its unconsolidated subsidiaries as reflected in the table below.
| For the Years Ended December 31, | ||||||||||
| 2004 |
2003 |
2002 | ||||||||
| Operating revenues from affiliates |
||||||||||
| ComEd Transitional Funding Trust |
$ | 3 | $ | — | $ | — | ||||
| Interest expense to affiliates |
||||||||||
| ComEd Transitional Funding Trust |
85 | — | — | |||||||
| ComEd Financing II |
13 | — | — | |||||||
| ComEd Financing III |
13 | — | — | |||||||
| Equity in earnings (losses) from unconsolidated affiliates |
||||||||||
| ComEd Funding LLC |
(20 | ) | — | — | ||||||
| ComEd Financing III |
1 | — | — | |||||||
| December 31, | ||||||
| 2004 |
2003 | |||||
| Receivables from affiliates (current) |
||||||
| ComEd Transitional Funding Trust |
$ | 9 | $ | 9 | ||
| Investment in subsidiaries |
||||||
| ComEd Transitional Funding LLC |
36 | 56 | ||||
| ComEd Financing II |
10 | 11 | ||||
| ComEd Financing III |
6 | 6 | ||||
| Receivable from affiliates (noncurrent) |
||||||
| ComEd Transitional Funding Trust |
10 | 9 | ||||
| Payables to affiliates (current) |
||||||
| ComEd Financing II |
6 | 6 | ||||
| ComEd Financing III |
4 | 4 | ||||
| Long-term debt to financing trusts (including due within one year) |
||||||
| ComEd Transitional Funding Trust |
1,341 | 1,676 | ||||
| ComEd Financing II |
155 | 155 | ||||
| ComEd Financing III |
206 | 206 | ||||
278
Commonwealth Edison Company and Subsidiary Companies
Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, unless otherwise noted)
In addition to the transactions described above, ComEd’s financial statements include related-party transactions as reflected in the tables below.
| For the Years Ended December 31, | ||||||||||
| 2004 |
2003 |
2002 | ||||||||
| Operating revenues from affiliates |
||||||||||
| Generation (a) |
$ | 17 | $ | 50 | $ | 51 | ||||
| Enterprises (a) |
1 | 15 | 12 | |||||||
| Purchased power from affiliate |
||||||||||
| PPA with Generation (b) |
2,374 | 2,479 | 2,559 | |||||||
| Operations & maintenance from (to) affiliates |
||||||||||
| BSC (c) |
192 | 102 | 124 | |||||||
| Enterprises (d, e) |
— | 26 | 12 | |||||||
| PECO(f) |
— | (5 | ) | — | ||||||
| Interest income from affiliates |
||||||||||
| UII (g) |
16 | 21 | 30 | |||||||
| Exelon intercompany money pool (h) |
3 | 2 | — | |||||||
| Other |
1 | 2 | 1 | |||||||
| Interest expense to affiliates |
||||||||||
| Generation (b) |
— | — | 4 | |||||||
| Capitalized costs |
||||||||||
| BSC (c) |
62 | 18 | 9 | |||||||
| Enterprises (e) |
— | 21 | 21 | |||||||
| Cash dividends paid to parent |
457 | 401 | 470 | |||||||
279
Commonwealth Edison Company and Subsidiary Companies
Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, unless otherwise noted)
| December 31, | ||||||
| 2004 |
2003 | |||||
| Receivables from affiliates (current) |
||||||
| UII (g) |
$ | – | $ | 3 | ||
| PECO (f) |
– | 6 | ||||
| Exelon intercompany money pool (h) |
308 | 405 | ||||
| Other |
1 | 5 | ||||
| Receivables from affiliates (noncurrent) |
||||||
| UII (g) |
– | 1,071 | ||||
| Generation (i) |
1,433 | 1,183 | ||||
| Other |
– | 8 | ||||
| Payables to affiliates (current) |
||||||
| Generation decommissioning (j) |
11 | 11 | ||||
| Generation (a, b) |
189 | 171 | ||||
| BSC (c) |
17 | 13 | ||||
| Other |
– | 2 | ||||
| Payables to affiliates (noncurrent) |
||||||
| Generation decommissioning (j) |
11 | 22 | ||||
| Other |
6 | 6 | ||||
| Shareholders’ equity—receivable from parent (k) |
125 | 250 | ||||
| (a) | ComEd provides retail electric and ancillary services to Generation. ComEd provided electric and ancillary services to certain Exelon Enterprises Company, LLC (Enterprises) companies which were sold in 2004. Prior to joining PJM on May 1, 2004, ComEd also provided transmission services to Generation and Enterprises. |
| (b) | Effective January 1, 2001, ComEd entered into a full-requirements PPA, as amended, with Generation. See Note 15—Commitments and Contingencies for further information regarding the PPA. |
| (c) | ComEd receives a variety of corporate support services from Exelon Business Services Company (BSC), including legal, human resources, financial, information technology and supply management services. Additionally in 2004, due to the centralization of certain functions, certain employees were transferred from ComEd to BSC. As a result, ComEd now receives additional services from BSC including planning and engineering of delivery systems, management of construction, maintenance and operations of the transmission and delivery systems and management of other support services. All services are provided at cost, including application overhead. A portion of such services is capitalized. |
| (d) | ComEd had contracted with a subsidiary of Exelon Services (an Enterprises company) to provide energy conservation services to ComEd customers. The subsidiary was sold by Exelon in 2004. |
| (e) | ComEd receives substation and transmission engineering and construction services under contracts with InfraSource. A portion of such services is capitalized. Exelon sold InfraSource in September 2003. |
| (f) | In 2003, ComEd provided hurricane restoration assistance to PECO. |
| (g) | ComEd had a note and interest receivable with a variable rate of the one month forward LIBOR rate plus 50 basis points from UII relating to the December 1999 fossil plant sale. This note was paid in full during 2004. |
| (h) | ComEd participates in Exelon’s intercompany money pool. ComEd earns interest on its contributions to the money pool and pays interest on its borrowings from the money pool at a market rate of interest. |
| (i) | ComEd has a long-term receivable from Generation as a result of the nuclear decommissioning contractual construct whereby, to the extent the assets associated with decommissioning are greater than the applicable ARO, such amounts are due back to ComEd for payment to the ratepayers. For further information see Note 10—Nuclear Decommissioning. |
| (j) | ComEd has a short-term and long-term payable to Generation, primarily representing ComEd’s legal requirements to remit collections of nuclear decommissioning costs from customers to Generation. |
| (k) | ComEd has a non-interest bearing receivable from Exelon related to a corporate restructuring in 2001. The receivable is expected to be settled in 2005 or 2006. |
280
Commonwealth Edison Company and Subsidiary Companies
Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, unless otherwise noted)
18. Quarterly Data (Unaudited)
The data shown below include all adjustments which ComEd considers necessary for a fair presentation of such amounts:
| Operating Revenues |
Operating Income |
Income Before Cumulative Effect Of a Change in Accounting Principle |
Net Income | |||||||||||||||||||||
| 2004 |
2003 |
2004 |
2003 |
2004 |
2003 |
2004 |
2003 | |||||||||||||||||
| Quarter ended: |
||||||||||||||||||||||||
| March 31 (a) |
$ | 1,336 | $ | 1,424 | $ | 407 | $ | 411 | $ | 184 | $ | 190 | $ | 184 | $ | 195 | ||||||||
| June 30 |
1,403 | 1,361 | 431 | 443 | 204 | 205 | 204 | 205 | ||||||||||||||||
| September 30 |
1,720 | 1,737 | 410 | 363 | 124 | 163 | 124 | 163 | ||||||||||||||||
| December 31 |
1,344 | 1,292 | 369 | 350 | 164 | 144 | 164 | 144 | ||||||||||||||||
| (a) | Operating income, income before cumulative effect of a change in accounting principle and net income for the three months ended March 31, 2004 have been adjusted to reflect a reduction in net periodic postretirement benefit cost of $2 million due to the adoption of FSP FAS 106-2. See Note 1—Significant Accounting Policies for additional information. |
19. Subsequent Events
In the first quarter 2005, ComEd received final approval of the income tax refund described in Note 15—Commitments and Contingencies; however the calculation of the claim, including interest has not been finalized. As a portion of the refund will be recorded against goodwill under the provisions of EITF Issue No. 93-7, “Uncertainties Related to Income Taxes in a Purchase Business Combination,” the net result is not anticipated to have a material impact on ComEd’s results of operations.
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| ITEM 7. | MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATION |
Executive Overview
Financial Results. PECO’s net income on common stock decreased 3% in 2004 primarily due to a 4% decrease in operating income. The decrease in operating income reflects higher taxes other than income, due primarily to the reduction of real estate tax accruals in 2003, and higher depreciation and amortization expense due to increased CTC amortization. Partially offsetting these unfavorable factors on operating income were slightly higher operating revenues net of purchased power and fuel and lower operating and maintenance expense.
Investment Strategy. PECO continued to invest in its infrastructure, spending approximately $225 million in 2004, and expects to invest over $280 million in 2005.
Financing Activities. PECO met its capital resource commitments with internally generated cash. When necessary, PECO obtains funds from external sources, including the capital markets, the intercompany money pool and through bank borrowings. During 2004, PECO refinanced $75 million of First Mortgage Bonds, retired $157 million of Pollution Control Revenue Refunding Bonds, made scheduled repayments of $393 million on its long-term debt to PETT, and repaid $46 million of commercial paper.
Regulatory Developments. Through and Out Rates. In November 2004, the FERC issued two orders authorizing PECO to recover from various entities revenue representing amounts PECO will lose as a result of the elimination of through and out (T&O) charges, for energy flowing across PECO’s transmission system, that were terminated pursuant to the FERC orders effective December 1, 2004. The collection of this revenue will be over a transitional period of December 1, 2004 through March 31, 2006. Several parties have sought rehearing of the FERC orders and there likely will be appeals filed in the matter after the rehearing order is issued. During 2004 prior to the termination of T&O charges, PECO collected net T&O charges of approximately $3 million. As a result of this proceeding, PECO may be come a net payer of these charges. The ultimate outcome of this proceeding is uncertain and may have a material adverse effect on PECO’s financial condition, results of operations or cash flows.
Rate Design Proceeding. Certain PJM transmission owners, including PECO, are subject to a rate design proceeding before the FERC. The issues in this proceeding involve the methodology used by PJM to charge customers for each PJM transmission owner’s regulated revenue requirement associated with its electric transmission facilities. On January 31, 2005, certain PJM transmission owners, including PECO, made two separate filings in which the transmission owners jointly proposed to retain the present modified zonal rate design applicable within PJM and to implement three separate rate options for recovery of the revenue requirement associated with their new and existing facilities. As part of the group of PJM transmission owners, PECO proposed to retain the present rate design through January 2008, at which time the FERC could reevaluate the continuation of the rate design in PJM. The ultimate outcome of this proceeding is uncertain and may have a material adverse effect on PECO’s financial condition, results of operations or cash flows.
Regulatory Outlook. Restructuring in the U.S. electric industry is at a crossroads at both the Federal and state levels, with continuing debate at the FERC on regional transmission organizations (RTOs) and standard market platform issues and in many states on the “post-transition” format. Some states abandoned failed transition plans (e.g. California), some states are adjusting or have adjusted current transition plans (e.g. Ohio), and the Commonwealth of Pennsylvania (by 2011) is considering options to preserve choice for large customers and rate stability for mass market customers, while ensuring the financial returns needed for continuing investments in reliability. PECO will continue to be an active participant in these policy debates, while continuing to focus on improving operations and controlling costs.
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As PECO looks toward the end of the restructuring transition period for which its transmission and distribution rates are capped in Pennsylvania (2006), PECO will also continue to work with Federal and state regulators, state and local governments, customer representatives and other interested parties to develop appropriate processes for establishing future rates in restructured electricity markets. PECO will strive to ensure that future rate structures recognize the substantial improvements PECO has made, and will continue to make, in its transmission and distribution systems. PECO will also work to ensure that its rates are adequate to cover its costs of obtaining electric power and energy from its suppliers, which could include Generation, for the costs associated with procuring full requirements power given PECO’s Provider of Last Resort (POLR) obligations. As in the past, by working together with all interested parties, PECO believes it can successfully meet these objectives and obtain fair recovery of its costs for providing service to its customers; however, if PECO is unsuccessful, its results of operations and cash flows could be negatively affected after the transition period.
Outlook for 2005 and Beyond. On December 20, 2004, Exelon entered into a merger agreement with PSEG, a holding company for an electric and gas utility company primarily located and serving customers in New Jersey. The transaction, which has been unanimously approved by the Boards of Directors of both companies, is expected to close in the first quarter of 2006. However, the transaction is contingent upon, among other things, the approval by shareholders of PSEG of the merger and shareholders of Exelon of the shares to be issued in the merger, antitrust clearance and a number of regulatory approvals and reviews. Exelon and PECO are in the process of evaluating the impacts of the merger.
PECO’s financial results will be affected by a number of factors, including weather conditions and successful implementation of operational improvement initiatives. If weather is warmer than normal in the summer months or colder than normal in the winter months, operating revenues at PECO generally will be favorably affected.
While the U.S. economic recovery appears underway, PECO’s current plan is based on moderate sales growth (between 1% and 2% for electric and gas). Continued implementation of cost reduction initiatives is needed to offset labor and material cost escalation, especially the double digit increases in health care costs. PECO’s stable base of 1.5 million electric and 460,000 gas customers will provide a solid platform with which to meet these challenges.
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Results of Operations
Year Ended December 31, 2004 Compared To Year Ended December 31, 2003
| 2004 |
2003 |
Favorable (unfavorable) variance |
||||||||||
| OPERATING REVENUES |
$ | 4,487 | $ | 4,388 | $ | 99 | ||||||
| OPERATING EXPENSES |
||||||||||||
| Purchased power |
1,644 | 1,677 | 33 | |||||||||
| Fuel |
528 | 419 | (109 | ) | ||||||||
| Operating and maintenance |
547 | 576 | 29 | |||||||||
| Depreciation and amortization |
518 | 487 | (31 | ) | ||||||||
| Taxes other than income |
236 | 173 | (63 | ) | ||||||||
| Total operating expense |
3,473 | 3,332 | (141 | ) | ||||||||
| OPERATING INCOME |
1,014 | 1,056 | (42 | ) | ||||||||
| OTHER INCOME AND DEDUCTIONS |
||||||||||||
| Interest expense |
(303 | ) | (324 | ) | 21 | |||||||
| Distributions on mandatorily redeemable preferred securities |
— | (8 | ) | 8 | ||||||||
| Equity in losses of unconsolidated affiliates |
(25 | ) | — | (25 | ) | |||||||
| Other, net |
18 | 2 | 16 | |||||||||
| Total other income and deductions |
(310 | ) | (330 | ) | 20 | |||||||
| INCOME BEFORE INCOME TAXES |
704 | 726 | (22 | ) | ||||||||
| INCOME TAXES |
249 | 253 | 4 | |||||||||
| NET INCOME |
455 | 473 | (18 | ) | ||||||||
| Preferred stock dividends |
3 | 5 | 2 | |||||||||
| NET INCOME ON COMMON STOCK |
$ | 452 | $ | 468 | $ | (16 | ) | |||||
Net Income on Common Stock
PECO’s net income on common stock decreased 3% in 2004 primarily due to a 4% decrease in operating income. The decrease in operating income reflects higher taxes other than income, due primarily to the reduction of real estate tax accruals in 2003, and higher depreciation and amortization expense due to increased CTC amortization. Partially offsetting these unfavorable factors on operating income were slightly higher operating revenues net of purchased power and fuel and lower operating and maintenance expense.
284
Operating Revenue
PECO’s electric sales statistics and revenue detail are as follows:
| Retail Deliveries—(in GWhs) |
2004 |
2003 |
Variance |
% Change |
||||||
| Full service (a) |
||||||||||
| Residential |
10,349 | 11,358 | (1,009 | ) | (8.9 | %) | ||||
| Small commercial & industrial |
6,728 | 6,624 | 104 | 1.6 | % | |||||
| Large commercial & industrial |
14,908 | 14,739 | 169 | 1.1 | % | |||||
| Public authorities & electric railroads |
914 | 897 | 17 | 1.9 | % | |||||
| 32,899 | 33,618 | (719 | ) | (2.1 | %) | |||||
| Delivery only (b) |
||||||||||
| Residential |
2,158 | 900 | 1,258 | 139.8 | % | |||||
| Small commercial & industrial |
1,687 | 1,455 | 232 | 15.9 | % | |||||
| Large commercial & industrial |
760 | 780 | (20 | ) | (2.6 | %) | ||||
| 4,605 | 3,135 | 1,470 | 46.9 | % | ||||||
| Total retail deliveries |
37,504 | 36,753 | 751 | 2.0 | % | |||||
| (a) | Full service reflects deliveries to customers taking electric service under tariffed rates. |
| (b) | Delivery only service reflects customers receiving electric generation service from an alternative electric supplier. |
| Electric Revenue |
2004 |
2003 |
Variance |
% Change |
|||||||||
| Full service (a) |
|||||||||||||
| Residential |
$ | 1,317 | $ | 1,444 | $ | (127 | ) | (8.8 | %) | ||||
| Small commercial & industrial |
756 | 753 | 3 | 0.4 | % | ||||||||
| Large commercial & industrial |
1,113 | 1,090 | 23 | 2.1 | % | ||||||||
| Public authorities & electric railroads |
80 | 80 | — | — | |||||||||
| 3,266 | 3,367 | (101 | ) | (3.0 | %) | ||||||||
| Delivery only (b) |
|||||||||||||
| Residential |
164 | 65 | 99 | 152.3 | % | ||||||||
| Small commercial & industrial |
86 | 75 | 11 | 14.7 | % | ||||||||
| Large commercial & industrial |
20 | 21 | (1 | ) | (4.8 | %) | |||||||
| 270 | 161 | 109 | 67.7 | % | |||||||||
| Total electric retail revenues |
3,536 | 3,528 | 8 | 0.2 | % | ||||||||
| Wholesale and miscellaneous revenue (c) |
203 | 215 | (12 | ) | (5.6 | %) | |||||||
| Total electric revenue |
$ | 3,739 | $ | 3,743 | $ | (4 | ) | (0.1 | %) | ||||
| (a) | Full service revenue reflects revenue from customers taking electric service under tariffed rates, which includes the cost of energy, the delivery cost of the transmission and the distribution of the energy and a CTC. |
| (b) | Delivery only revenue reflects revenue from customers receiving generation from an alternative electric supplier, which includes a distribution charge and a CTC. |
| (c) | Wholesale and miscellaneous revenues include transmission revenue from PJM and other wholesale energy sales. |
285
The changes in electric retail revenues for 2004 compared to 2003 consisted of the following:
| Variance |
||||
| Volume |
$ | 148 | ||
| Rate change |
20 | |||
| Customer choice |
(78 | ) | ||
| Weather |
(63 | ) | ||
| Rate mix |
(19 | ) | ||
| Electric retail revenue |
$ | 8 | ||
Volume. Exclusive of the effects of weather and customer choice, higher delivery volume increased PECO’s revenue $148 million compared to 2003, related primarily to an increased number of customers and increased usage by all customer classes.
Rate Change. Revenues increased $20 million due to a scheduled phase-out of merger-related rate reductions. In connection with the PUC’s approval of the merger of PECO, Unicom Corporation, and Exelon in 2000, PECO entered into a settlement agreement with the PUC and agreed to $200 million in aggregate rate reductions for all customers over the period January 1, 2002 through December 31, 2005. Consequently, rates were reduced from the levels that otherwise would have been in effect pursuant to the PUC approved restructuring settlement by $60 million annually until January 1, 2004 when the reduction decreased to $40 million annually, which will be in effect through December 31, 2005.
Customer Choice. All PECO customers may choose to purchase energy from an alternative electric supplier. This choice does not affect kWh deliveries, but reduces revenue collected from customers because they are not obtaining generation supply from PECO. Also, operating income is not affected by customer choice since reduced revenues are offset by reduced purchase power expense.
In 2004, the energy provided by alternative electric suppliers was 4,605 GWhs or 12% as compared to 3,135 GWhs or 9% in 2003. As of December 31, 2004, the number of customers served by alternative electric suppliers was 101,500 or 7% as compared to 312,600 or 20% as of December 31, 2003. The decrease in electric retail revenue associated with customer choice primarily relates to residential customers selecting or being assigned to an alternative electric supplier. The increase in energy provided by alternative electric suppliers was due to the assignment of residential customers to alternative electric suppliers for a one-year term beginning in December 2003, as required by the PUC and PECO’s final electric restructuring order. The decrease in the number of customers served by alternative electric suppliers was due to these residential customers returning to PECO as their energy provider in December 2004.
Weather. The demand for electricity is affected by weather conditions. Very warm weather in summer months and very cold weather in other months are referred to as “favorable weather conditions” because these weather conditions result in increased sales of electricity. Conversely, mild weather reduces demand. The weather impact was unfavorable compared to the prior year reflecting warmer winter weather. Heating degree-days decreased 5% in 2004 compared to 2003. Cooling degree-days remained relatively unchanged compared to 2003.
Rate Mix. The decrease in revenues from rate mix is due to changes in monthly usage patterns in all customer classes during 2004 compared to 2003.
Electric wholesale and miscellaneous revenue includes PECO’s proportionate share of the transmission revenues generated by PJM. Additionally, PECO pays PJM for its use of these
286
transmission assets, and this expense is recorded in purchased power. Electric wholesale and miscellaneous revenue decreased $12 million primarily due to lower PJM transmission revenue.
PECO’s gas sales statistics and revenue detail are as follows:
| Deliveries to customers (in million cubic feet (mmcf)) |
2004 |
2003 |
Variance |
% Change |
||||||
| Retail sales |
59,949 | 61,858 | (1,909 | ) | (3.1 | %) | ||||
| Transportation |
27,148 | 26,404 | 744 | 2.8 | % | |||||
| Total |
87,097 | 88,262 | (1,165 | ) | (1.3 | %) | ||||
| Revenue |
2004 |
2003 |
Variance |
% Change |
||||||||
| Retail sales |
$ | 702 | $ | 609 | $ | 93 | 15.3 | % | ||||
| Transportation |
18 | 18 | — | — | ||||||||
| Resales and other |
28 | 18 | 10 | 55.6 | % | |||||||
| Total |
$ | 748 | $ | 645 | $ | 103 | 16.0 | % | ||||
The changes in gas retail revenue for 2004 compared to 2003 consisted of the following:
| Variance |
||||
| Rate changes |
$ | 111 | ||
| Volume |
3 | |||
| Weather |
(21 | ) | ||
| Gas retail revenue |
$ | 93 | ||
Rate Changes. The favorable variance in rates was attributable to increases in rates through the purchased gas adjustment clause that became effective March 1, 2003, June 1, 2003, December 1, 2003 and March 1, 2004. The average purchased gas cost rate per mmcf for 2004 was 33% higher than the rate in 2003. PECO’s gas cost rates are subject to periodic adjustments by the PUC and are designed to recover from or refund to customers the difference between the actual cost of purchased gas and the amount included in rates. Effective December 1, 2004, the PUC approved a decrease in PECO’s rates through the purchased gas adjustment clause as a result of lower gas costs. Changes in PECO’s rates through the purchased gas adjustment clause have no impact on operating income.
Volume. Exclusive of the effect of weather conditions, revenues were higher in 2004 compared to 2003 due primarily to increased sales in the small commercial and industrial class.
Weather. The weather conditions were unfavorable in 2004 compared to 2003. Heating degree-days in PECO’s service territory decreased 5% in 2004 compared to 2003.
Resales and other revenue increased $10 million primarily due to increased off-system sales.
Purchased Power
The decrease in purchased power expense was attributable to $78 million from customers in Pennsylvania assigned to or selecting an alternative electric supplier, a $27 million decrease associated with lower sales due to unfavorable weather conditions and a $15 million decrease in PJM transmission expense, partially offset by an increase of $69 million related to increased sales exclusive of weather conditions and $18 million of higher prices.
287
Fuel
The increase in fuel expense in 2004 was primarily attributable to $111 million of higher gas costs and $14 million related to increased off-system sales, partially offset by a $15 million decrease associated with lower sales due to unfavorable weather conditions.
Operating and Maintenance
The changes in operating and maintenance expense for 2004 compared to 2003 consisted of the following:
| Increase (Decrease) |
||||
| Severance and severance-related expenses |
$ | (17 | ) | |
| Automated meter reading system implementation costs in 2003 |
(16 | ) | ||
| Incremental storm costs (a) |
(14 | ) | ||
| Payroll expense (b) |
(11 | ) | ||
| Allowance for uncollectible accounts expense |
(4 | ) | ||
| Corporate allocations (c) |
34 | |||
| Other |
(1 | ) | ||
| Decrease in operating and maintenance expense |
$ | (29 | ) | |
| (a) | Storm costs were significantly higher in 2003 primarily as a result of Hurricane Isabel. |
| (b) | PECO had fewer employees in 2004 compared to 2003. |
| (c) | Higher corporate allocations primarily result from centralization of information technology, supply, human resources, communications, and finance functions into BSC from all of the Exelon operating companies, and changes in the corporate governance allocation calculation. Corporate governance allocations increased overall as a result of higher centralized costs distributed out of BSC, the sale of the Enterprises companies resulting in PECO comprising a greater base percentage of Exelon, and an SEC-mandated change to the methodology used to allocate Exelon’s corporate governance costs. |
Depreciation and Amortization
Depreciation and amortization expense increased for 2004 compared to 2003, as follows:
| 2004 |
2003 |
Increase (Decrease) |
||||||||
| Competitive transition charge amortization |
$ | 367 | $ | 336 | $ | 31 | ||||
| Depreciation expense |
131 | 130 | 1 | |||||||
| Other amortization expense |
20 | 21 | (1 | ) | ||||||
| Total depreciation and amortization |
$ | 518 | $ | 487 | $ | 31 | ||||
The additional amortization of the CTC is in accordance with PECO’s original settlement under the Pennsylvania Competition Act. In January 2005, PECO’s Board of Directors approved the implementation of a new customer information and billing system as part of a broader Energy Delivery systems strategy. The approval of this new system will result in the accelerated depreciation of PECO’s current system, which is expected to result in additional annual depreciation expense in 2005 and 2006 of $15 million and $8 million, respectively, above 2004 levels. If additional systems changes are approved, additional accelerated depreciation may be required.
Taxes Other Than Income
The increase in taxes other than income in 2004 was primarily attributable to a $58 million reduction of real estate tax accruals in 2003 and $12 million related to the reversal of a use tax accrual in 2003 resulting from an audit settlement, partially offset by $4 million of lower payroll taxes.
288
Interest Expense and Distributions on Mandatorily Redeemable Preferred Securities
The aggregate of interest expense and distributions on mandatorily redeemable preferred securities decreased primarily due to lower outstanding debt and refinancings at lower rates, partially offset by a reversal in 2003 of accrued interest expense on Federal income taxes of $8 million to reflect actual interest paid. Effective December 31, 2003, with the adoption of FIN 46-R, PECO deconsolidated its financing trusts (see Note 1 of PECO’s Notes to Consolidated Financial Statements). PECO no longer records distributions on mandatorily redeemable preferred securities of subsidiaries but records interest expense to affiliates related to PECO’s obligations to the financing trusts.
Equity in Losses of Unconsolidated Affiliates
In 2004, PECO recorded $25 million of equity in losses of unconsolidated affiliates as a result of deconsolidating its subsidiary financing trusts.
Other, net
The increase was primarily attributable to a reversal in 2003 of accrued interest on Federal income taxes of $14 million to reflect actual interest received and gains on disposition of assets in 2004.
Income Taxes
The effective tax rate was 35% for 2004 and 2003. See Note 8 of PECO’s Notes to Consolidated Financial Statements for further discussion of the effective income tax rate.
Results of Operations
Year Ended December 31, 2003 Compared To Year Ended December 31, 2002
| 2003 |
2002 |
Favorable (unfavorable) variance |
||||||||||
| OPERATING REVENUES |
$ | 4,388 | $ | 4,333 | $ | 55 | ||||||
| OPERATING EXPENSES |
||||||||||||
| Purchased power |
1,677 | 1,669 | (8 | ) | ||||||||
| Fuel |
419 | 348 | (71 | ) | ||||||||
| Operating and maintenance |
576 | 523 | (53 | ) | ||||||||
| Depreciation and amortization |
487 | 456 | (31 | ) | ||||||||
| Taxes other than income |
173 | 244 | 71 | |||||||||
| Total operating expense |
3,332 | 3,240 | (92 | ) | ||||||||
| OPERATING INCOME |
1,056 | 1,093 | (37 | ) | ||||||||
| OTHER INCOME AND DEDUCTIONS |
||||||||||||
| Interest expense |
(324 | ) | (370 | ) | 46 | |||||||
| Distributions on mandatorily redeemable preferred securities |
(8 | ) | (10 | ) | 2 | |||||||
| Other, net |
2 | 32 | (30 | ) | ||||||||
| Total other income and deductions |
(330 | ) | (348 | ) | 18 | |||||||
| INCOME BEFORE INCOME TAXES |
726 | 745 | (19 | ) | ||||||||
| INCOME TAXES |
253 | 259 | 6 | |||||||||
| NET INCOME |
473 | 486 | (13 | ) | ||||||||
| Preferred stock dividends |
5 | 8 | 3 | |||||||||
| NET INCOME ON COMMON STOCK |
$ | 468 | $ | 478 | $ | (10 | ) | |||||
289
Net Income on Common Stock
The decrease in net income on common stock in 2003 was a result of higher fuel, operating and maintenance and depreciation and amortization expense, partially offset by higher gas revenue, lower taxes other than income and lower interest expense.
Operating Revenue
PECO’s electric sales statistics and revenue detail are as follows:
| Retail Deliveries—(in GWhs) |
2003 |
2002 |
Variance |
% Change |
||||||
| Full service (a) |
||||||||||
| Residential |
11,358 | 10,365 | 993 | 9.6 | % | |||||
| Small commercial & industrial |
6,624 | 7,606 | (982 | ) | (12.9 | %) | ||||
| Large commercial & industrial |
14,739 | 14,766 | (27 | ) | (0.2 | %) | ||||
| Public authorities & electric railroads |
897 | 852 | 45 | 5.3 | % | |||||
| 33,618 | 33,589 | 29 | 0.1 | % | ||||||
| Delivery only (b) |
||||||||||
| Residential |
900 | 1,971 | (1,071 | ) | (54.3 | %) | ||||
| Small commercial & industrial |
1,455 | 415 | 1,040 | n.m. | ||||||
| Large commercial & industrial |
780 | 557 | 223 | 40.0 | % | |||||
| 3,135 | 2,943 | 192 | 6.5 | % | ||||||
| Total retail deliveries |
36,753 | 36,532 | 221 | 0.6 | % | |||||
| n.m.—not | meaningful |
| (a) | Full service reflects deliveries to customers taking electric service under tariffed rates. |
| (c) | Delivery only service reflects customers electing to receive electric generation service from an alternative energy supplier. |
| Electric Revenue |
2003 |
2002 |
Variance |
% Change |
|||||||||
| Full service (a) |
|||||||||||||
| Residential |
$ | 1,444 | $ | 1,338 | $ | 106 | 7.9 | % | |||||
| Small commercial & industrial |
753 | 865 | (112 | ) | (12.9 | %) | |||||||
| Large commercial & industrial |
1,090 | 1,086 | 4 | 0.4 | % | ||||||||
| Public authorities & electric railroads |
80 | 79 | 1 | 1.3 | % | ||||||||
| 3,367 | 3,368 | (1 | ) | 0.0 | % | ||||||||
| Delivery only (b) |
|||||||||||||
| Residential |
65 | 145 | (80 | ) | (55.2 | %) | |||||||
| Small commercial & industrial |
75 | 21 | 54 | n.m. | |||||||||
| Large commercial & industrial |
21 | 16 | 5 | 31.3 | % | ||||||||
| 161 | 182 | (21 | ) | (11.5 | %) | ||||||||
| Total electric retail revenues |
3,528 | 3,550 | (22 | ) | (0.6 | %) | |||||||
| Wholesale and miscellaneous revenue (c) |
215 | 234 | (19 | ) | (8.1 | %) | |||||||
| Total electric revenue |
$ | 3,743 | $ | 3,784 | $ | (41 | ) | (1.1 | %) | ||||
| n.m.—not | meaningful |
| (a) | Full service reflects revenue from customers taking electric service under tariffed rates, which includes the cost of energy, the delivery cost of the transmission and the distribution of the energy and a CTC. |
| (b) | Delivery only revenue reflects revenue from customers electing to receive generation from an alternative supplier, which includes a distribution charge and a CTC. |
| (c) | Wholesale and miscellaneous revenues include transmission revenue and other wholesale energy sales. |
290
The changes in electric retail revenues for 2003 compared to 2002 consisted of the following:
| Variance |
||||
| Rate mix |
$ | (25 | ) | |
| Customer choice |
(12 | ) | ||
| Volume |
13 | |||
| Weather |
3 | |||
| Other effects |
(1 | ) | ||
| Electric retail revenue |
$ | (22 | ) | |
Rate Mix. The decrease in revenues from rate mix is due to changes in monthly usage patterns in all customer classes during 2003 compared to 2002.
Customer Choice. All PECO customers may choose to purchase energy from an alternative electric supplier. This choice does not affect kWh deliveries, but reduces revenue collected from customers because they are not obtaining generation supply from PECO. Also, operating income is not affected by customer choice since reduced revenues are offset by reduced purchase power expense.
For the year ended December 31, 2003, the energy provided by alternative electric suppliers was 3,135 GWhs or 9% as compared to 2,943 GWhs or 8% for the year ended December 31, 2002. As of December 31, 2003, the number of customers served by was 312,600 or 20% as compared to 277,800 or 18% as of December 31, 2002. The decrease in electric retail revenue associated with customer choice primarily relates to small commercial and industrial customers selecting or being assigned to an alternative electric supplier.
Volume. Exclusive of the effects of weather and customer choice, higher delivery volume increased PECO’s revenue $13 million compared to 2002, primarily related to increases in the residential customer class, reflecting customer growth, and increased usage in the small commercial and industrial customer classes.
Weather. The demand for electricity is affected by weather conditions. The weather impact was slightly favorable compared to the prior year reflecting colder winter weather during the beginning of the year, largely offset by cooler summer weather and warmer winter weather during the end of the year. Heating degree-days increased 16% in 2003 compared to 2002. Cooling degree-days decreased 21% compared to 2002.
PECO’s gas sales statistics and revenue detail are as follows:
| Deliveries to customers (in million cubic feet (mmcf)) |
2003 |
2002 |
Variance |
% Change |
||||||
| Retail sales |
61,858 | 54,782 | 7,076 | 12.9 | % | |||||
| Transportation |
26,404 | 30,763 | (4,359 | ) | (14.2 | %) | ||||
| Total |
88,262 | 85,545 | 2,717 | 3.2 | % | |||||
| Revenue |
2003 |
2002 |
Variance |
% Change |
|||||||||
| Retail sales |
$ | 609 | $ | 490 | $ | 119 | 24.3 | % | |||||
| Transportation |
18 | 19 | (1 | ) | (5.3 | %) | |||||||
| Resales and other |
18 | 40 | (22 | ) | (55.0 | %) | |||||||
| Total |
$ | 645 | $ | 549 | $ | 96 | 17.5 | % | |||||
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The changes in gas retail revenue for 2003 compared to 2002 consisted of the following:
| Variance |
||||
| Weather |
$ | 71 | ||
| Rate changes |
51 | |||
| Volume |
(3 | ) | ||
| Gas retail revenue |
$ | 119 | ||
Weather. The weather impact was favorable in 2003 compared to 2002 reflecting colder winter weather during the beginning of the year, partly offset by warmer weather during the end of the year. Heating degree-days in PECO’s service territory increased 16% in 2003 compared to 2002.
Rate Changes. The favorable variance in rates was attributable to increases in rates through the purchased gas adjustment clause that became effective March 1, 2003, June 1, 2003 and December 1, 2003. The average purchased gas cost rate per mmcf for 2003 was 11% higher than the rate in 2002. PECO’s purchased gas cost rates are subject to periodic adjustments by the PUC and are designed to recover from or refund to customers the difference between the actual cost of purchased gas and the amount included in rates.
Lower gas resale and other revenues are attributable to a decrease in off-system sales, exchanges and capacity releases during 2003 compared to 2002.
Purchased Power
The increase in purchased power expense was attributable to $10 million for higher electric delivery volume and $7 million for higher prices, including higher PJM ancillary charges, partially offset by decreased purchases of $9 million primarily related to additional small commercial and industrial customers selecting or being assigned to alternative electric suppliers in 2003.
Fuel
The increase in fuel expense in 2003 was primarily attributable to a $55 million increase in purchased gas volumes to meet increased customer demand and a $39 million increase due to higher gas costs, partially offset by a $28 million decrease in fuel expense associated with lower resale sales.
Operating and Maintenance
The increase in operating and maintenance expense was primarily attributable to $30 million of severance and severance-related costs associated with The Exelon Way, $22 million of higher storm-related costs, $16 million of increased employee fringe benefits, $7 million related to additional uncollectible accounts expense, partially offset by $13 million of lower costs associated with the initial implementation of automated meter reading services in 2002, and $15 million of lower payroll expense due to a lower number of employees. During 2002, PECO decreased its reserve for uncollectible accounts by $17 million as a result of a change in estimate.
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Depreciation and Amortization
Depreciation and amortization expense increased for 2003 compared to 2002 as follows:
| 2003 |
2002 |
Variance |
||||||||
| Competitive transition charge amortization |
$ | 336 | $ | 308 | $ | 28 | ||||
| Depreciation expense |
130 | 125 | 5 | |||||||
| Other amortization expense |
21 | 23 | (2 | ) | ||||||
| Total depreciation and amortization |
$ | 487 | $ | 456 | $ | 31 | ||||
The additional amortization of the CTC is in accordance with PECO’s original settlement under the Pennsylvania Competition Act. The increase in depreciation expense was due to additional plant in service.
Taxes Other Than Income
The decrease in taxes other than income in 2003 was primarily attributable to a $58 million reduction of real estate tax accruals in 2003, a $16 million decrease in real estate tax expense in 2003, a $12 million reversal of the use tax accrual due to an audit settlement, partially offset by a $14 million reversal of an overaccrual of Pennsylvania sales and use tax in 2002.
Interest Charges
Interest charges consisted of interest expense, interest expense to unconsolidated affiliates and distributions on Company-Obligated Mandatorily Redeemable Preferred Securities of a Partnership (COMPrS). The decrease in 2003 was primarily attributable to lower interest expense on long-term debt of $38 million as a result of less outstanding debt and refinancing of existing debt at lower interest rates, and the reversal of accrued interest expense on Federal income taxes of $8 million in 2003.
Other Income and Deductions
The decrease in other income and deductions was primarily attributable to a reversal of interest expense on Federal income taxes of $14 million and an $18 million IRS refund, both of which occurred during 2002.
Liquidity and Capital Resources
PECO’s business is capital intensive and requires considerable capital resources. PECO’s capital resources are primarily provided by internally generated cash flows from operations and, to the extent necessary, external financing, including the issuance of commercial paper, participation in the intercompany money pool or capital contributions from Exelon. PECO’s access to external financing at reasonable terms is dependent on its credit ratings and general business conditions, as well as that of the utility industry in general. If these conditions deteriorate to the extent that PECO no longer has access to external financing sources at reasonable terms, PECO has access to a revolving credit facility that PECO currently utilizes to support its commercial paper program. See the Credit Issues section of Liquidity and Capital Resources for further discussion. Capital resources, including cash, are used primarily to fund PECO’s capital requirements, including construction expenditures, repayments of maturing debt, the payment of dividends and contributions to Exelon’s pension plans. PECO’s construction expenditures utilize a significant amount of cash on projects that have a long-term return on investment. Additionally, PECO operates in a rate-regulated environment in which recovery of current cash expenditures takes place over an extended period of time. As a result of these factors, PECO has historically operated with a working capital deficit. However, PECO expects operating cash flows to be sufficient to meet operating and capital expenditure requirements.
293
Cash Flows from Operating Activities
PECO’s cash flows from operating activities primarily result from sales of electricity and gas to a stable and diverse base of retail customers at fixed prices and are weighted toward the first and third quarters of each fiscal year. PECO’s future cash flows will be affected by its ability to achieve operating cost reductions and the impact of the economy, weather, customer choice and future regulatory proceedings on its revenues. Cash flows from operations have been and are expected to continue to provide a reliable, steady source of cash flow, sufficient to meet operating and capital expenditures requirements for the foreseeable future. Operating cash flows after 2006 could be negatively affected by changes in PECO’s rate regulatory environment, although any effects are not expected to hinder PECO’s ability to fund its business requirements. See Business Outlook and Challenges in Managing the Business.
Cash flows provided by operations for the years ended December 31, 2004 and 2003 were $983 million and $814 million, respectively. Changes in PECO’s cash flows from operations are generally consistent with changes in its results of operations, as further adjusted by changes in working capital in the normal course of business.
In addition to the items mentioned in Results of Operations, PECO’s operating cash flows in 2004 were affected by the following items:
| • | Deferred natural gas costs decreased $10 million during 2004 resulting in an increase to operating cash flows. During 2003, an increase in deferred natural gas costs of $50 million resulted in a decrease to operating cash flows. PECO’s gas cost rates are subject to periodic adjustments by the PUC that are designed to recover from or refund to customers the difference between the actual cost of purchased gas and the amount included in rates. During 2004, PECO was recovering fuel revenues from customers in excess of gas costs being incurred. During 2003, PECO was incurring gas costs in excess of fuel revenues being recovered from customers. |
| • | PECO participates in Exelon’s defined benefit pension plans and postretirement welfare benefit plans. Contributions by PECO to the plans were $14 million in 2004 compared to $49 million for the same period in 2003. |
Cash Flows from Investing Activities
Cash flows used in investing activities in 2004 were $248 million compared to $246 million in 2003 and reflect a $34 million increase in PECO’s contribution to the Exelon intercompany money pool in 2004, partially offset by lower construction expenditures of $25 million in 2004. PECO’s investing activities during 2004 were funded by operating activities.
PECO’s projected capital expenditures for 2005 are $281 million. Approximately 65% of the budgeted 2005 expenditures are for additions to or upgrades of existing facilities, including reliability improvements. The remainder of the capital expenditures support customer and load growth. Internally generated cash flow in 2005 is expected to meet capital requirements. PECO’s proposed capital expenditures and other investments are subject to periodic review and revision to reflect changes in economic conditions and other factors.
Cash Flows from Financing Activities
Cash flows used in financing activities in 2004 were $676 million compared to $587 million in 2003. The increase in cash flows used in financing activities was primarily due to an increase in net retirements of long-term debt of $388 million, partially offset by a decrease in repayments of short-term debt of $108 million, a decrease in the retirement of preferred securities of $100 million and an
294
increase in contributions received from Exelon of $153 million. Additionally, PECO paid dividends of $394 million and $327 million during 2004 and 2003, respectively, of which $391 million and $322 million, respectively, were common dividends paid to Exelon.
From time to time and as market conditions warrant, PECO may engage in long-term debt retirements via tender offers, open market repurchases or other viable options to strengthen its balance sheet.
Credit Issues
Exelon Credit Facility. A description of Exelon’s credit agreements, and PECO’s participation therein, is set forth above under “Credit Issues—Exelon Credit Facility” in “Exelon Corporation—Liquidity and Capital Resources.”
Capital Structure. At December 31, 2004, PECO’s capital structure consisted of 78% long-term debt, including long-term debt to unconsolidated affiliates, 21% common equity and 1% preferred securities. Long-term debt to unconsolidated affiliates includes obligations to PETT, PECO Trust III, and PECO Trust IV, which are no longer consolidated within the financial statements due to the adoption of FIN 46 and FIN 46-R. PECO’s capital structure, excluding the deduction from shareholders’ equity of the $1.5 billion receivable from Exelon (which amount is deducted for GAAP purposes but is excluded here to reflect amounts expected to be received by PECO from Exelon to pay future taxes), consisted of 63% long-term debt, including long-term debt to unconsolidated affiliates, 36% common equity and 1% preferred securities. See Note 1 of PECO’s Notes to Consolidated Financial Statements for further information regarding FIN 46 and FIN 46-R.
Intercompany Money Pool. A description of the intercompany money pool, and PECO’s participation therein, is set forth above under “Credit Issues—Intercompany Money Pool” in “Exelon Corporation—Liquidity and Capital Resources.” During 2004, PECO earned less than $1 million in interest from its contributions to the intercompany money pool and paid less than $1 million on borrowings from the intercompany money pool.
Security Ratings. A description of PECO’s security ratings is set forth above under “Credit Issues—Security Ratings” in “Exelon Corporation—Liquidity and Capital Resources.”
Shelf Registration. A description of PECO’s shelf registration is set forth above under “Credit Issues—Shelf Registration” in “Exelon Corporation—Liquidity and Capital Resources.”
Fund Transfer Restrictions. Under applicable law, PECO is precluded from lending or extending credit or indemnity to Exelon and can pay dividends only from retained or current earnings. At December 31, 2004, PECO had retained earnings of $607 million.
295
Contractual Obligations and Off-Balance Sheet Obligations
The following table summarizes PECO’s future estimated cash payments under existing contractual obligations, including payments due by period.
| Payment due within |
Due 2010 and beyond | ||||||||||||||
| (in millions) |
Total |
2005 |
2006-2007 |
2008-2009 |
|||||||||||
| Long-term debt |
$ | 1,200 | $ | 46 | $ | — | $ | 450 | $ | 704 | |||||
| Long-term debt to financing trusts |
3,640 | 165 | 1,160 | 1,325 | 990 | ||||||||||
| Interest payments on long-term debt (a) |
391 | 48 | 97 | 71 | 175 | ||||||||||
| Interest payments on long-term debt to financing trusts (a) |
1,109 | 233 | 381 | 221 | 274 | ||||||||||
| Operating leases |
11 | 3 | 4 | 2 | 2 | ||||||||||
| Other purchase commitments (b) |
2 | 1 | 1 | — | — | ||||||||||
| Total contractual obligations |
$ | 6,353 | $ | 496 | $ | 1,643 | $ | 2,069 | $ | 2,145 | |||||
| (a) | Interest payments are estimated based on final maturity dates of debt securities outstanding at December 31, 2004 and do not reflect anticipated future refinancing, early redemptions or debt issuances. |
| (b) | Commitments for services and materials. |
See ITEM 8. Financial Statements and Supplementary Data—PECO’s Notes to Consolidated Financial Statements for additional information about:
| • | long-term debt, including long-term debt due to financing trusts, see Note 7 |
| • | operating leases, see Note 14 |
See Note 14 of PECO’s Notes to Consolidated Financial Statements for discussion of PECO’s commercial commitments as of December 31, 2004.
Accounts Receivable Agreement. PECO is party to an agreement with a financial institution under which it can sell or finance with limited recourse an undivided interest, adjusted daily, in up to $225 million of designated accounts receivable until November 2005. PECO entered into this agreement to diversify its funding sources at favorable floating interest rates. At December 31, 2004, PECO had sold a $225 million interest in accounts receivable, consisting of a $179 million interest in accounts receivable, which PECO accounted for as a sale under SFAS No. 140, “Accounting for Transfers and Servicing of Financial Assets and Extinguishment of Liabilities—a Replacement of FASB Statement No. 125,” and a $46 million interest in special-agreement accounts receivable, which was accounted for as a long-term note payable and reflected on PECO’s Consolidated Balance Sheet as long-term debt due within one year. At December 31, 2003, PECO had sold a $225 million interest in accounts receivable, consisting of a $176 million interest in accounts receivable which PECO accounted for as a sale under SFAS No. 140 and a $49 million interest in special-agreement accounts receivable which was accounted for as a long-term note payable. See ITEM 8. Financial Statements and Supplementary Data—PECO Note 3 of PECO’s Notes to Consolidated Financial Statements. PECO must continue to service these receivables and must maintain the level of the accounts receivable at $225 million. If PECO fails to maintain that level, the cash that would otherwise be received by PECO under this program must be held in escrow until the level is met. At December 31, 2004 and 2003, PECO met this requirement and was not required to make any cash deposits.
IRS Refund Claims. PECO entered into several agreements with a tax consultant related to the filing of refund claims with the Internal Revenue Service (IRS) and previously made refundable prepayments to the tax consultant of $5 million. The fees for these agreements are contingent upon a successful outcome and are based upon a percentage of the refunds recovered from the IRS, if any.
296
The ultimate net cash outflow to PECO related to all the agreements will either be positive or neutral depending upon the outcome of the refund claim with the IRS. These potential tax benefits and associated fees could be material to PECO’s financial position, results of operations and cash flows. PECO cannot predict the timing of the final resolution of these refund claims.
Variable Interest Entities. Effective July 1, 2003, PECO Trust IV was deconsolidated from the financial statements of PECO in conjunction with the adoption of FIN 46. Effective December 31, 2003, PETT and PECC were deconsolidated from the financial statements of PECO in conjunction with the adoption of FIN 46-R. Approximately $3.6 billion of debt issued by PECO to these financing trusts was recorded as long-term debt to PETT and long-term debt to financing trusts within the Consolidated Balance Sheet as of December 31, 2004.
Critical Accounting Policies and Estimates
See Exelon, ComEd, PECO and Generation—Critical Accounting Policies and Estimates above for a discussion of PECO’s critical accounting policies and estimates.
Business Outlook and the Challenges in Managing the Business
PECO’s business is comprised of utility transmission and distribution operations, which provides electricity and natural gas to customers in Pennsylvania. The electric industry in the United States is in the midst of a fundamental and, at this point, uncertain transition from a fully regulated industry offering bundled service to an industry with unbundled services, some of which are regulated and others of which are priced in competitive markets. PECO’s energy delivery business remains highly regulated and is capital intensive.
A description of the business outlook and challenges in managing PECO’s business is set forth above under “Business Outlook and the Challenges in Managing the Business—Energy Delivery and General Business” in “Exelon Corporation—Management’s Discussion and Analysis of Financial Condition and Results of Operation.”
Further discussion of PECO’s liquidity position and capital resources and related challenges is included in the Liquidity and Capital Resources section.
New Accounting Pronouncements
See Note 1 of PECO’s Notes to Consolidated Financial Statements for information regarding new accounting pronouncements.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK— PECO
PECO is exposed to market risks associated with credit and interest rates. These risks are described above under “Quantitative and Qualitative Disclosures about Market Risk—Exelon.”
297
| ITEM 8. | FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA |
Report of Independent Registered Public Accounting Firm
To the Shareholders and Board of Directors of PECO Energy Company:
In our opinion, the consolidated financial statements listed in the index appearing under Item 15(a)(3)(i) present fairly, in all material respects, the financial position of PECO Energy Company and Subsidiary Companies (PECO) at December 31, 2004 and 2003, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2004 in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedule listed in the index appearing under Item 15(a)(3)(ii) presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements. These financial statements and financial statement schedule are the responsibility of PECO’s management. Our responsibility is to express an opinion on these financial statements and financial statement schedule based on our audits. We conducted our audits of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
As discussed in Note 1 to the consolidated financial statements, PECO changed its method of accounting for variable interest entities in 2003; and as discussed in Note 9 to the consolidated financial statements, PECO changed its method of accounting for asset retirement obligations as of January 1, 2003.
PricewaterhouseCoopers LLP
Chicago, Illinois
February 22, 2005
298
PECO Energy Company and Subsidiary Companies
Consolidated Statements of Income
| For the Years Ended December 31, |
||||||||||||
| (in millions) |
2004 |
2003 |
2002 |
|||||||||
| Operating revenues |
||||||||||||
| Operating revenues |
$ | 4,468 | $ | 4,377 | $ | 4,321 | ||||||
| Operating revenues from affiliates |
19 | 11 | 12 | |||||||||
| Total operating revenues |
4,487 | 4,388 | 4,333 | |||||||||
| Operating expenses |
||||||||||||
| Purchased power |
197 | 244 | 231 | |||||||||
| Purchased power from affiliate |
1,447 | 1,433 | 1,438 | |||||||||
| Fuel |
511 | 419 | 348 | |||||||||
| Fuel from affiliate |
17 | — | — | |||||||||
| Operating and maintenance |
440 | 519 | 450 | |||||||||
| Operating and maintenance from affiliates |
107 | 57 | 73 | |||||||||
| Depreciation and amortization |
518 | 487 | 456 | |||||||||
| Taxes other than income |
236 | 173 | 244 | |||||||||
| Total operating expenses |
3,473 | 3,332 | 3,240 | |||||||||
| Operating income |
1,014 | 1,056 | 1,093 | |||||||||
| Other income and deductions |
||||||||||||
| Interest expense |
(56 | ) | (321 | ) | (370 | ) | ||||||
| Interest expense to affiliates |
(247 | ) | (3 | ) | — | |||||||
| Distributions on mandatorily redeemable preferred securities |
— | (8 | ) | (10 | ) | |||||||
| Equity in earnings (losses) of unconsolidated affiliates |
(25 | ) | — | 1 | ||||||||
| Other, net |
18 | 2 | 31 | |||||||||
| Total other income and deductions |
(310 | ) | (330 | ) | (348 | ) | ||||||
| Income before income taxes |
704 | 726 | 745 | |||||||||
| Income taxes |
249 | 253 | 259 | |||||||||
| Net income |
455 | 473 | 486 | |||||||||
| Preferred stock dividends |
3 | 5 | 8 | |||||||||
| Net income on common stock |
$ | 452 | $ | 468 | $ | 478 | ||||||
See Notes to Consolidated Financial Statements
299
PECO Energy Company and Subsidiary Companies
Consolidated Statements of Cash Flows
| For the Years Ended December 31, |
||||||||||||
| (in millions) |
2004 |
2003 |
2002 |
|||||||||
| Cash flows from operating activities |
||||||||||||
| Net income |
$ | 455 | $ | 473 | $ | 486 | ||||||
| Adjustments to reconcile net income to net cash flows provided by operating activities: |
||||||||||||
| Depreciation and amortization |
518 | 487 | 456 | |||||||||
| Provision for uncollectible accounts |
47 | 52 | 46 | |||||||||
| Deferred income taxes and amortization of investment tax credits |
(98 | ) | (50 | ) | (92 | ) | ||||||
| Equity in (earnings) losses of unconsolidated affiliates |
25 | — | (1 | ) | ||||||||
| Other non-cash operating activities |
9 | 8 | 8 | |||||||||
| Changes in assets and liabilities: |
||||||||||||
| Accounts receivable |
(59 | ) | (24 | ) | (145 | ) | ||||||
| Inventories |
(21 | ) | (32 | ) | 4 | |||||||
| Deferred energy costs |
10 | (50 | ) | 25 | ||||||||
| Other current assets |
(1 | ) | (2 | ) | (6 | ) | ||||||
| Accounts payable, accrued expenses and other current liabilities |
27 | (59 | ) | 45 | ||||||||
| Change in receivables and payables to affiliates, net |
(4 | ) | (31 | ) | (41 | ) | ||||||
| Income taxes |
57 | 21 | (23 | ) | ||||||||
| Pension and non-pension postretirement benefits obligations |
23 | 9 | (9 | ) | ||||||||
| Other noncurrent assets and liabilities |
(5 | ) | 12 | 7 | ||||||||
| Net cash flows provided by operating activities |
983 | 814 | 760 | |||||||||
| Cash flows from investing activities |
||||||||||||
| Capital expenditures |
(225 | ) | (250 | ) | (261 | ) | ||||||
| Changes in Exelon intercompany money pool contributions |
(34 | ) | — | — | ||||||||
| Change in restricted cash |
— | — | (8 | ) | ||||||||
| Other investing activities |
11 | 4 | 9 | |||||||||
| Net cash flows used in investing activities |
(248 | ) | (246 | ) | (260 | ) | ||||||
| Cash flows from financing activities |
||||||||||||
| Issuance of long-term debt |
75 | 450 | 225 | |||||||||
| Retirement of long-term debt |
(235 | ) | (718 | ) | (571 | ) | ||||||
| Issuance of long-term debt to financing trusts |
— | 103 | — | |||||||||
| Retirement of long-term debt to financing trusts |
(393 | ) | — | — | ||||||||
| Change in short-term debt |
(46 | ) | (154 | ) | 99 | |||||||
| Retirement of mandatorily redeemable preferred stock |
— | (50 | ) | (19 | ) | |||||||
| Retirement of preferred stock |
— | (50 | ) | — | ||||||||
| Dividends paid on preferred and common stock |
(394 | ) | (327 | ) | (348 | ) | ||||||
| Contribution from parent |
312 | 159 | 150 | |||||||||
| Other financing activities |
5 | — | (5 | ) | ||||||||
| Net cash flows used in financing activities |
(676 | ) | (587 | ) | (469 | ) | ||||||
| Increase (decrease) in cash and cash equivalents |
59 | (19 | ) | 31 | ||||||||
| Cash and cash equivalents at beginning of period |
44 | 63 | 32 | |||||||||
| Cash and cash equivalents at end of period |
$ | 103 | $ | 44 | $ | 63 | ||||||
See Notes to Consolidated Financial Statements
300
PECO Energy Company and Subsidiary Companies
Consolidated Balance Sheets
| December 31, |
||||||||
| (in millions) |
2004 |
2003 |
||||||
| Assets |
||||||||
| Current assets |
||||||||
| Cash and cash equivalents |
$ | 103 | $ | 44 | ||||
| Accounts receivable, net |
||||||||
| Customer |
368 | 363 | ||||||
| Other |
34 | 27 | ||||||
| Inventories, at average cost |
||||||||
| Gas |
117 | 99 | ||||||
| Materials and supplies |
10 | 7 | ||||||
| Deferred income taxes |
24 | 64 | ||||||
| Contributions to Exelon intercompany money pool |
34 | — | ||||||
| Deferred energy costs |
71 | 81 | ||||||
| Other |
12 | 11 | ||||||
| Total current assets |
773 | 696 | ||||||
| Property, plant and equipment, net |
4,329 | 4,256 | ||||||
| Deferred debits and other assets |
||||||||
| Regulatory assets |
4,790 | 5,226 | ||||||
| Investments |
22 | 20 | ||||||
| Investment in affiliates |
87 | 123 | ||||||
| Receivables from affiliates |
46 | 13 | ||||||
| Pension asset |
77 | 68 | ||||||
| Other |
9 | 8 | ||||||
| Total deferred debits and other assets |
5,031 | 5,458 | ||||||
| Total assets |
$ | 10,133 | $ | 10,410 | ||||
| Liabilities and shareholders’ equity |
||||||||
| Current liabilities |
||||||||
| Commercial paper |
$ | — | $ | 46 | ||||
| Long-term debt due within one year |
46 | — | ||||||
| Long-term debt to PECO Energy Transition Trust due within one year |
165 | 153 | ||||||
| Accounts payable |
121 | 92 | ||||||
| Accrued expenses |
263 | 237 | ||||||
| Payables to affiliates |
146 | 150 | ||||||
| Customer deposits |
42 | 30 | ||||||
| Other |
11 | 5 | ||||||
| Total current liabilities |
794 | 713 | ||||||
| Long-term debt |
1,153 | 1,359 | ||||||
| Long-term debt to PECO Energy Transition Trust |
3,291 | 3,696 | ||||||
| Long-term debt to other financing trusts |
184 | 184 | ||||||
| Deferred credits and other liabilities |
||||||||
| Deferred income taxes |
2,834 | 2,986 | ||||||
| Unamortized investment tax credits |
19 | 22 | ||||||
| Non-pension postretirement benefits obligation |
319 | 287 | ||||||
| Other |
141 | 147 | ||||||
| Total deferred credits and other liabilities |
3,313 | 3,442 | ||||||
| Total liabilities |
8,735 | 9,394 | ||||||
| Commitments and contingencies |
||||||||
| Shareholders’ equity |
||||||||
| Common stock |
2,176 | 1,999 | ||||||
| Receivable from parent |
(1,482 | ) | (1,623 | ) | ||||
| Preferred stock |
87 | 87 | ||||||
| Retained earnings |
607 | 546 | ||||||
| Accumulated other comprehensive income |
10 | 7 | ||||||
| Total shareholders’ equity |
1,398 | 1,016 | ||||||
| Total liabilities and shareholders’ equity |
$ | 10,133 | $ | 10,410 | ||||
See Notes to Consolidated Financial Statements
301
PECO Energy Company and Subsidiary Companies
Consolidated Statements of Changes in Shareholders’ Equity
| (in millions) |
Common Stock |
Preferred Stock |
Receivable from Parent |
Retained Earnings |
Accumulated Other Comprehensive Income (Loss) |
Total Shareholders’ Equity |
||||||||||||||||||
| Balance, December 31, 2001 |
$ | 1,919 | $ | 137 | $ | (1,878 | ) | $ | 263 | $ | 19 | $ | 460 | |||||||||||
| Net income |
— | — | — | 486 | — | 486 | ||||||||||||||||||
| Common stock dividends |
— | — | — | (340 | ) | — | (340 | ) | ||||||||||||||||
| Preferred stock dividends |
— | — | — | (8 | ) | — | (8 | ) | ||||||||||||||||
| Repayment of receivable from parent |
— | — | 120 | — | — | 120 | ||||||||||||||||||
| Capital contribution from parent |
30 | — | — | — | — | 30 | ||||||||||||||||||
| Allocation of tax benefit from parent |
27 | — | — | — | — | 27 | ||||||||||||||||||
| Other comprehensive income, net of income taxes of $(9) |
— | — | — | — | (14 | ) | (14 | ) | ||||||||||||||||
| Balance, December 31, 2002 |
1,976 | 137 | (1,758 | ) | 401 | 5 | 761 | |||||||||||||||||
| Net income |
— | — | — | 473 | — | 473 | ||||||||||||||||||
| Common stock dividends |
— | — | — | (322 | ) | — | (322 | ) | ||||||||||||||||
| Preferred stock dividends |
— | — | — | (5 | ) | — | (5 | ) | ||||||||||||||||
| Redemption of preferred stock |
— | (50 | ) | — | (1 | ) | — | (51 | ) | |||||||||||||||
| Repayment of receivable from parent |
— | — | 135 | — | — | 135 | ||||||||||||||||||
| Capital contribution from parent |
17 | — | — | — | — | 17 | ||||||||||||||||||
| Allocation of tax benefit from parent |
7 | — | — | — | — | 7 | ||||||||||||||||||
| Return of equity from unconsolidated affiliate |
(1 | ) | — | — | — | — | (1 | ) | ||||||||||||||||
| Other comprehensive income, net of income taxes of $1 |
— | — | — | — | 2 | 2 | ||||||||||||||||||
| Balance, December 31, 2003 |
1,999 | 87 | (1,623 | ) | 546 | 7 | 1,016 | |||||||||||||||||
| Net income |
— | — | — | 455 | — | 455 | ||||||||||||||||||
| Common stock dividends |
— | — | — | (391 | ) | — | (391 | ) | ||||||||||||||||
| Preferred stock dividends |
— | — | — | (3 | ) | — | (3 | ) | ||||||||||||||||
| Repayment of receivable from parent |
— | — | 141 | — | — | 141 | ||||||||||||||||||
| Capital contribution from parent |
156 | — | — | — | — | 156 | ||||||||||||||||||
| Allocation of tax benefit from parent |
21 | — | — | — | — | 21 | ||||||||||||||||||
| Other comprehensive income, net of income taxes of $(2) |
— | — | — | — | 3 | 3 | ||||||||||||||||||
| Balance, December 31, 2004 |
$ | 2,176 | $ | 87 | $ | (1,482 | ) | $ | 607 | $ | 10 | $ | 1,398 | |||||||||||
See Notes to Consolidated Financial Statements
302
PECO Energy Company and Subsidiary Companies
Consolidated Statements of Comprehensive Income
| For the Years Ended December 31, |
||||||||||
| (in millions) |
2004 |
2003 |
2002 |
|||||||
| Net income |
$ | 455 | $ | 473 | $ | 486 | ||||
| Other comprehensive income (loss) |
||||||||||
| Change in net unrealized gain (loss) on cash-flow hedges, net of income taxes of $(1) and $(8), respectively |
1 | — | (13 | ) | ||||||
| Unrealized gain (loss) on marketable securities, net of income taxes of $(1), $1 and $(1), respectively |
2 | 2 | (1 | ) | ||||||
| Total other comprehensive income (loss) |
3 | 2 | (14 | ) | ||||||
| Total comprehensive income |
$ | 458 | $ | 475 | $ | 472 | ||||
See Notes to Consolidated Financial Statements
303
PECO Energy Company and Subsidiary Companies
Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
1. Significant Accounting Policies
Description of Business
Incorporated in Pennsylvania in 1929, PECO Energy Company (PECO) is a regulated utility engaged principally in the purchase, transmission, distribution and sale of electricity to residential, commercial and industrial customers in southeastern Pennsylvania, including the City of Philadelphia, and the distribution and sale of natural gas to residential, commercial and industrial customers in the Pennsylvania counties surrounding the City of Philadelphia. Pursuant to the Pennsylvania Electricity Generation Customer Choice and Competition Act (Competition Act), the Commonwealth of Pennsylvania requires the unbundling of retail electric services in Pennsylvania into separate generation, transmission and distribution services with open retail competition for generation services. PECO serves as the local distribution company providing electric distribution services in its franchised service territory in southeastern Pennsylvania and energy service to customers who do not choose an alternate electric generation supplier.
Basis of Presentation
PECO, a regulated electric and gas utility, is a principal subsidiary of Exelon Corporation (Exelon), which owns 100% of PECO’s common stock. The consolidated financial statements of PECO include the accounts of its subsidiaries, including ExTel Corporation, LLC, Adwin Realty Company and PECO Wireless, LP, except certain financing trusts for 2004 and 2003. All intercompany transactions have been eliminated. As of July 1, 2003, PECO Energy Capital Trust IV (PECO Trust IV) was no longer consolidated within the financial statements of PECO. Effective December 31, 2003, the accounts of PECO Energy Transition Trust (PETT) and PECO Energy Capital Corporation (PECC) are no longer consolidated. PECC is the sole general partner of PECO Energy Capital L.P. (PEC L.P.), which is the sponsor of PECO Energy Capital Trust III (PECO Trust III). PETT is a separate legal entity from PECO; the debt issued by PETT is solely its obligation, and its assets, including transitional property, is not available to creditors of PECO. See “Variable Interest Entities” below. PECO accounts for its less than 20% owned investments under the cost method of accounting.
Reclassifications
Certain prior year amounts have been reclassified for comparative purposes. The reclassifications did not affect net income or shareholders’ equity.
Use of Estimates
The preparation of financial statements in conformity with accounting principles generally accepted in the United States (GAAP) requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. Areas in which significant estimates have been made include, but are not limited to, the accounting for unbilled revenues, derivatives, environmental costs, allowance for doubtful accounts, fixed asset depreciation, taxes and pension and other postretirement benefits.
304
PECO Energy Company and Subsidiary Companies
Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, except per share data unless otherwise noted)
Accounting for the Effects of Regulation
PECO is regulated by the Pennsylvania Public Utility Commission (PUC) under state public utility laws, the Federal Energy Regulatory Commission (FERC) under various Federal laws, and the Securities and Exchange Commission (SEC) under the Public Utility Holding Company Act of 1935 (PUHCA). PECO accounts for all of its regulated electric and gas operations in accordance with Financial Accounting Standards Board (FASB) Statement of Financial Accounting Standards (SFAS) No. 71, “Accounting for the Effects of Certain Types of Regulation,” (SFAS No. 71) which requires PECO to record in its financial statements the effects of the rate regulation to which these operations are currently subject. Use of SFAS No. 71 is applicable to the utility operations of PECO that meet the following criteria: (1) third-party regulation of rates; (2) cost-based rates; and (3) a reasonable assumption that all costs will be recoverable from customers through rates. PECO believes that it is probable that currently recorded regulatory assets and liabilities associated with these operations will be recovered or settled. If a separable portion of PECO’s business no longer meets the provisions of SFAS No. 71, PECO would be required to eliminate the financial statement effects of regulation for that portion.
Segment Information
PECO operates in one segment—energy delivery.
Variable Interest Entities
The FASB issued FASB Interpretation No. (FIN) 46 “Consolidation of Variable Interest Entities” (FIN 46) in January 2003 and issued its revision in FASB Interpretation No. 46-R “Consolidation of Variable Interest Entities” (FIN 46-R) in December 2003, which addressed the requirements for consolidating certain variable interest entities. FIN 46 was effective for PECO’s variable interest entities created after January 31, 2003 and FIN 46-R was effective December 31, 2003 for PECO’s other variable interest entities that are considered to be special-purpose entities. FIN 46-R applied to all other variable interest entities as of March 31, 2004.
PECO Trust IV, a financing trust of PECO created in May 2003, was deconsolidated from the financial statements of PECO pursuant to the provisions of FIN 46 as of July 1, 2003. As of December 31, 2004, the remaining financing trusts of PECO, including PECO Trust III (formed in April 1998) and PETT (formed in June 1998), were deconsolidated from the financial statements of PECO pursuant to the provisions of FIN 46-R. Amounts of $3.6 billion owed to these financing trusts were recorded as long-term debt due to PETT and long-term debt to other financing trusts within the Consolidated Balance Sheets at December 31, 2004. PECO recognized equity in losses related to these unconsolidated financing subsidiaries of $25 million for the year ended December 31, 2004.
This change in presentation had no significant affect on the results of operations or financial position of PECO. In accordance with FIN 46 and FIN 46-R, prior periods have not been restated. The maximum exposure to loss as a result of PECO’s involvement with the financing trusts is $87 million at December 31, 2004.
Revenues
Operating revenues are recorded as service is rendered or energy is delivered to customers. At the end of each month, PECO accrues an estimate for the unbilled amount of energy delivered or
305
PECO Energy Company and Subsidiary Companies
Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, except per share data unless otherwise noted)
services provided to its electric and gas customers. See Note 3—Accounts Receivable for further discussion.
Stock-Based Compensation
PECO participates in Exelon’s stock-based compensation plans. Exelon accounts for its stock-based compensation plans under the intrinsic method prescribed by Accounting Principles Board No. 25, “Accounting for Stock Issued to Employees” and related interpretations and follows the disclosure requirements of SFAS No. 123, “Accounting for Stock-Based Compensation” (SFAS No. 123), and SFAS No. 148, “Accounting for Stock-Based Compensation—Transition and Disclosure—an amendment of FASB Statement No. 123.” Accordingly, no compensation expense for stock options has been recognized within the Consolidated Statements of Income. The table below shows the effect on PECO’s net income for 2004, 2003 and 2002 had Exelon elected to account for its stock-based compensation plans using the fair-value method under SFAS No. 123:
| 2004 |
2003 |
2002 | |||||||
| Net income—as reported |
$ | 455 | $ | 473 | $ | 486 | |||
| Deduct: Total stock-based compensation expense determined under fair-value method for all awards, net of income taxes (a) |
3 | 3 | 13 | ||||||
| Pro forma net income |
$ | 452 | $ | 470 | $ | 473 | |||
| (a) | The fair value of options granted was estimated using a Black-Scholes option pricing model. |
Income Taxes
Deferred Federal and state income taxes are provided on all significant temporary differences between the book basis and the tax basis of assets and liabilities and for tax carryforwards. Investment tax credits previously utilized for income tax purposes have been deferred on PECO’s Consolidated Balance Sheets and are recognized in book income over the life of the related property.
Exelon and its subsidiaries, including PECO, file a consolidated return for Federal and certain state income tax returns. Income taxes of the Exelon consolidated group are allocated to PECO based on the separate return method. See Note 8—Income Taxes for further discussion.
PECO is a party to an agreement (Tax Sharing Agreement) with Exelon and other subsidiaries of Exelon that provides for the allocation of consolidated tax liabilities. The Tax Sharing Agreement generally provides that each party is allocated an amount of tax similar to that which would be owed had the party been separately subject to tax. Any net benefit attributable to the parent is reallocated to other members. That allocation is treated as a contribution to the capital of the party receiving the benefit.
Losses on Reacquired Debt
Recoverable losses on reacquired debt related to regulated operations are deferred and amortized to interest expense over the life of the new debt issued to finance the debt redemption consistent with rate recovery for rate-making purposes. Losses on reacquired debt that are not refinanced with new debt are recognized in PECO’s Consolidated Statements of Income as incurred.
306
PECO Energy Company and Subsidiary Companies
Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, except per share data unless otherwise noted)
Comprehensive Income
Comprehensive income includes all changes in equity during a period except those resulting from investments by and distributions to shareholders. Comprehensive Income is reflected in the Consolidated Statements of Changes in Shareholders’ Equity and the Consolidated Statements of Comprehensive Income.
Cash and Cash Equivalents
PECO considers all temporary cash investments purchased with an original maturity of three months or less to be cash equivalents.
Allowance for Doubtful Accounts
The allowance for doubtful accounts reflects PECO’s best estimate of probable losses in the accounts receivable balance. The allowance is based on known troubled accounts, historical experience and other currently available evidence. Customer accounts are generally considered delinquent if the amount billed is not received by the time the next bill is issued, typically monthly. Customer accounts are written off based upon approved regulatory or legislative requirements.
Inventories
Gas inventory includes the cost of stored natural gas and propane. PECO has several long-term storage contracts for natural gas as well as a liquefied natural gas storage facility. Gas inventory is recorded at the lower of cost or net realizable value using a weighted average cost methodology.
Marketable Securities
Marketable securities are classified as available-for-sale securities and are reported at fair value, with the unrealized gains and losses, net of tax, reported in other comprehensive income. At December 31, 2004 and 2003, PECO had no held-to-maturity or trading securities.
Purchased Gas Adjustment Clause
PECO’s natural gas rates are subject to a fuel adjustment clause designed to recover or refund the difference between the actual cost of purchased gas and the amount included in rates. Differences between the amounts billed to customers and the actual costs recoverable are deferred and recovered or refunded in future periods by means of prospective quarterly adjustments to rates, which are subject to periodic review by the PUC. At December 31, 2004 and 2003, deferred energy costs of $71 million and $81 million, respectively, were recorded in other current assets on PECO’s Consolidated Balance Sheets.
Property, Plant and Equipment
Property, plant and equipment is recorded at cost. PECO evaluates the carrying value of property, plant and equipment and other long-term assets for impairment whenever circumstances indicate the carrying value of those assets may not be recoverable under the provisions of SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets.” The cost of maintenance, repairs and minor replacements of property is charged to maintenance expense as incurred.
307
PECO Energy Company and Subsidiary Companies
Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, except per share data unless otherwise noted)
Upon retirement, the cost of regulated property, net of salvage, is charged to accumulated depreciation and removal costs reduce the related regulated liability in accordance with the composite method of depreciation. See Note 15—Supplemental Financial Information. For unregulated property, the cost and accumulated depreciation of property, plant and equipment retired or otherwise disposed of are removed from the related accounts and included in the determination of any gain or loss on disposition. See Note 4—Property, Plant and Equipment.
Capitalized Software Costs
Costs incurred during the application development stage of software projects that are developed or obtained for internal use are capitalized. At December 31, 2004 and 2003, net unamortized capitalized software costs totaled $46 million and $53 million, respectively. Such capitalized amounts are amortized ratably over the expected lives of the projects when they become operational, not to exceed ten years. During 2004, 2003, and 2002, PECO amortized capitalized software costs of $12 million, $15 million and $17 million, respectively.
Depreciation and Amortization
Depreciation, including a provision for estimated removal costs as authorized by the PUC, is provided over the estimated service lives of property, plant and equipment on a straight-line basis using the composite method. Annual depreciation provisions for financial reporting purposes, expressed as a percentage of average service life for each asset category, are presented in the table below:
| Asset Category |
2004 |
2003 |
2002 |
||||||
| Electric-transmission and distribution |
2.14 | % | 2.08 | % | 2.09 | % | |||
| Gas |
2.52 | % | 2.38 | % | 2.13 | % | |||
| Common—gas and electric |
4.60 | % | 7.53 | % | 6.40 | % |
Amortization of regulatory assets is provided over the recovery period as specified in the related regulatory agreement.
Allowance for Funds Used During Construction
Allowance for Funds Used During Construction (AFUDC) is the cost, during the period of construction, of debt and equity funds used to finance construction projects for regulated operations. AFUDC of $2 million, $1 million and $1 million in 2004, 2003 and 2002, respectively, was recorded as a charge to construction work in progress and as a non-cash credit to AFUDC which is included in other income and deductions within the Consolidated Statements of Income. The rates used for capitalizing AFUDC are computed under a method prescribed by regulatory authorities.
Derivative Financial Instruments
PECO enters into derivatives to manage its exposure to fluctuations in interest rates, changes in interest rates related to planned future debt issuances and exposure to changes in the fair value of outstanding debt. PECO’s derivative activities are in accordance with Exelon’s Risk Management Policy (RMP).
308
PECO Energy Company and Subsidiary Companies
Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, except per share data unless otherwise noted)
PECO accounts for derivative financial instruments pursuant to SFAS No. 133, “Accounting for Derivatives and Hedging Activities” (SFAS No. 133). Under the provisions of SFAS No. 133, all derivatives are recognized on the balance sheet at their fair value unless they qualify for a normal purchases and normal sales exception. Derivatives recorded at fair value on the balance sheet are presented as current or noncurrent mark-to-market derivative assets or liabilities. Changes in the fair value of the derivative financial instrument are recognized in earnings unless specific hedge accounting criteria are met, in which case those changes are recorded in earnings as an offset to the changes in fair value of the exposure being hedged or deferred in accumulated other comprehensive income and recognized in earnings as hedged transactions occur. Amounts recorded in earnings are included in other, net on the consolidated statements of income.
A derivative financial instrument can be designated as a hedge of the fair value of a recognized asset or liability or of an unrecognized firm commitment (fair-value hedge), or a hedge of a forecasted transaction or the variability of cash flows to be received or paid related to a recognized asset or liability (cash-flow hedge). Changes in the fair value of a derivative that is highly effective as, and is designated and qualifies as a fair-value hedge, are recognized in earnings as offsets to the changes in fair value of the exposure being hedged. Changes in the fair value of a derivative that is highly effective as, and is designated as and qualifies as, a cash-flow hedge are deferred in accumulated other comprehensive income and are recognized in earnings as the hedged transactions occur. Any ineffectiveness is recognized in earnings immediately. On an ongoing basis, the Company assesses the hedge effectiveness of all derivatives that are designated as hedges for accounting purposes in order to determine that each derivative continues to be highly effective in offsetting changes in fair values or cash flows of hedged items. If it is determined that the derivative is not highly effective as a hedge, hedge accounting will be discontinued prospectively.
Severance Benefits
PECO participates in Exelon’s ongoing severance plans, which are accounted for in accordance with SFAS No. 112, “Employer’s Accounting for Postemployment Benefits, an amendment of FASB Statements No. 5 and 43” (SFAS No. 112) and SFAS No. 88, “Employers’ Accounting for Settlements and Curtailments of Defined Benefit Pension Plans and for Termination Benefits.” Amounts associated with severance benefits that are considered probable and can be reasonably estimated are accrued. See Note 5—Severance Accounting for further discussion of PECO’s accounting for severance benefits.
Retirement Benefits
PECO participates in Exelon’s defined benefit pension plans and postretirement welfare benefit plans. Exelon’s defined benefit pension plans and postretirement welfare benefit plans are accounted for in accordance with SFAS No. 87, “Employer’s Accounting for Pensions” (SFAS No. 87), SFAS No. 106, “Employers’ Accounting for Postretirement Benefits Other than Pensions” (SFAS No. 106) and FASB Staff Position (FSP) FAS 106-2, “Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003” (FSP FAS 106-2), and are disclosed in accordance with SFAS No. 132, “Employers’ Disclosures about Pensions and Other Postretirement Benefits—an Amendment of FASB Statements No. 87, 88, and 106” (revised 2003) (SFAS No. 132). See Note 10—Retirement Benefits for further discussion of retirement benefits.
FSP FAS 106-2. Through Exelon’s postretirement benefit plans, PECO provides retirees with prescription drug coverage. On December 8, 2003 the Medicare Prescription Drug, Improvement and
309
PECO Energy Company and Subsidiary Companies
Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, except per share data unless otherwise noted)
Modernization Act of 2003 (the Prescription Drug Act) was enacted. The Prescription Drug Act introduced a prescription drug benefit under Medicare as well as a Federal subsidy to sponsors of retiree health care benefit plans that provide a benefit that is at least actuarially equivalent to the Medicare prescription drug benefit. Management believes the prescription drug benefit provided under Exelon’s postretirement benefit plans is at least actuarially equivalent to the Medicare prescription drug benefit. In response to the enactment of the Prescription Drug Act, in May 2004, the FASB issued FSP FAS 106-2, which provided transition guidance for accounting for the effects of the Prescription Drug Act and superseded FSP FAS 106-1, which had been issued in January 2004. FSP FAS 106-1 permitted a plan sponsor of a postretirement health care plan that provides a prescription drug benefit to make a one-time election to defer the accounting for the effects of the Prescription Drug Act. PECO made the one-time election allowed by FSP FAS 106-1 during the first quarter of 2004. During the second quarter of 2004, PECO early adopted the provisions of FSP FAS 106-2, resulting in a reduction in net periodic postretirement benefit cost. Historical financial information for the three months ended March 31, 2004 has been adjusted in Note 17—Quarterly Data (Unaudited) and will be adjusted when presented for comparative purposes in future periods to reflect a reduction in net periodic postretirement benefit cost due to the adoption of FSP FAS 106-2.
New Accounting Pronouncements
SFAS No. 151. In November 2004, the FASB issued FASB Statement No. 151, “Inventory Costs—an amendment of ARB No. 43, Chapter 4” (SFAS No. 151), which is the result of its efforts to converge U.S. accounting standards for inventories with International Accounting Standards. SFAS No. 151 requires abnormal amounts of idle facility expense, freight, handling costs and wasted material or spoilage to be recognized as current-period charges. It also requires that allocation of fixed production overheads to the costs of conversion be based on the normal capacity of the production facilities. SFAS No. 151 will be effective for inventory costs incurred during fiscal years beginning after June 15, 2005. PECO is assessing the impact SFAS No. 151 will have on its consolidated financial statements.
SFAS No. 123-R. In December 2004, the FASB issued FASB Statement No. 123 (revised 2004), “Share-Based Payment” (SFAS No. 123-R). SFAS No. 123-R replaces SFAS No. 123 and supersedes APB No. 25. SFAS No. 123-R requires that the compensation cost relating to share-based payment transactions be recognized in the financial statements. That cost will be measured based on the fair value of the equity or liability instruments issued. Exelon will no longer be permitted to follow the intrinsic value accounting method of APB No. 25, which resulted in no expense being recorded for stock option grants for which the strike price was equal to the fair value of the underlying stock on the date of grant. Exelon has not elected to early adopt SFAS No. 123-R. As a result, SFAS No. 123-R will be effective for Exelon in the third quarter of 2005 and will apply to all of Exelon’s outstanding unvested share-based payment awards as of July 1, 2005 and all prospective awards. Exelon is assessing the impact SFAS No. 123-R will have on its consolidated financial statements and which of three transition methods allowed by SFAS No. 123-R will be elected.
SFAS No. 153. In December 2004, the FASB issued FASB Statement No. 153, “Exchanges of Nonmonetary Assets, an amendment of APB Opinion No. 29, ‘Accounting for Nonmonetary Transactions’” (SFAS No. 153). Previously, APB Opinion No. 29 had required that the accounting for an exchange of a productive asset for a similar productive asset or an equivalent interest in the same or similar productive asset should be based on the recorded amount of the asset relinquished. The amendments made by SFAS No. 153 are based on the principle that exchanges of nonmonetary
310
PECO Energy Company and Subsidiary Companies
Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, except per share data unless otherwise noted)
assets should be measured based on the fair value of the assets exchanged. Further, the amendments eliminate the narrow exception for nonmonetary exchanges of similar productive assets and replace it with a broader exception for exchanges of nonmonetary assets that do not have commercial substance. SFAS No. 153 will be effective for PECO in the third quarter of 2005 and earlier application is permitted for nonmonetary asset exchanges occurring after the issuance of SFAS No. 153. The provisions of SFAS No. 153 are applied prospectively. PECO is assessing the impact SFAS No. 153 will have on its consolidated financial statements.
FSP FAS 109-1 and FSP FAS 109-2. In December 2004, the FASB issued FSP FAS 109-1, “Application of FASB Statement No. 109, ‘Accounting for Income Taxes,’ to the Tax Deduction on Qualified Production Activities Provided by the American Jobs Creation Act of 2004” (FSP FAS 109-1) and FSP FAS 109-2, “Accounting and Disclosure Guidance for the Foreign Earnings Repatriation Provisions within the American Jobs Creation Act of 2004” (FSP FAS 109-2). FSP FAS 109-1 and FSP FAS 109-2 were effective upon issuance. The American Jobs Creation Act of 2004 (Act), signed into law on October 22, 2004, provided, generally, for a tax deduction for domestic manufacturing activities of up to nine percent (when fully phased-in) of the lesser of “qualified production activities income,” as defined in the Act, or taxable income. FSP FAS 109-1 clarified that the tax deduction for domestic manufacturing activities under the Act should be accounted for as a special deduction in accordance with SFAS No. 109, “Accounting for Income Taxes” (SFAS No. 109). The Act also provided a special limited-time dividends received deduction on the repatriation of certain foreign earnings to a U.S. taxpayer, provided certain criteria are met. FSP FAS 109-2 provides a registrant more time to evaluate the Act’s impact on the registrant’s plan for reinvestment or repatriation of certain foreign earnings for purposes of applying SFAS No. 109. PECO is assessing the impact, if any, that the Act and these standards may have on its consolidated financial statements in future periods.
2. Regulatory Issues
Through and Out Rates. In November 2004, the FERC issued two orders authorizing PECO to recover from various entities revenue representing amounts PECO will lose as a result of the elimination of through and out (T&O) charges, for energy flowing across PECO’s transmission system, that were terminated pursuant to the FERC orders effective December 1, 2004. The collection of this revenue will be over a transitional period of December 1, 2004 through March 31, 2006. Several parties have sought rehearing of the FERC orders and there likely will be appeals filed in the matter after the rehearing order is issued. During 2004 prior to the termination of T&O charges, PECO collected net T&O charges of approximately $3 million. As a result of this proceeding, PECO may become a net payer of these charges. The ultimate outcome of this proceeding is uncertain and may have a material adverse effect on PECO’s financial condition, results of operations or cash flows.
Customer Choice. All PECO customers may choose to purchase energy from an alternative electric supplier. As of December 31, 2004, approximately 101,500 customers, representing approximately 8% of PECO’s annual retail kilowatthour sales, had elected to purchase their electric energy from an alternative electric supplier. Customers who receive energy from an alternative electric supplier continue to pay delivery and competitive transition charges (CTCs).
PECO cannot predict the long-term impact of customer choice on its result of operations.
Rate Limitations. Pursuant to the settlement agreement with the PUC related to the merger of PECO, Unicom Corporation (Unicom), the former parent company of ComEd, and Exelon (PECO /
311
PECO Energy Company and Subsidiary Companies
Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, except per share data unless otherwise noted)
Unicom Merger), PECO is subject to agreed-upon electric service rate reductions of $200 million, in aggregate, for the period January 1, 2002 through December 31, 2005, including $40 million in each of 2004 and 2005. As required by the 1998 electric restructuring settlement and as modified by the PECO / Unicom Merger-related settlement agreement, PECO is subject to rate caps (subject to limited exceptions for significant increases in Federal or state income taxes or other significant changes in law or regulation that do not allow PECO to earn a fair rate of return) on its transmission and distribution rates through December 31, 2006, and on its energy rates through December 31, 2010.
Nuclear Decommissioning Costs. Effective January 1, 2004, the PUC approved an adjustment to PECO’s nuclear decommissioning cost adjustment clause permitting PECO to recover an additional $3.6 million annually, or $33 million compared to $29 million previously. The amounts recovered by PECO are remitted to Exelon Generation Company, LLC (Generation) upon collection.
3. Accounts Receivable
Customer accounts receivable at December 31, 2004 and 2003 included unbilled operating revenues of $143 million. The allowance for uncollectible accounts at December 31, 2004 and 2003 was $52 million and $72 million, respectively.
PECO is party to an agreement with a financial institution under which it can sell or finance with limited recourse an undivided interest, adjusted daily, in up to $225 million of designated accounts receivable until November 2005. At December 31, 2004, PECO had sold a $225 million interest in accounts receivable, consisting of a $179 million interest in accounts receivable which PECO accounted for as a sale under SFAS No. 140, “Accounting for Transfers and Servicing of Financial Assets and Extinguishment of Liabilities—a Replacement of FASB Statement No. 125,” (SFAS No. 140) and a $46 million interest in special-agreement accounts receivable which was accounted for as a long-term note payable and reflected on the consolidated balance sheet as long-term debt due within one year. At December 31, 2003, PECO had sold a $225 million interest in accounts receivable, consisting of a $176 million interest in accounts receivable which PECO accounted for as a sale under SFAS No. 140 and a $49 million interest in special-agreement accounts receivable which was accounted for as a long-term note payable (see Note 7—Long-Term Debt). PECO retains the servicing responsibility for these receivables. The agreement requires PECO to maintain the $225 million interest, which, if not met, requires cash, which would otherwise be received by PECO under this program, to be held in escrow until the requirement is met. At December 31, 2004 and 2003, PECO met this requirement and was not required to make any cash deposits.
4. Property, Plant and Equipment
A summary of property, plant and equipment by category as of December 31, 2004 and 2003 is as follows:
| Asset Category |
2004 |
2003 | ||||
| Electric—transmission and distribution |
$ | 4,501 | $ | 4,347 | ||
| Gas—transmission and distribution |
1,436 | 1,381 | ||||
| Common |
501 | 492 | ||||
| Construction work in progress |
37 | 65 | ||||
| Other property, plant and equipment |
19 | 19 | ||||
| Total property, plant and equipment |
6,494 | 6,304 | ||||
| Less accumulated depreciation |
2,165 | 2,048 | ||||
| Property, plant and equipment, net |
$ | 4,329 | $ | 4,256 | ||
312
PECO Energy Company and Subsidiary Companies
Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, except per share data unless otherwise noted)
PECO’s depreciation expense, which is included in cost of service for rate purposes, includes the cost of dismantling and removing plant from service upon retirement. For more information, see Note 15—Supplemental Information.
PECO has undivided ownership interests in jointly owned electric transmission plant comprised of a 22.00% ownership of 127 miles of 500,000 voltage lines located in Pennsylvania and a 42.55% ownership of 151 miles of 500,000 voltage lines located in Delaware and New Jersey. Gross plant and accumulated depreciation balances for these assets were $60 million and $27 million, respectively, at December 31, 2004 and $60 million and $26 million, respectively, at December 31, 2003. PECO’s undivided ownership interests are financed with PECO funds and all operations are accounted for as if such participating interests were wholly owned facilities. PECO’s share of direct expenses of the jointly owned plant is included in the corresponding operating expenses on the Consolidated Statements of Income.
5. Severance Accounting
PECO provides severance and health and welfare benefits to terminated employees pursuant to pre-existing severance plans maintained by Exelon primarily based upon each individual employee’s years of service with PECO and compensation level.
During the years ended December 31, 2004 and 2003, PECO identified approximately 55 and 165 positions, respectively, for elimination. As of December 31, 2004, approximately 15 of the identified positions had not been eliminated. PECO recorded charges for salary continuance severance of $3 million and $16 million (before income taxes) during 2004 and 2003, respectively, which represented salary continuance severance costs that were probable and could be reasonably estimated as of the end of the year. During 2004 and 2003, PECO recorded charges of $2 million and $4 million (before income taxes), respectively, associated with special health and welfare severance benefits. Additionally, PECO incurred curtailment costs in 2004 and 2003 associated with its pension and postretirement benefit plans of $2 million and $10 million (before income taxes), respectively, as a result of personnel reductions. In total, PECO recorded charges of $7 million and $30 million (before income taxes) in 2004 and 2003, respectively. See Note 10—Retirement Benefits for a description of the curtailment charges for the pension and postretirement benefit plans.
PECO based its estimate of the number of positions to be eliminated on management’s current plans and its ability to determine the appropriate staffing levels to effectively operate the business. PECO may incur further severance costs if additional positions are identified for elimination. These costs will be recorded in the period in which the costs can be reasonably estimated.
The following table details PECO’s total salary continuance severance costs, recorded as an operating and maintenance expense, for the years ended December 31, 2004 and 2003. During 2002, no amounts were recorded as severance expense.
| Salary continuance severance charges |
|||
| Expense recorded—2004 |
$ | 3 | |
| Expense recorded—2003 |
16 | ||
| Expense recorded—2002 |
— | ||
313
PECO Energy Company and Subsidiary Companies
Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, except per share data unless otherwise noted)
The following table provides a roll forward of PECO’s salary continuance severance obligation from January 1, 2003 through December 31, 2004. PECO had no severance charges or cash payments during 2002.
| Salary continuance severance obligation |
||||
| Balance as of January 1, 2003 |
$ | — | ||
| Severance charges recorded |
16 | |||
| Cash payments |
(2 | ) | ||
| Other adjustments |
— | |||
| Balance as of January 1, 2004 |
14 | |||
| Severance charges recorded |
3 | |||
| Cash payments |
(10 | ) | ||
| Other adjustments |
— | |||
| Balance as of December 31, 2004 |
$ | 7 | ||
6. Short-Term Debt
| 2004 |
2003 |
2002 |
||||||||||
| Average borrowings |
$ | 23 | $ | 168 | $ | 155 | ||||||
| Maximum borrowings outstanding |
207 | 582 | 612 | |||||||||
| Average interest rates, computed on a daily basis |
1.08 | % | 1.23 | % | 1.77 | % | ||||||
| Average interest rates, at December 31 |
— | 1.02 | % | 1.51 | % | |||||||
At December 31, 2003, Exelon, along with PECO, Commonwealth Edison Company (ComEd) and Generation, participated with a group of banks in a $750 million 364-day unsecured revolving credit agreement and a $750 million three-year unsecured revolving credit agreement. On July 16, 2004, the $750 million 364-day facility was replaced with a $1 billion unsecured revolving facility maturing on July 16, 2009, and the $750 million three-year facility was reduced to $500 million maturing on October 31, 2006. Both revolving credit agreements are used principally to support the commercial paper programs at Exelon, PECO, ComEd and Generation and to issue letters of credit.
At December 31, 2004, PECO’s aggregate sublimit under the credit agreements was $100 million. Sublimits under the credit agreements can change upon written notification to the bank group. PECO had approximately $100 million of unused bank commitments, net of outstanding letters of credit, under the credit agreements at December 31, 2004. PECO did not have any commercial paper outstanding at December 31, 2004. At December 31, 2003, commercial paper outstanding was $46 million. Interest rates on advances under the credit facilities are based on either prime or the London Interbank Offering Rate (LIBOR) plus an adder based on the credit rating of the borrower as well as the total outstanding amounts under the agreement at the time of borrowing. The maximum adder is 170 basis points.
The credit agreements require PECO to maintain a minimum cash from operations to interest expense ratio for the twelve-month period ended on the last day of any quarter. The ratio excludes revenues and interest expenses attributable to securitization debt, certain changes in working capital and distributions on preferred securities of subsidiaries. For the twelve-month period ended December 31, 2004, PECO’s minimum cash from operations to interest expense ratio was 2.25 to 1. At December 31, 2004, PECO was in compliance with this threshold.
314
PECO Energy Company and Subsidiary Companies
Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, except per share data unless otherwise noted)
7. Long-Term Debt
| December 31, 2004 |
December 31, |
||||||||||||
| Rates |
Maturity Date |
2004 |
2003 |
||||||||||
| Long-term debt |
|||||||||||||
| First Mortgage Bonds (a) (b): |
|||||||||||||
| Fixed rates |
3.50%-5.95 | % | 2008-2034 | $ | 1,000 | $ | 1,000 | ||||||
| Floating rates |
1.70%-1.80 | % | 2012 | 154 | 154 | ||||||||
| Pollution control notes: |
|||||||||||||
| Fixed rates |
— | — | — | 157 | |||||||||
| Notes payable—accounts receivable agreement |
2.50 | % | 2005 | 46 | 49 | ||||||||
| Other |
— | — | — | 1 | |||||||||
| Total long-term debt (c) |
1,200 | 1,361 | |||||||||||
| Unamortized debt discount and premium, net |
(1 | ) | (2 | ) | |||||||||
| Long-term debt due within one year |
(46 | ) | — | ||||||||||
| Long-term debt |
$ | 1,153 | $ | 1,359 | |||||||||
| Long-term debt due to PETT (d) (e) |
|||||||||||||
| Series 1999-A: |
|||||||||||||
| Fixed rates |
6.05%-6.13 | % | 2005-2008 | $ | 1,890 | $ | 2,138 | ||||||
| Floating rates |
2.98 | % | 2007 | 10 | 155 | ||||||||
| Series 2000-A |
7.63%-7.65 | % | 2009 | 750 | 750 | ||||||||
| Series 2001 |
6.52 | % | 2010 | 806 | 806 | ||||||||
| Long-term debt due to PETT |
3,456 | 3,849 | |||||||||||
| Long-term debt due to PETT within one year |
(165 | ) | (153 | ) | |||||||||
| Total long-term debt due to PETT |
$ | 3,291 | $ | 3,696 | |||||||||
| Long-term debt to other financing trusts (d) (e) |
|||||||||||||
| Subordinated debentures to PECO Trust III |
7.38 | % | 2028 | $ | 81 | $ | 81 | ||||||
| Subordinated debentures to PECO Trust IV |
5.75 | % | 2033 | 103 | 103 | ||||||||
| Total long-term debt to other financing trusts |
$ | 184 | $ | 184 | |||||||||
| (a) | Utility plant of PECO is subject to the lien of the PECO mortgage indenture. |
| (b) | Includes first mortgage bonds issued under the PECO mortgage indenture securing pollution control notes. |
| (c) | Long-term debt maturities in the periods 2005 through 2009 and thereafter are as follows: |
| 2005 |
$ | 46 | |
| 2006 |
— | ||
| 2007 |
— | ||
| 2008 |
450 | ||
| 2009 |
— | ||
| Thereafter |
704 | ||
| Total |
$ | 1,200 | |
| (d) | Effective July 1, 2003, PECO Trust IV, a financing subsidiary created in May 2003, was deconsolidated from the financial statements of PECO in conjunction with the adoption of FIN 46. Effective December 31, 2003, PECO Trust III and PETT were deconsolidated from the financial statements in conjunction with the adoption of FIN 46-R. Amounts owed to PETT have been recorded as debt to PETT within the Consolidated Balance Sheets, and interest owed to PECO Trust IV has been recorded as interest expense to affiliates within the Consolidated Statements of Income. |
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PECO Energy Company and Subsidiary Companies
Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, except per share data unless otherwise noted)
| (e) | Long-term debt to PETT and other financing trusts maturities in the periods 2005 through 2009 and thereafter are as follows: |
| 2005 |
$ | 165 | |
| 2006 |
520 | ||
| 2007 |
640 | ||
| 2008 |
625 | ||
| 2009 |
700 | ||
| Thereafter |
990 | ||
| Total |
$ | 3,640 | |
Debt issuances. During 2004, PECO issued $75 million of 5.90% First Mortgage Bonds due May 1, 2034.
Debt Retirements and Redemptions. Payments were made on the following long-term debt during 2004:
| Type |
Rate |
Maturity |
Amount | |||||
| Pollution Control Revenue Bonds |
5.20 | % | April 1, 2021 | $ | 51 | |||
| Pollution Control Revenue Bonds |
5.20 | % | October 1, 2030 | 92 | ||||
| Pollution Control Revenue Bonds |
5.30 | % | October 1, 2034 | 14 | ||||
| First Mortgage Bonds |
6.375 | % | August 15, 2005 | 75 | ||||
| Notes payable—accounts receivable agreement |
3 | |||||||
| Total payments |
$ | 235 | ||||||
During 2004, PECO made payments of $393 million related to its obligation to PETT.
See Note 11—Fair Value of Financial Assets and Liabilities for additional information regarding interest-rate swaps. See Note 12—Preferred Securities for additional information regarding preferred stock.
8. Income Taxes
Income tax expense (benefit) is comprised of the following components:
| For the Year Ended December 31, |
||||||||||||
| 2004 |
2003 |
2002 |
||||||||||
| Included in operations: |
||||||||||||
| Federal |
||||||||||||
| Current |
$ | 311 | $ | 257 | $ | 305 | ||||||
| Deferred |
(59 | ) | (15 | ) | (51 | ) | ||||||
| Investment tax credit amortization |
(2 | ) | (2 | ) | (3 | ) | ||||||
| State |
||||||||||||
| Current |
36 | 46 | 46 | |||||||||
| Deferred |
(37 | ) | (33 | ) | (38 | ) | ||||||
| Total income tax expense |
$ | 249 | $ | 253 | $ | 259 | ||||||
316
PECO Energy Company and Subsidiary Companies
Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, except per share data unless otherwise noted)
The effective income tax rate varies from the U.S. Federal statutory rate principally due to the following:
| For the Year Ended December 31, |
|||||||||
| 2004 |
2003 |
2002 |
|||||||
| U.S. Federal statutory rate |
35.0 | % | 35.0 | % | 35.0 | % | |||
| Increase (decrease) due to: |
|||||||||
| State income taxes, net of Federal income tax benefit |
(0.1 | ) | 1.1 | 0.7 | |||||
| Plant basis differences |
0.6 | (1.1 | ) | (1.5 | ) | ||||
| Amortization of investment tax credit |
(0.4 | ) | (0.4 | ) | (0.3 | ) | |||
| Other, net |
0.2 | 0.2 | 0.9 | ||||||
| Effective income tax rate |
35.3 | % | 34.8 | % | 34.8 | % | |||
The tax effects of temporary differences giving rise to significant portions of PECO’s deferred tax assets and liabilities as of December 31, 2004 and 2003 are presented below:
| 2004 |
2003 |
|||||||
| Deferred tax liabilities: |
||||||||
| Stranded cost recovery |
$ | 1,632 | $ | 1,784 | ||||
| Plant basis difference |
1,295 | 1,253 | ||||||
| Deferred debt refinancing costs |
17 | 20 | ||||||
| Unrealized gain on derivative financial instruments |
9 | 11 | ||||||
| Total deferred tax liabilities |
2,953 | 3,068 | ||||||
| Deferred tax assets: |
||||||||
| Deferred pension and postretirement obligations |
(51 | ) | (49 | ) | ||||
| Other, net |
(92 | ) | (97 | ) | ||||
| Total deferred tax assets |
(143 | ) | (146 | ) | ||||
| Deferred income tax liabilities (net) on the Consolidated Balance Sheets |
$ | 2,810 | $ | 2,922 | ||||
In accordance with regulatory treatment of certain temporary differences, PECO has recorded a net regulatory asset associated with deferred income taxes, pursuant to SFAS No. 71 and SFAS No. 109 “Accounting for Income Taxes,” of $747 million and $762 million at December 31, 2004 and 2003, respectively. See Note 15—Supplemental Financial Information for further discussion of PECO’s regulatory asset associated with deferred income taxes.
Certain PECO tax returns are under review at the audit or appeals level of the Internal Revenue Service (IRS) and certain state authorities. These reviews by governmental taxing authorities are not expected to have an adverse impact on the financial condition or results of operations at PECO.
In 2004 and 2003, PECO received $21 million and $7 million, respectively, from Exelon related to PECO’s allocation of tax benefits under the Tax Sharing Agreement.
317
PECO Energy Company and Subsidiary Companies
Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, except per share data unless otherwise noted)
9. Nuclear Decommissioning
As a result of a corporate restructuring in 2001, assets and liabilities associated with nuclear power plants previously owned by PECO were transferred to Generation. Pursuant to Nuclear Regulatory Commission regulations, Generation has an obligation to decommission these nuclear power plants. Based on the actual or anticipated extended license lives of the nuclear plants, expenditures are expected to occur primarily during the period 2034 through 2056 for plants currently in operation. Generation currently recovers costs for decommissioning nuclear generating stations previously owned by PECO through regulated rates collected by PECO. The amounts recovered from customers are deposited in trust accounts by Generation and invested for funding of future decommissioning costs of these nuclear generating stations.
SFAS No. 143, “Accounting for Asset Retirement Obligations” (SFAS No. 143) provides accounting requirements for retirement obligations (whether statutory, contractual or as a result of principles of promissory estoppel) associated with tangible long-lived assets. PECO was required to adopt SFAS No. 143 as of January 1, 2003.
Generation was required to re-measure the decommissioning liabilities at fair value using the methodology prescribed by SFAS No. 143. The transition provisions of SFAS No. 143 required Exelon to apply this remeasurement back to the historical periods in which asset retirement obligations (AROs) were incurred, resulting in a remeasurement of these obligations at the date the related assets were acquired by Generation.
For the nuclear power plants formerly owned by PECO, the SFAS No. 143 ARO calculation yielded decommissioning obligations greater than the corresponding trust assets at January 1, 2003. As such, a regulatory asset of $20 million and a corresponding payable to Generation were recorded upon adoption of SFAS No. 143 at PECO. Due to additional contributions to and increases in the market value of the decommissioning trusts, as of December 31, 2004, the trust assets exceeded the ARO by $46 million. This amount was recorded as a regulatory liability with a corresponding receivable from Generation. Generation and PECO believe that all of the decommissioning assets, prospective earnings thereon and annual collections from PECO ratepayers, which increased to approximately $33 million from $29 million beginning in 2004, will be required to decommission the former PECO plants. Generation and PECO also expect the regulatory liability will be reduced to zero at the conclusion of the decommissioning of the former PECO plants. See Note 2—Regulatory Issues for more information regarding the annual collections from PECO ratepayers.
10. Retirement Benefits
PECO participates in defined benefit pension plans and postretirement welfare benefit plans sponsored by Exelon. Substantially all PECO employees are eligible to participate in these plans. Benefits under these plans generally reflect each employee’s compensation, years of service, and age at retirement.
The prepaid pension asset and non-pension postretirement benefits obligation on PECO’s Consolidated Balance Sheets reflects PECO’s obligation from and to the plan sponsor, Exelon. Employee-related assets and liabilities, including both pension and SFAS No. 106, “Employers’ Accounting for Postretirement Benefits Other than Pensions,” postretirement welfare assets and liabilities, were allocated by Exelon to its subsidiaries based on the number of active employees as of
318
PECO Energy Company and Subsidiary Companies
Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, except per share data unless otherwise noted)
January 1, 2001 as part of Exelon’s corporate restructuring. Exelon allocates the components of pension and postretirement benefits expense to the participating employers based upon several factors, including the percentage of active employees in each participating unit.
See Note 15—Retirement Benefits of Exelon’s Notes to Consolidated Financial Statements for pension and other postretirement benefits information for the Exelon plans.
Approximately $32 million, $49 million, and $31 million were included in capital and operating and maintenance expense, excluding curtailment and special termination costs, in 2004, 2003 and 2002, respectively, for PECO’s allocated portion of Exelon’s pension and postretirement benefit expense. The 2004 amounts include a reduction in net periodic post-retirement benefit cost resulting from the adoption of FSP FAS 106-2. PECO contributed $14 million in 2004 and $49 million annually in 2003 and 2002 to Exelon-sponsored plans. PECO expects to contribute approximately $104 million to the pension benefit plans in 2005.
During 2004 and 2003, PECO recognized curtailment charges of $2 million and $10 million (before income taxes), respectively, associated with an overall reduction in participants in Exelon’s pension and postretirement benefit plans due to employee reductions associated with The Exelon Way. During 2004 and 2003, PECO recognized special termination benefit costs of $2 million and $4 million (before income taxes), respectively.
PECO participates in a 401(k) savings plan sponsored by Exelon. The plan allows employees to contribute a portion of their pre-tax income in accordance with specified guidelines. PECO matches a percentage of the employee contribution up to certain limits. The cost of PECO’s matching contribution to the savings plan totaled $6 million in 2004 and $7 million annually in 2003 and 2002.
11. Fair Value of Financial Assets and Liabilities
The carrying amounts and fair values of PECO’s financial assets and liabilities as of December 31, 2004 and 2003 were as follows:
| 2004 |
2003 | |||||||||||
| Carrying Amount |
Fair Value |
Carrying Amount |
Fair Value | |||||||||
| Non-derivatives: |
||||||||||||
| Liabilities |
||||||||||||
| Long-term debt (including amounts due within one year) |
$ | 1,199 | $ | 1,227 | $ | 1,359 | $ | 1,380 | ||||
| Long-term debt to PETT (including amounts due within one year) (a) |
3,456 | 3,779 | 3,849 | 4,215 | ||||||||
| Long-term debt to other financing trusts (including amounts due within one year) (a) |
184 | 193 | 184 | 189 | ||||||||
| (a) | Effective July 1, 2003, PECO Trust IV was deconsolidated from the financial statements of PECO. Effective December 31, 2003, PETT and PECC were deconsolidated from the financial statements of PECO. The deconsolidation of these entities is in connection with the adoption of FIN 46-R. Amounts owed to PECO Trust IV, PETT and PECC were recorded as long-term debt to PETT and long-term debt to other financing trusts within the Consolidated Balance Sheets. |
Fair Value of Financial Instruments. As of December 31, 2004 and 2003, PECO’s carrying amounts of cash and cash equivalents, accounts receivable, accounts payable and accrued liabilities
319
PECO Energy Company and Subsidiary Companies
Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, except per share data unless otherwise noted)
are representative of fair value because of the short-term nature of these instruments. Fair values of the long-term debt are determined by an external valuation model which is based on a conventional discounted cash flow methodology and utilizes assumptions of current market pricing curves. The fair value of PECO’s interest-rate swaps is determined using external dealer prices or internal valuation models which utilize assumptions of available market pricing curves.
Interest-Rate Swaps. PECO has interest-rate swaps in place to satisfy counterparty credit requirements in regards to the floating-rate series of transition bonds which are mirror swaps of each other. These swaps are not designated as cash-flow hedges; therefore, they are required to be marked-to-market if there is a difference in their values. Since these swaps are offsetting each other, a mark-to-market adjustment is not expected to occur.
During 2004, PECO entered into a forward-starting interest-rate swap in the aggregate notional amount of $75 million to lock in interest-rate levels in anticipation of a future financing. This interest-rate swap was designated as a cash-flow hedge. In connection with a bond issuance in 2004, PECO settled this forward-starting interest-rate swap resulting in a $5 million pre-tax gain recorded in other comprehensive income, a component of shareholders’ equity, which is being amortized over the life of the related debt to interest expense.
As of December 31, 2004, $7 million of deferred net gains on derivative instruments accumulated in other comprehensive income are expected to be reclassified to interest expense during the next twelve months. Amounts in accumulated other comprehensive income related to interest-rate cash flows are reclassified into earnings when the interest payment occurs.
At December 31, 2004 and 2003, the aggregate unamortized net gain on the settlements of swap transactions was $21 million and $35 million, respectively, recorded in accumulated other comprehensive income.
Credit Risk Associated with Financial Instruments. Non-derivative financial instruments that potentially subject PECO to concentrations of credit risk consist principally of cash equivalents and customer accounts receivable. PECO places its cash equivalents with high-credit quality financial institutions. Generally, such investments are in excess of the Federal Deposit Insurance Corporation limits. Concentrations of credit risk with respect to customer accounts receivable are limited due to PECO’s large number of customers and their dispersion across many industries.
PECO would also be exposed to credit-related losses in the event of non-performance by counterparties that issue derivative instruments. The credit exposure of derivative contracts is represented by the fair value of contracts at the reporting date. The notional amount of derivatives do not represent amounts that are exchanged by the parties and, thus, are not a measure of PECO’s exposure. The amounts exchanged are calculated on the basis of the notional or contract amounts, as well as on the other terms of the derivatives, which relate to interest rates and the volatility of these rates.
320
PECO Energy Company and Subsidiary Companies
Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, except per share data unless otherwise noted)
12. Preferred Securities
At December 31, 2004 and 2003, cumulative preferred stock of PECO, no par value, consisted of 15,000,000 shares authorized and the outstanding amounts set forth below:
| Current Redemption Price (a) |
December 31, | ||||||||||||
| 2004 |
2003 |
2004 |
2003 | ||||||||||
| Shares Outstanding |
Dollar Amount | ||||||||||||
| Series (without mandatory redemption) |
|||||||||||||
| $4.68 (Series D) |
$ | 104.00 | 150,000 | 150,000 | $ | 15 | $ | 15 | |||||
| $4.40 (Series C) |
112.50 | 274,720 | 274,720 | 27 | 27 | ||||||||
| $4.30 (Series B) |
102.00 | 150,000 | 150,000 | 15 | 15 | ||||||||
| $3.80 (Series A) |
106.00 | 300,000 | 300,000 | 30 | 30 | ||||||||
| Total preferred stock |
874,720 | 874,720 | $ | 87 | $ | 87 | |||||||
| (a) | Redeemable, at the option of PECO, at the indicated dollar amounts per share, plus accrued dividends. |
13. Common Stock
At December 31, 2004 and 2003, common stock without par value consisted of 500,000,000 shares authorized and 170,478,507 shares outstanding.
Fund Transfer Restrictions
Under applicable Federal law, PECO can pay dividends only from retained or current earnings. At December 31, 2004, PECO had retained earnings of $607 million.
PECO’s Articles of Incorporation prohibit payment of any dividend on, or other distribution to the holders of, common stock if, after giving effect thereto, the capital of PECO represented by its common stock together with its retained earnings is, in the aggregate, less than the involuntary liquidating value of its then outstanding preferred stock. At December 31, 2004, such capital was $2.8 billion and amounted to about 32 times the liquidating value of the outstanding preferred stock of $87 million.
PECO may not declare dividends on any shares of its capital stock in the event that: (1) it exercises its right to extend the interest payment periods on the subordinated debentures which were issued to PEC L.P. or PECO Trust IV; (2) it defaults on its guarantee of the payment of distributions on the Series D Preferred Securities of PEC L.P. or the preferred trust securities of PECO Trust IV; or (3) an event of default occurs under the Indenture under which the subordinated debentures are issued.
Undistributed Losses of Equity Method Investments
PECO had undistributed losses of equity method investments of $25 million at December 31, 2004.
14. Commitments and Contingencies
Energy Commitments
In connection with the 2001 Exelon corporate restructuring, PECO entered into a purchase power agreement (PPA) with Generation. Under the terms of the PPA, PECO obtains substantially all its
321
PECO Energy Company and Subsidiary Companies
Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, except per share data unless otherwise noted)
electric supply from Generation through 2010. Prices for this energy vary depending upon the month of delivery. Subsequent to 2010, PECO expects to procure all of its supply from market sources, which could include Generation.
Commercial Commitments
PECO’s commercial commitments as of December 31, 2004, representing commitments potentially triggered by future events, were as follows:
| Total |
Expiration within | ||||||||||||||
| 2005 |
2006-2007 |
2008-2009 |
2010 and beyond | ||||||||||||
| Letters of credit (non-debt) (a) |
$ | 29 | $ | 29 | $ | — | $ | — | $ | — | |||||
| Surety bonds (b) |
24 | 24 | — | — | — | ||||||||||
| Total commercial commitments |
$ | 53 | $ | 53 | $ | — | $ | — | $ | — | |||||
| (a) | Letters of credit (non-debt)—PECO maintains non-debt letters of credit to provide credit support for certain transactions as requested by third parties. |
| (b) | Surety bonds—Guarantees issued related to contract and commercial surety bonds, excluding bid bonds. |
Environmental Issues
PECO’s operations have in the past and may in the future require substantial expenditures in order to comply with environmental laws. Additionally, under Federal and state environmental laws, PECO is generally liable for the costs of remediating environmental contamination of property now or formerly owned by PECO and of property contaminated by hazardous substances generated by PECO. PECO owns or leases a number of real estate parcels, including parcels on which its operations or the operations of others may have resulted in contamination by substances that are considered hazardous under environmental laws. PECO has identified 27 sites where former manufactured gas plant (MGP) activities have or may have resulted in actual site contamination. Of these 27 sites, the Pennsylvania Department of Environmental Protection has approved the clean-up of 9 sites. PECO is currently involved in a number of proceedings relating to other sites where hazardous substances have been deposited and may be subject to additional proceedings in the future.
As of December 31, 2004 and 2003, PECO had accrued $47 million and $50 million, respectively, for environmental investigation and remediation costs, including $41 million and $41 million, respectively (reflecting a discount rate of 4.25% and 5.0% in 2004 and 2003, respectively), for investigation and remediation at its 27 MGP sites, that currently can be reasonably estimated. Such estimates, reflecting the effects of a 2.25% and 2.5% inflation rate in 2004 and 2003, respectively, before the effects of discounting were $49 million and $44 million at December 31, 2004 and 2003, respectively. PECO cannot reasonably estimate whether it will incur other significant liabilities for additional investigation and remediation costs at these or additional sites identified by PECO, environmental agencies or others, or whether such costs will be recoverable from third parties; however, PECO is currently recovering through regulated gas rates costs associated with the remediation of the MGP sites.
322
PECO Energy Company and Subsidiary Companies
Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, except per share data unless otherwise noted)
As of December 31, 2004, PECO anticipates that payments related to the discounted environmental investigation and remediation costs, disclosed below on an undiscounted basis, will be:
| 2005 |
$ | 8 | |
| 2006 |
9 | ||
| 2007 |
3 | ||
| 2008 |
6 | ||
| 2009 |
2 | ||
| Remaining years |
21 | ||
| Total payments |
$ | 49 | |
In December 2003, PECO updated its accounting estimate related to the reserve for environmental remediation. Based on an update of an independently prepared environmental remediation study of its MGP sites, PECO increased its environmental reserve by $18 million, with an offsetting increase to the MGP regulatory asset. See Note 15—Supplemental Financial Information for further discussion of the MGP regulatory asset.
Leases
Minimum future operating lease payments, which consist primarily of lease payments for vehicles, as of December 31, 2004 were:
| 2005 |
$ | 3 | |
| 2006 |
3 | ||
| 2007 |
1 | ||
| 2008 |
1 | ||
| 2009 |
1 | ||
| Remaining years |
2 | ||
| Total minimum future lease payments |
$ | 11 | |
Rental expense under operating leases totaled $4 million, $6 million and $7 million in 2004, 2003, and 2002, respectively.
Litigation
Real Estate Tax Appeals. PECO is challenging real estate taxes assessed on nuclear plants since 1997. PECO is involved in litigation in which it is contesting taxes assessed in 1997 under the Pennsylvania Public Utility Realty Tax Act of March 4, 1971, as amended (PURTA) and has appealed local real estate assessments for 1998 and 1999 on its formerly owned Limerick Generating Station (Montgomery County, PA) (Limerick) and Peach Bottom Atomic Power Station (York County, PA) (Peach Bottom) plants.
During 2003, upon completion of updated nuclear plant appraisal studies, PECO recorded reductions of $58 million to reserves recorded for exposures associated with the real estate taxes. While PECO believes the resulting reserve balances as of December 31, 2004 reflect the most likely probable expected outcome of the litigation and appeals proceedings in accordance with SFAS No. 5, “Accounting for Contingencies,” the ultimate outcome of such matters could result in unfavorable or favorable adjustments to the consolidated financial statements of PECO, and such adjustments could be material.
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PECO Energy Company and Subsidiary Companies
Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, except per share data unless otherwise noted)
General. PECO is involved in various other litigation matters that are being defended and handled in the ordinary course of business, and PECO maintains accruals for such costs that are probable of being incurred and subject to reasonable estimation. The ultimate outcome of such matters, as well as the matters discussed above, are uncertain and may have a material adverse effect on PECO’s financial condition, results of operations, or cash flows.
Capital Commitments
PECO estimates that it will spend approximately $281 million for capital expenditures in 2005.
Income Tax Refund Claims
PECO has entered into several agreements with a tax consultant related to the filing of refund claims with the IRS. PECO previously made refundable prepayments to the tax consultant of $5 million. The fees for these agreements are contingent upon a successful outcome and are based upon a percentage of the refunds recovered from the IRS, if any. The ultimate net cash outflow to PECO related to all agreements will either be positive or neutral depending upon the outcome of the refund claim with the IRS. These potential tax benefits and associated fees could be material to the financial position, results of operations and cash flows of PECO. PECO cannot predict the timing of the final resolution of these refund claims.
15. Supplemental Financial Information
Supplemental Income Statement Information
| For the Years Ended December 31, | |||||||||
| 2004 |
2003 |
2002 | |||||||
| Depreciation and amortization |
|||||||||
| Property, plant and equipment (a) |
$ | 144 | $ | 144 | $ | 141 | |||
| Competitive transition charge |
367 | 336 | 308 | ||||||
| Other regulatory assets |
7 | 7 | 7 | ||||||
| Total depreciation and amortization |
$ | 518 | $ | 487 | $ | 456 | |||
| (a) | Includes amortization of capitalized software costs. |
| For the Years Ended December 31, |
|||||||||||
| 2004 |
2003 |
2002 |
|||||||||
| Taxes other than income |
|||||||||||
| Utility (a) |
$ | 205 | $ | 206 | $ | 207 | |||||
| Real estate |
10 | (47 | )(b) | 27 | |||||||
| Payroll |
10 | 11 | 13 | ||||||||
| Other |
11 | 3 | (3 | ) | |||||||
| Total |
$ | 236 | $ | 173 | $ | 244 | |||||
| (a) | Municipal and state utility taxes are also recorded in revenues on PECO’s Consolidated Statements of Income. |
| (b) | Includes the reduction of a $58 million property tax accrual during 2003 as described in Note 14—Commitments and Contingencies. |
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PECO Energy Company and Subsidiary Companies
Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, except per share data unless otherwise noted)
| For the Years Ended December 31, | ||||||||||
| 2004 |
2003 |
2002 | ||||||||
| Other, net |
||||||||||
| Investment income |
$ | 8 | $ | 10 | $ | 26 | ||||
| AFUDC, equity |
1 | — | 1 | |||||||
| Gain (loss) on disposition of assets, net |
9 | — | 1 | |||||||
| Interest associated with Federal income taxes |
— | (14 | ) | — | ||||||
| Other income (expense) |
— | 6 | 3 | |||||||
| Total |
$ | 18 | $ | 2 | $ | 31 | ||||
Supplemental Cash Flow Information
| For the Years Ended December 31, | |||||||||
| 2004 |
2003 |
2002 | |||||||
| Cash paid during the year |
|||||||||
| Interest (net of amount capitalized) |
$ | 298 | $ | 346 | $ | 379 | |||
| Income taxes (net of refunds) |
394 | 269 | 388 | ||||||
Supplemental Balance Sheet Information
| December 31, |
||||||||
| 2004 |
2003 |
|||||||
| Regulatory assets (liabilities) |
||||||||
| Competitive transition charges |
$ | 3,936 | $ | 4,303 | ||||
| Deferred income taxes |
747 | 762 | ||||||
| Non-pension postretirement benefits |
52 | 58 | ||||||
| Reacquired debt costs |
42 | 49 | ||||||
| MGP regulatory asset |
32 | 34 | ||||||
| DOE facility decommissioning |
19 | 26 | ||||||
| Nuclear decommissioning |
(46 | ) | (12 | ) | ||||
| Other |
8 | 6 | ||||||
| Long-term regulatory assets |
4,790 | 5,226 | ||||||
| Deferred energy costs (current asset) |
71 | 81 | ||||||
| Total |
$ | 4,861 | $ | 5,307 | ||||
Competitive transition charges. These charges represent PECO’s stranded costs that the PUC determined would be recoverable through regulated rates. These costs are related to the deregulation of the generation portion of the electric utility business in Pennsylvania. The CTC includes intangible transition property sold to PETT, an unconsolidated subsidiary of PECO, in connection with the securitization of PECO’s stranded cost recovery. These charges are being amortized through December 31, 2010 with a return on the unamortized balance of 10.75%.
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PECO Energy Company and Subsidiary Companies
Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, except per share data unless otherwise noted)
Deferred income taxes. These costs represent the difference between the method by which the regulator allows for the recovery of income taxes and how income taxes would be recorded by unregulated entities. Regulatory assets and liabilities associated with deferred income taxes, recorded in compliance with SFAS No. 71 and SFAS No. 109, include the deferred tax effects associated principally with liberalized depreciation accounted for in accordance with the rate-making policies of the PUC, as well as the revenue impacts thereon, and assume continued recovery or settlement of these costs in future rates. See Note 8—Income Taxes for further discussion.
Non-pension postretirement benefits. These costs are the result of transitioning to SFAS No. 106 in 1993, which are recoverable in regulated rates through 2012.
Reacquired debt costs. These costs represent premiums paid for the early extinguishment and refinancing of long-term debt, which are amortized over the life of the new debt issued to finance the debt redemption.
MGP regulatory asset. These costs represent estimated MGP-related environmental remediation costs which are recoverable through regulated gas rates. See Note 14—Commitments and Contingencies for further discussion.
DOE facility decommissioning. These costs represent PECO’s share of recoverable decommissioning and decontamination costs of the Department of Energy’s (DOE) nuclear fuel enrichment facilities established by the National Energy Policy Act of 1992.
Nuclear decommissioning. Generation is responsible for decommissioning the nuclear plants formerly owned by PECO. These amounts represent future nuclear decommissioning costs that exceed (regulatory asset) or are less than (regulatory liability) the associated decommissioning trust fund assets. Generation and PECO believe the trust fund assets, including prospective earnings thereon and any future collections from ratepayers, will equal the associated future decommissioning costs at the time of decommissioning. See Note 9—Nuclear Decommissioning for further discussion.
Deferred energy costs (current asset). These costs represent fuel costs recoverable under the purchase gas adjustment clause.
Recovery of regulatory assets. The regulatory assets related to deferred income taxes and non-pension post-retirement benefits did not require a cash outlay of investor supplied funds; consequently, this cost is not earning a rate of return. Recovery of the regulatory assets for loss on reacquired debt, MGP remediation costs and deferred energy costs is provided for through regulated revenue sources. Therefore, these costs are earning a rate of return.
| December 31, | ||||||
| 2004 |
2003 | |||||
| Accrued expenses |
||||||
| Taxes accrued |
$ | 140 | $ | 110 | ||
| Interest accrued |
12 | 14 | ||||
| Other accrued expenses |
111 | 113 | ||||
| Total |
$ | 263 | $ | 237 | ||
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PECO Energy Company and Subsidiary Companies
Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, except per share data unless otherwise noted)
| December 31, |
|||||||
| 2004 |
2003 |
||||||
| Accumulated other comprehensive income |
|||||||
| Net unrealized gain on cash-flow hedges | $ | 10 | $ | 9 | |||
| Unrealized loss on marketable securities | — | (2 | ) | ||||
| Total accumulated other comprehensive income |
$ | 10 | $ | 7 | |||
16. Related-Party Transactions
Effective July 1, 2003 PECO Trust IV was deconsolidated from the financial statements of PECO in conjunction with the adoption of FIN 46. Effective December 31, 2003, PETT, PECC, and PECO Trust III were deconsolidated from the financial statements of PECO in conjunction with the adoption of FIN 46-R. Prior periods were not restated.
PECO’s financial statements include related-party transactions with its unconsolidated subsidiaries as reflected in the table below.
| For Year Ended December 31, | |||||||||
| 2004 |
2003 |
2002 | |||||||
| Operating revenues from affiliate |
|||||||||
| PETT (a) |
$ | 10 | $ | — | $ | — | |||
| Interest expense to affiliates |
|||||||||
| PETT |
235 | — | — | ||||||
| PECO Trust III |
6 | — | — | ||||||
| PECO Trust IV |
6 | 3 | — | ||||||
| Equity in losses from unconsolidated affiliates |
|||||||||
| PETT |
25 | — | — | ||||||
| December 31, | ||||||
| 2004 |
2003 | |||||
| Investment in subsidiaries |
||||||
| PETT |
$ | 77 | $ | 104 | ||
| PECC |
4 | 16 | ||||
| PECO Trust IV |
6 | 3 | ||||
| Receivables from affiliates (noncurrent) |
||||||
| PECO Trust IV |
— | 1 | ||||
| Payables to affiliates (current) |
||||||
| PECC |
— | 1 | ||||
| PECO Trust III |
1 | 10 | ||||
| Long-term debt to financing trusts (including due within one year) |
||||||
| PETT |
3,456 | 3,849 | ||||
| PECO Trust IV |
103 | 103 | ||||
| PECO Trust III |
81 | 81 | ||||
| (a) | PECO receives a monthly service fee from PETT based on a percentage of the outstanding balance of all series of transition bonds. |
327
PECO Energy Company and Subsidiary Companies
Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, except per share data unless otherwise noted)
In addition to the transactions described above, PECO’s financial statements include related-party transactions as reflected in the tables below.
| For Year Ended December 31, | |||||||||
| 2004 |
2003 |
2002 | |||||||
| Operating revenues from affiliates |
|||||||||
| Generation (a) |
$ | 9 | $ | 10 | $ | 12 | |||
| Other |
— | 1 | — | ||||||
| Purchased power from affiliate |
|||||||||
| Generation (b) |
1,447 | 1,433 | 1,438 | ||||||
| Fuel from affiliate |
|||||||||
| Generation (c) |
17 | — | — | ||||||
| O&M from affiliates |
|||||||||
| BSC (d) |
106 | 50 | 49 | ||||||
| Generation |
1 | — | — | ||||||
| Enterprises (e) |
— | 2 | 24 | ||||||
| ComEd (f) |
— | 5 | — | ||||||
| Capitalized costs |
|||||||||
| BSC (d) |
22 | 4 | 8 | ||||||
| Enterprises (e) |
— | 15 | 24 | ||||||
| Cash dividends paid to parent |
391 | 322 | 340 | ||||||
| December 31, | ||||||
| 2004 |
2003 | |||||
| Receivable from affiliate (current) |
||||||
| Exelon intercompany money pool (g) |
$ | 34 | $ | — | ||
| Receivable from affiliate (noncurrent) |
||||||
| Generation decommissioning (h) |
46 | 12 | ||||
| Payables to affiliates (current) |
||||||
| Generation (b) |
125 | 115 | ||||
| BSC (d) |
20 | 15 | ||||
| Enterprises (e) |
— | — | ||||
| ComEd (f) |
— | 6 | ||||
| Other |
— | 3 | ||||
| Shareholders’ equity—receivable from parent (i) |
1,482 | 1,623 | ||||
| (a) | PECO provides energy to Generation for Generation’s own use. |
| (b) | Effective January 1, 2001, PECO entered into a PPA with Generation. |
| (c) | Effective April 1, 2004, PECO entered into a one-year gas procurement agreement with Generation. |
| (d) | PECO receives a variety of corporate support services from Exelon Business Services Company (BSC) including legal, human resources, financial, information technology and supply management services. Additionally in 2004, due to the centralization of certain functions, certain employees were transferred from PECO to BSC. As a result, PECO now receives additional services from BSC including planning and engineering of delivery systems, management of construction, maintenance and operations of the transmission and delivery systems and management of other support services. All services are provided at cost, including application overhead. A portion of such services is capitalized. |
| (e) | Prior to 2004, PECO received services from Exelon Enterprises Company, LLC (Enterprises) for construction, which were capitalized, and the deployment of automated meter reading technology, which was expensed. This entity was sold by Exelon in 2004. |
| (f) | ComEd provided hurricane restoration services to PECO during Hurricane Isabel. |
| (g) | PECO participates in Exelon’s intercompany money pool. PECO earns interest on its contributions to the money pool at a market rate of interest. |
328
PECO Energy Company and Subsidiary Companies
Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, except per share data unless otherwise noted)
| (h) | PECO has a receivable from Generation as a result of the nuclear decommissioning contractual construct, whereby, to the extent the assets associated with decommissioning are greater than the applicable ARO, such amounts are due back to PECO for payment to ratepayers. See Note 9—Nuclear Decommissioning for further information. |
| (i) | PECO has a non-interest bearing receivable from Exelon related to the 2001 corporate restructuring. The receivable is expected to be settled over the years 2005 through 2010. |
17. Quarterly Data (Unaudited)
The data shown below include all adjustments which PECO considers necessary for a fair presentation of such amounts:
| Operating Revenues |
Operating Income |
Net Income on Common Stock | ||||||||||||||||
| 2004 |
2003 |
2004 |
2003 |
2004 |
2003 | |||||||||||||
| Quarter ended: |
||||||||||||||||||
| March 31 (a) |
$ | 1,239 | $ | 1,217 | $ | 276 | $ | 282 | $ | 131 | $ | 135 | ||||||
| June 30 |
1,032 | 961 | 230 | 224 | 99 | 86 | ||||||||||||
| September 30 |
1,124 | 1,149 | 301 | 301 | 138 | 140 | ||||||||||||
| December 31 |
1,092 | 1,061 | 207 | 249 | 84 | 107 | ||||||||||||
| (a) | Operating income and net income for the three months ended March 31, 2004 has been adjusted to reflect a reduction in net periodic postretirement benefit cost of $1 million due to the adoption of FSP FAS 106-2. See Note 1—Significant Accounting Policies for additional information. |
329
| ITEM 7. | MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATION |
Executive Overview
As of December 31, 2004, Generation consisted of its owned and contracted for electric generating facilities and energy marketing operations, a 50% interest in Sithe, 49.5% interests in two power stations in Mexico, and the competitive retail sales business of Exelon Energy Company. On January 31, 2005, Generation purchased the remaining 50% interest of Sithe and immediately sold its entire interest in Sithe.
Effective January 1, 2004, Enterprises’ competitive retail sales business, Exelon Energy Company, became part of Generation. Generation’s results of operations have not been adjusted to reflect Exelon Energy Company as a part of Generation for 2003 or 2002. Exelon Energy Company’s results for the years ended December 31, 2003, and 2002 were as follows:
| Year ended December 31, 2003 |
Year ended December 31, 2002 |
|||||||
| Total revenues |
$ | 834 | $ | 697 | ||||
| Intersegment revenues |
4 | 8 | ||||||
| Income (loss) before income taxes |
(29 | ) | (6 | ) | ||||
| Income taxes (benefit) |
(11 | ) | 16 | |||||
| Net income (loss) |
(18 | ) | (33 | ) | ||||
Generation is one of the largest competitive electric generation companies in the United States, as measured by owned and controlled MWs. Generation combines its large generation fleet with an experienced wholesale and retail power marketing operation. Generation owns generation assets in the Northeast, Mid-Atlantic, Midwest and Texas regions with a net capacity of 25,756 MWs, including 16,751 MWs of nuclear capacity, and controls another 8,701 MWs of capacity in the Midwest, Southeast and South Central regions through long-term contracts.
In addition to its owned generating facilities, Generation, through its investment in Sithe International, owns 49.5% interests in two Mexican business trusts that own the Termoeléctrica del Golfo (TEG) and Termoeléctrica Peñoles (TEP) power stations, two 230 MW petcoke-fired generating facilities in Tamuín, Mexico.
Generation’s wholesale marketing unit, Power Team, a major wholesale marketer of energy, uses Generation’s energy generation portfolio, transmission rights and expertise to ensure delivery of energy to Generation’s wholesale customers under long-term and short-term contracts, including the energy, or “load,” requirements of ComEd and PECO. Power Team markets any remaining energy in the wholesale bilateral and spot markets.
2004 has been a year of operating accomplishments and execution of Generation’s overall investment strategy. Generation has focused on living up to its commitments while pursuing greater productivity, quality and innovation. 2004 highlights included the following:
Financial Results. Generation’s net income was $673 million in 2004, compared to a $133 million net loss in 2003. The improvement in Generation’s financial results is primarily attributable to the acquisition of the remaining 50% interest of AmerGen, the sale of Boston Generating, reductions in costs associated with The Exelon Way and an increase in revenue net of purchased power and fuel (revenue net fuel) of over $750 million in 2004 compared to 2003. Also, Generation incurred a $945 million impairment charge related to the long-lived assets of Boston Generating in 2003. The increase
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in revenue net fuel is attributable to a reduction in realized purchased power and fuel costs due to Generation’s hedging program and the inclusion of AmerGen, Exelon Energy and Sithe in the 2004 results from operations. Also included in Generation’s financial results in 2004 is $32 million of net income resulting from the cumulative effect of a change in accounting principle for the adoption of FIN 46-R. The increase in net income was partially offset by an increase in operating and maintenance expense of $499 million associated with the consolidation of AmerGen, Sithe and Exelon Energy in 2004. In 2003, Generation also recorded $108 million of net income resulting from the cumulative effect of a change in accounting principle upon the adoption of a new accounting standard that has a significant impact on how Generation accounts for its nuclear decommissioning obligations.
Investment and Divestiture Activities. On May 25, 2004, Generation completed the sale, transfer and assignment of ownership of its indirect wholly owned subsidiary Boston Generating, which owns directly or indirectly the companies that own Mystic 4-7, Mystic 8 and 9 and Fore River generating facilities, to a special purpose entity owned by the lenders under Boston Generating’s $1.25 billion credit facility. The resulting gain of $85 million ($52 million after-tax) was recorded within Generation’s results of operations during the second quarter of 2004. On September 1, 2004, Generation completed the transfer of plant operations and power marketing arrangements to the lenders’ special purpose entity and its contractors under Boston Generating’s credit facility. In 2003, Generation recorded a pre-tax impairment charge of $945 million related to the long-lived assets of Boston Generating.
On September 29, 2004, Generation exercised its call option and entered into an agreement to acquire Reservoir’s 50% interest in Sithe for $97 million and, on November 1, 2004, Generation entered into an agreement to sell its anticipated 100% interest in Sithe to Dynegy, Inc. for $135 million in cash. On January 31, 2005, Generation closed on these two transactions and exited its investment in Sithe. The sale did not include Sithe International, which was sold to a subsidiary of Generation on October 13, 2004. Generation acquired Sithe International in exchange for its $92 million note receivable from Sithe in a non-cash transaction. Effective January 26, 2005, Sithe International’s name was changed to Tamuin International Inc.
Financing Activities. Generation met its capital resource commitments primarily through internally generated cash. When necessary, Generation obtains funds from external sources, including the capital markets, the intercompany money pool and through bank borrowings. During 2004, Generation issued $157 million of pollution control bonds, decreased borrowings in the intercompany money pool by $133 million, net of $29 million of borrowings assumed as a result of the transfer of Exelon Energy, and distributed $505 million of dividends to Exelon. On December 31, 2004, Generation had $283 million in outstanding money pool loans to fund operations.
Operational Achievements. Generation focused on the core fundamentals of providing efficient generation to its customers. Generation’s nuclear fleet achieved a 93.5% capacity factor in 2004 compared to 93.4% in 2003 while reducing the production costs of nuclear generation to 1.24 cents per kilowatt-hour. Generation’s nuclear fleet’s production costs continue to be in the top quartile of the nuclear industry. Other operational achievements include improved commercial availability and improved safety metrics at Generation’s fossil fuel plants in 2004.
Outlook for 2005 and Beyond. On December 20, 2004, Exelon entered into a merger agreement with PSEG, a holding company for an electric and gas utility company primarily located and serving customers in New Jersey. The transaction, which has been unanimously approved by the Boards of Directors of both companies, is expected to close in the first quarter of 2006. However, the transaction is contingent upon, among other things, the approval by shareholders of PSEG of the merger and shareholders of Exelon of the shares to be issued in the merger, antitrust clearance and a number of regulatory approvals and reviews. Exelon and Generation are in the process of evaluating the impacts of the merger.
331
In the near term, Generation’s financial results can be affected by a number of factors, including wholesale market prices, weather conditions, the continued successful implementation of operational improvement initiatives and Generation’s ability to generate electricity at low costs. Generation believes that Power Team’s hedging program reduces the short-term exposure to the variability in market prices.
Generation’s results will be affected by long-term changes in the market prices of power and fuel caused by supply/demand changes, the continued restructuring of the U.S. electric industry at both the Federal and state levels and various environmental regulations. Generating companies must also work with regulators to ensure that a viable capacity market exists to ensure that new units will be constructed in a timely manner to meet the growing demand for power. Generation will continue to be an active participant in these policy debates, while continuing to focus on improving operations and controlling costs and providing a fair return to its investors. To meet Exelon’s financial goals, Generation’s nuclear units must continue their superior performance while keeping costs under control despite inflationary pressures and increasing security costs caused by external events.
Results of Operations
Year Ended December 31, 2004 Compared To Year Ended December 31, 2003
| 2004 |
2003 |
Favorable (Unfavorable) |
||||||||||
| OPERATING REVENUES |
$ | 7,938 | $ | 8,135 | $ | (197 | ) | |||||
| OPERATING EXPENSES |
||||||||||||
| Purchased power |
2,325 | 3,587 | 1,262 | |||||||||
| Fuel |
1,845 | 1,533 | (312 | ) | ||||||||
| Operating and maintenance |
2,273 | 1,866 | (407 | ) | ||||||||
| Impairment of Boston Generating, LLC long-lived assets |
— | 945 | 945 | |||||||||
| Depreciation and amortization |
294 | 199 | (95 | ) | ||||||||
| Taxes other than income |
171 | 120 | (51 | ) | ||||||||
| Total operating expense |
6,908 | 8,250 | 1,342 | |||||||||
| OPERATING INCOME (LOSS) |
1,030 | (115 | ) | 1,145 | ||||||||
| OTHER INCOME AND DEDUCTIONS |
||||||||||||
| Interest expense |
(167 | ) | (88 | ) | (79 | ) | ||||||
| Equity in earnings (losses) of unconsolidated affiliates |
(14 | ) | 49 | (63 | ) | |||||||
| Other, net |
143 | (262 | ) | 405 | ||||||||
| Total other income and deductions |
(38 | ) | (301 | ) | 263 | |||||||
| INCOME (LOSS) BEFORE INCOME TAXES, MINORITY INTEREST, AND CUMULATIVE EFFECT OF CHANGES IN ACCOUNTING PRINCIPLES |
992 | (416 | ) | 1,408 | ||||||||
| INCOME TAXES |
372 | (179 | ) | (551 | ) | |||||||
| INCOME (LOSS) BEFORE MINORITY INTEREST AND CUMULATIVE EFFECT OF CHANGES IN ACCOUNTING PRINCIPLES |
620 | (237 | ) | 857 | ||||||||
| MINORITY INTEREST |
21 | (4 | ) | 25 | ||||||||
| INCOME (LOSS) BEFORE CUMULATIVE EFFECT OF CHANGES IN ACCOUNTING PRINCIPLES |
641 | (241 | ) | 882 | ||||||||
| CUMULATIVE EFFECT OF CHANGES IN ACCOUNTING PRINCIPLES (net of income taxes) |
32 | 108 | (76 | ) | ||||||||
| NET INCOME (LOSS) |
$ | 673 | $ | (133 | ) | $ | 806 | |||||
332
Operating Revenues
Operating revenues decreased in 2004 as compared to 2003, primarily as a result of the adoption of EITF 03-11. The adoption of EITF 03-11 resulted in a net decrease in revenues of $980 million in 2004 as compared with the prior year. Generation’s sales in 2004 and 2003 were as follows:
| Revenue (in millions) |
2004 |
2003 |
Variance |
% Change |
|||||||||
| Electric sales to affiliates (a) |
$ | 3,749 | $ | 4,036 | $ | (287 | ) | (7.1 | %) | ||||
| Wholesale and retail electric sales (b) |
3,227 | 3,861 | (634 | ) | (16.4 | %) | |||||||
| Total energy sales revenue |
6,976 | 7,897 | (921 | ) | (11.7 | %) | |||||||
| Retail gas sales |
456 | — | 456 | n.m. | |||||||||
| Trading portfolio |
— | 1 | (1 | ) | (100.0 | %) | |||||||
| Other revenue (c) |
506 | 237 | 269 | 113.5 | % | ||||||||
| Total revenue |
$ | 7,938 | $ | 8,135 | $ | (197 | ) | (2.4 | %) | ||||
| Sales (in GWhs) |
2004 |
2003 |
Variance |
% Change |
||||||
| Sales to affiliates (a) |
110,465 | 117,405 | (6,940 | ) | (5.9 | %) | ||||
| Wholesale and retail electric sales (b) |
92,134 | 107,267 | (15,133 | ) | (14.1 | %) | ||||
| Total sales |
202,599 | 224,672 | (22,073 | ) | (9.8 | %) | ||||
| (a) | Includes sales to Exelon Energy Company during 2003. As of January 1, 2004, Exelon Energy Company became part of Generation and is presented as retail electric sales. |
| (b) | Includes retail electric sales of Exelon Energy Company in 2004. |
| (c) | Includes sales related to tolling agreements, including Sithe in 2004, and fossil fuel sales. |
| n.m.—not | meaningful |
Trading volumes of 24,001 GWhs and 32,584 GWhs for the years ended December 31, 2004 and 2003, respectively, are not included in the table above. The decrease in trading volume is a result of reduced volumetric and VAR trading limits in 2004, which are set by the Exelon Risk Management Committee and approved by the Board of Directors.
Electric Sales to Affiliates. Revenue from sales to affiliates decreased primarily as a result of the transfer of Exelon Energy Company to Generation effective January 1, 2004. Sales to Exelon Energy Company are no longer reported as affiliate revenue by Generation. Revenue from sales to Exelon Energy Company for the year ended December 31, 2003 was $209 million.
Sales to Energy Delivery declined $76 million in 2004 as compared to the prior year, which further contributed to the decrease in sales to affiliates. The lower sales to Energy Delivery were primarily driven by cooler than normal summer weather and lower average transfer prices in 2004 as compared to the prior year.
Wholesale and Retail Electric Sales. The changes in Generation’s wholesale and retail electric sales for the year ended December 31, 2004 compared to the same period in 2003, consisted of the following:
| Variance |
||||
| Effects of EITF 03-11 adoption (a) |
$ | (966 | ) | |
| Sale of Boston Generating |
(370 | ) | ||
| Addition of Exelon Energy Company and AmerGen operations |
424 | |||
| Other operations |
278 | |||
| Decrease in wholesale and retail electric sales |
$ | (634 | ) | |
| (a) | Does not include $14 million of EITF 03-11 reclassifications related to fuel sales that are included in other revenues. |
333
As previously described, the adoption of EITF 03-11 on January 1, 2004 resulted in the netting of certain revenues and the associated purchase power and fuel expense in 2004. The sale of Boston Generating in May 2004 resulted in less revenue from this entity in 2004 compared to the prior year. The acquisition of Exelon Energy and AmerGen resulted in increased market and retail electric sales of approximately $424 million compared to the prior year.
The remaining increase in wholesale and retail electric sales was primarily due to higher volumes sold to the market at overall higher prices. The increase in market prices was primarily driven by higher coal prices in the Midwest region and higher oil and gas prices in the Mid-Atlantic region.
Retail Gas Sales. Retail gas sales increased $456 million as a result of the transfer of Exelon Energy Company to Generation as of January 1, 2004.
Other. Other revenues in 2004 include $235 million of revenue related to the results of Sithe Energies, Inc. The remaining increase in other revenues includes sales from tolling agreement, fossil fuel and decommissioning revenue.
Purchased Power and Fuel Expense
Generation’s supply of sales in 2004 and 2003, excluding the trading portfolio, was as follows:
| Supply of Sales (in GWhs) |
2004 |
2003 |
% Change |
||||
| Nuclear generation (a) |
136,621 | 117,502 | 16.3 | % | |||
| Purchases—non-trading portfolio (b) |
48,968 | 82,860 | (40.9 | %) | |||
| Fossil and hydroelectric generation (c, d) |
17,010 | 24,310 | (30.0 | %) | |||
| Total supply |
202,599 | 224,672 | (9.8 | %) | |||
| (a) | Excludes AmerGen for 2003. AmerGen generated 20,135 GWhs during the year ended December 31, 2004. |
| (b) | Sales in 2004 do not include 25,464 GWhs that were netted with purchased power GWhs as a result of the reclassification of certain hedging activities in accordance with EITF 03-11. Includes PPAs with AmerGen, which represented 12,667 GWhs in 2003. |
| (c) | Fossil and hydroelectric supply mix changed as a result of decreased fossil fuel generation due to the sale of Boston Generating in May 2004. |
| (d) | Excludes Sithe and Generation’s investment in TEG and TEP. |
The changes in Generation’s purchased power and fuel expense for the year ended December 31, 2004 compared to the same period in 2003 consisted of the following:
| Variance |
||||
| Effects of the adoption of EITF 03-11 |
$ | (980 | ) | |
| Sale of Boston Generating |
(290 | ) | ||
| Midwest Generation |
(122 | ) | ||
| Mark-to-market adjustments on hedging activity |
(14 | ) | ||
| Price |
(13 | ) | ||
| Volume |
267 | |||
| Sithe Energies, Inc. |
165 | |||
| Addition of AmerGen and Exelon Energy Company |
124 | |||
| Other |
(87 | ) | ||
| Decrease in purchased power and fuel expense |
$ | (950 | ) | |
334
Adoption of EITF 03-11. The adoption of EITF 03-11 resulted in a decrease in purchased power and fuel expense of $980 million.
Sale of Boston Generating. The decrease in fuel and purchased power expense for Boston Generating is due primarily to the sale of the business in May 2004.
Midwest Generation. The volume of purchased power acquired from Midwest Generation declined in 2004 as a result of Generation exercising its option to reduce the capacity purchased from Midwest Generation, as announced in 2003.
Hedging Activity. Mark-to-market losses on hedging activities at Generation were $2 million for the year ended December 31, 2004 compared to losses of $16 million for 2003. Hedging activities in 2004 relating to Boston Generating operations accounted for a gain of $4 million and hedging activities relating to other Generation operations in 2004 accounted for a loss of $6 million.
Price. The decrease reflects the forward hedging of fuel at lower costs than 2003 realized costs.
Volume. Generation experienced increases in purchased power and fuel expense due to increased market and retail electric sales throughout its various sales regions.
Sithe Energies, Inc. Under the provisions of FIN 46-R, the operating results of Sithe were included in Generation’s results of operations beginning April 1, 2004. See Note 3 of Generation’s Notes to Consolidated Financial Statements for further discussion of Sithe.
Addition of AmerGen and Exelon Energy Company. Due to the transfer of Exelon Energy Company to Generation effective January 1, 2004, fuel expense increased $468 million as fuel purchases made by Exelon Energy Company did not previously affect Generation’s results. As a result of Generation’s acquisition of the remaining 50% interest in AmerGen in December 2003, purchased power decreased $379 million in 2004. In prior periods, Generation reported energy purchased from AmerGen as purchased power expense. The decrease in purchase power from the acquisition of the remaining 50% of AmerGen was partially offset by an increase of $35 million in AmerGen’s nuclear fuel expense.
Other. Other decreases in purchased power and fuel expense were primarily due to $97 million of lower transmission expense resulting from reduced inter-region transmission charges, primarily associated with ComEd’s integration into PJM.
Generation’s average margins per MWh sold for the years ended December 31, 2004 and 2003 were as follows:
| ($/MWh) |
2004 |
2003 |
% Change | |||||
| Average revenue |
||||||||
| Electric sales to affiliates (a) |
$ | 33.94 | $ | 34.38 | (1.3%) | |||
| Wholesale and retail electric sales (b) |
35.03 | 35.99 | (2.7%) | |||||
| Total—excluding the trading portfolio |
34.43 | 35.15 | (2.0%) | |||||
| Average supply cost—excluding the trading portfolio (c) |
20.59 | 22.79 | (9.7%) | |||||
| Average margin—excluding the trading portfolio |
13.84 | 12.36 | 12.0% | |||||
| (a) | Includes sales to Exelon Energy Company during 2003. As of January 1, 2004, Exelon Energy Company became part of Generation and is presented as retail sales. |
| (b) | Includes retail electric sales of Exelon Energy Company in 2004. |
| (c) | Average supply cost includes purchased power, fuel costs and PPAs with AmerGen in 2003. |
335
Operating and Maintenance
The changes in operating and maintenance expense for the year ended December 31, 2004 compared to the same period in 2003 consisted of the following:
| Variance |
||||
| Addition of AmerGen and Exelon Energy Company |
$ | 345 | ||
| Sithe Energies, Inc. |
71 | |||
| Refueling outage costs (a) |
50 | |||
| Decommissioning related costs (b) |
50 | |||
| Pension, payroll and benefit costs, primarily associated with The Exelon Way |
(84 | ) | ||
| DOE Settlement (c) |
(52 | ) | ||
| Sale of Boston Generating |
(12 | ) | ||
| Other |
39 | |||
| Increase in operating and maintenance expense |
$ | 407 | ||
| (a) | Includes refueling outage expense of $43 million at AmerGen. |
| (b) | Includes $40 million due to AmerGen asset retirement obligation accretion. |
| (c) | See Note 13 of Generation’s Notes to Consolidated Financial Statements for further discussions of the spent nuclear fuel storage settlement agreement with the DOE. |
The increase in operating and maintenance expense is primarily due to the inclusion of AmerGen, Exelon Energy Company and Sithe in Generation’s consolidated results for 2004. Decommissioning related costs increased primarily due to the inclusion of AmerGen in 2004 compared to the prior year. Accretion expense includes accretion of the asset retirement obligation and adjustments to offset the earnings impacts of certain decommissioning related activities, including revenues earned from ComEd and PECO, income taxes and depreciation of the asset retirement cost asset (ARC) to zero. The increase in operating and maintenance expense was partially offset with reductions in payroll-related costs due to implementation of the programs associated with The Exelon Way, the sale of Boston Generating in May 2004 and the settlement with the DOE to reimburse Generation for costs associated with storage of spent nuclear fuel.
Nuclear fleet operating data and purchased power costs data for the year ended December 31, 2004 and 2003 were as follows:
| 2004 |
2003 |
|||||||
| Nuclear fleet capacity factor (a) |
93.5 | % | 93.4 | % | ||||
| Nuclear fleet production cost per MWh (a) |
$ | 12.43 | $ | 12.53 | ||||
| Average purchased power cost for wholesale operations per MWh (b) |
$ | 47.48 | $ | 43.29 | ||||
| (a) | Includes AmerGen and excludes Salem, which is operated by PSEG Nuclear. |
| (b) | Includes PPAs with AmerGen in 2003. |
The higher nuclear capacity factor is primarily due to ten fewer unplanned outages which offset the impact of one additional planned refuel outage. The lower production cost in 2004 as compared to 2003 is primarily due to lower fuel costs and the impact of the spent fuel storage cost settlement agreement with the DOE which offset the added cost for one additional planned refuel outage and costs associated with the Dresden generator repairs during outages in the fourth quarter of 2004.
In 2004 as compared to 2003, the Quad Cities Units intermittently operated at pre-Extended Power Uprate (EPU) generation levels due to performance issues with their steam dryers. Generation plans additional expenditures to ensure safe and reliable operations at the EPU output levels by mid-2005.
336
Impairment of the Long-Lived Assets of Boston Generating
In connection with the decision to transition out of the ownership of Boston Generating during the third quarter of 2003, Generation recorded a long-lived asset impairment charge of $945 million ($573 million net of income taxes). See Note 2 of Generation’s Notes to Consolidated Financial Statements for further discussion of the sale of Generation’s ownership interest in Boston Generating.
Depreciation and Amortization
The increase in depreciation and amortization expense in 2004 as compared to 2003 was primarily due to the immediate expensing of an asset retirement cost (ARC), totaling $49 million, recorded in 2004 for which no useful life remains. The ARC was originally recorded in accordance with SFAS No. 143, which requires the establishment of an asset to offset the impact of an increased asset retirement obligation (ARO). See Note 13 of Generation’s Notes to Consolidated Financial Statements for more information on the 2004 update to the ARO and ARC. The remaining increase was due to capital additions and the consolidation of Sithe, AmerGen and Exelon Energy. These increases were partially offset by a decrease in depreciation expense related to Boston Generating facilities, which were sold in May 2004.
Taxes Other Than Income
Taxes other than income increased in 2004 compared to 2003 due primarily to $31 million of additional payroll and property taxes incurred from the consolidation of Sithe, AmerGen and Exelon Energy. The remaining increase resulted from a $15 million reduction to reserves recorded in 2003 for exposures associated with real estate taxes.
Interest Expense
The increase in interest expense in 2004 as compared to 2003 was primarily related to additional expense incurred from the consolidation of Sithe, the purchase of British Energy’s interest in AmerGen, and the issuance of $500 million of Senior Notes in December 2003. The increase was partially offset by a reduction in interest expense of $12 million related to the Boston Generating project debt.
Equity in Earnings of Unconsolidated Affiliates
The decrease in equity in earnings of unconsolidated affiliates in 2004 as compared to 2003 was due to a $47 million decrease resulting from Generation’s consolidation of AmerGen in 2004 following the purchase of British Energy’s 50% interest in AmerGen in December 2003 and the consolidation of Sithe in 2004. Equity in earnings of unconsolidated affiliates in 2004 represents equity earnings from TEG and TEP following the transfer of ownership in Sithe International in the fourth quarter of 2004, and prior to that, relates to earnings recorded at Sithe for Sithe’s 49.5% interests in TEG and TEP.
337
Other, Net
The components of other, net for 2004 as compared to 2003 are as follows:
| Other, Net |
2004 |
2003 |
Variance |
|||||||||
| Gain on sale of Boston Generating (a) |
$ | 85 | $ | — | $ | 85 | ||||||
| Decommissioning-related activities: |
||||||||||||
| Decommissioning trust fund income (b) |
194 | 79 | 115 | |||||||||
| Decommissioning trust fund income—AmerGen (b) |
43 | — | 43 | |||||||||
| Other-than-temporary impairment of decommissioning trust funds (c) |
(268 | ) | — | (268 | ) | |||||||
| Contractual offset to decommissioning-related activities (d) |
66 | (79 | ) | 145 | ||||||||
| Gain on sale of Sithe related assets |
6 | — | 6 | |||||||||
| Impairment of investment in Sithe |
— | (255 | ) | 255 | ||||||||
| Other |
17 | (7 | ) | 24 | ||||||||
| Total |
$ | 143 | $ | (262 | ) | $ | 405 | |||||
| (a) | See Note 2 of Generation’s Notes to the Consolidated Financial Statements for further discussion of Generation’s sale of Boston Generating. |
| (b) | Includes investment income and realized gains/(losses). |
| (c) | Includes other-than-temporary impairments totaling $255 million, $5 million and $8 million on nuclear decommissioning trust funds for the former ComEd, PECO and AmerGen units, respectively. |
| (d) | Includes the elimination of non-operating decommissioning related activity for those units that are subject to contractual accounting, including the elimination of decommissioning trust fund income and other-than-temporary impairments for certain nuclear units. See Notes 13 and 15 of Generation’s Notes to Consolidated Financial Statements for more information regarding the contractual accounting applied for certain nuclear units. |
The increase in other, net in 2004 as compared to 2003 was primarily due to the $85 million gain ($52 million, net of taxes) on the sale of Boston Generating recorded in 2004, a $255 million impairment charge in 2003 related to Generation’s equity investment in Sithe Energies, Inc. and a $25 million loss resulting from the purchase and subsequent sale of 50% of the assets of Sithe to Reservoir (see Note 3 of Generation’s Notes to Consolidated Financial Statements) in 2003. The remaining increase was due to a $35 million increase in decommissioning trust fund investment income primarily related to AmerGen.
Effective Income Tax Rate
The effective income tax rate was 37.5% for 2004 compared to 43.0% for 2003. The decrease in the effective rate was primarily attributable to income taxes associated with nuclear decommissioning trust fund activity, income tax deductions related to non-taxable employee benefits and the dilution of the permanent income tax benefits due to the increase in pre-tax income in 2004.
Cumulative Effect of Changes in Accounting Principles
On March 31, 2004, Generation adopted FIN 46-R, resulting in a benefit of $32 million (net of income taxes of $22 million).
On January 1, 2003, Generation adopted SFAS No. 143 resulting in a benefit of $108 million (net of income taxes of $70 million).
338
Results of Operations
Year Ended December 31, 2003 Compared To Year Ended December 31, 2002
| 2003 |
2002 |
Favorable (Unfavorable) |
||||||||||
| OPERATING REVENUES |
$ | 8,135 | $ | 6,858 | $ | 1,277 | ||||||
| OPERATING EXPENSES |
||||||||||||
| Purchased power |
3,587 | 3,294 | (293 | ) | ||||||||
| Fuel |
1,533 | 959 | (574 | ) | ||||||||
| Operating and maintenance |
1,866 | 1,656 | (210 | ) | ||||||||
| Impairment of Boston Generating, LLC long-lived assets |
945 | — | (945 | ) | ||||||||
| Depreciation and amortization |
199 | 276 | 77 | |||||||||
| Taxes other than income |
120 | 164 | 44 | |||||||||
| Total operating expense |
8,250 | 6,349 | (1,901 | ) | ||||||||
| OPERATING INCOME (LOSS) |
(115 | ) | 509 | (624 | ) | |||||||
| OTHER INCOME AND DEDUCTIONS |
||||||||||||
| Interest expense |
(88 | ) | (75 | ) | (13 | ) | ||||||
| Equity in earnings of unconsolidated affiliates |
49 | 87 | (38 | ) | ||||||||
| Other, net |
(262 | ) | 86 | (348 | ) | |||||||
| Total other income and deductions |
(301 | ) | 98 | (399 | ) | |||||||
| INCOME (LOSS) BEFORE INCOME TAXES, MINORITY INTEREST, AND CUMULATIVE EFFECT OF CHANGES IN ACCOUNTING PRINCIPLES |
(416 | ) | 607 | (1,023 | ) | |||||||
| INCOME TAXES |
(179 | ) | 217 | 396 | ||||||||
| INCOME (LOSS) BEFORE MINORITY INTEREST AND CUMULATIVE EFFECT OF CHANGES IN ACCOUNTING PRINCIPLES |
(237 | ) | 390 | (627 | ) | |||||||
| MINORITY INTEREST |
(4 | ) | (3 | ) | (1 | ) | ||||||
| INCOME (LOSS) BEFORE CUMULATIVE EFFECT OF CHANGES IN ACCOUNTING PRINCIPLES |
(241 | ) | 387 | (628 | ) | |||||||
| CUMULATIVE EFFECT OF CHANGES IN ACCOUNTING PRINCIPLES (net of income taxes) |
108 | 13 | 95 | |||||||||
| NET INCOME (LOSS) |
$ | (133 | ) | $ | 400 | $ | (533 | ) | ||||
339
Operating Revenues
Operating revenues increased in 2003 as compared to 2002. Generation’s sales in 2003 and 2002 were as follows:
| Revenue (in millions) |
2003 |
2002 |
Variance |
% Change |
||||||||||
| Electric sales to affiliates (a) |
$ | 4,036 | $ | 4,213 | $ | (177 | ) | (4.2 | %) | |||||
| Wholesale and retail electric sales |
3,861 | 2,490 | 1,371 | 55.1 | % | |||||||||
| Total energy sales revenue |
7,897 | 6,703 | 1,194 | 17.8 | % | |||||||||
| Trading portfolio |
1 | (29 | ) | 30 | (103.4 | %) | ||||||||
| Other revenue |
237 | 184 | 53 | 28.8 | % | |||||||||
| Total revenue |
$ | 8,135 | $ | 6,858 | $ | 1,277 | 18.6 | % | ||||||
| Sales (in GWhs) |
2003 |
2002 |
Variance |
% Change |
||||||||||
| Electric sales to affiliates (a) |
117,405 | 123,975 | (6,570 | ) | (5.3 | %) | ||||||||
| Wholesale and retail electric sales |
107,267 | 83,565 | 23,702 | 28.4 | % | |||||||||
| Total sales |
224,672 | 207,540 | 17,132 | 8.3 | % | |||||||||
| (a) | Includes sales to Exelon Energy Company. |
Trading volumes of 32,584 GWhs and 69,933 GWhs for the years ended December 31, 2003 and 2002, respectively, are not included in the table above. The decrease in trading volume is a result of reduced volumetric and VAR trading limits in 2003, which are set by the Exelon Risk Management Committee and approved by the Board of Directors.
Electric sales to affiliates. Sales to affiliates decreased primarily due to lower volume sales to ComEd, offset by slightly higher realized prices. Revenues from PECO were lower, primarily due to lower realized prices, partially offset by slightly higher volumes. Sales to Exelon Energy Company decreased primarily due to the discontinuance of Exelon Energy Company operations in the PJM region.
Wholesale and Retail Electric Sales. Sales volume in the wholesale spot and bilateral markets increased primarily due to the acquisition of Exelon New England in November 2002 and the commencement of commercial operations in 2003 of the Boston Generating facilities, Mystic 8 and 9 and Fore River. In addition, average market prices in 2003 were $5/MWh higher than in 2002.
Trading Revenues. Trading margin increased, reflecting a $1 million gain for the year ended December 31, 2003 as compared to a $29 million loss in the same period in 2002. The increase was primarily related to an increase in gas prices in April 2002, which negatively affected Generation’s trading positions.
Other Revenue. Revenues also increased in 2003 as compared to 2002, as a result of a $76 million increase in sales of excess fossil fuel. The excess fossil fuel is a result of generating plants in Texas and New England operating at less than projected levels.
340
Purchased Power and Fuel
Generation’s supply of sales in 2003 and 2002, excluding the trading portfolio, was as follows:
| Supply of Sales (in GWhs) |
2003 |
2002 |
% Change |
||||
| Nuclear generation (a) |
117,502 | 115,854 | 1.4 | % | |||
| Purchases—non-trading portfolio (b) |
82,860 | 78,710 | 5.3 | % | |||
| Fossil and hydroelectric generation |
24,310 | 12,976 | 87.3 | % | |||
| Total supply |
224,672 | 207,540 | 8.3 | % | |||
| (a) | Excluding AmerGen. |
| (b) | Including purchase power agreements with AmerGen. |
Generation’s supply mix changed as a result of increased nuclear generation due to a lower number of refueling and unplanned outages during 2003 as compared to 2002, increased fossil generation due to the Exelon New England plants acquired in November 2002, including plants under construction which became operational in the second and third quarters of 2003 which accounted for an increase of 8,426 GWhs. Additionally, the change included additional purchased power of 3,320 GWhs from Exelon New England, a new PPA with AmerGen, which increased purchased power by 3,049 GWhs in the second quarter of 2003, and 11,989 GWhs of other miscellaneous power purchases, which more than offset a 14,208 GWhs reduction in purchased power from Midwest Generation.
Purchased Power and Fuel Expense. The changes in Generation’s purchased power and fuel expense for the year ended December 31, 2003 compared to the same period in 2002 consisted of the following:
| Variance | |||
| Exelon New England |
$ | 429 | |
| Prices |
350 | ||
| Volume |
46 | ||
| Hedging activity |
22 | ||
| Other |
20 | ||
| Increase in purchased power and fuel expense |
$ | 867 | |
Exelon New England. Generation acquired Exelon New England in November 2002 and Mystic Units 8 and 9 began commercial operations during the second quarter of 2003, while Fore River began commercial operations during the third quarter of 2003.
Prices. The increase reflects higher market prices in 2003.
Volume. Purchased power increased in 2003 due to an increase in purchased power from AmerGen under a June 2003 PPA to purchase 100% of the output of Oyster Creek. Prior to the June 2003 PPA, Generation did not purchase power from Oyster Creek. Fuel expense increased due to increases in fossil fuel generation required to meet the increased market demand for energy and the acquisition of generating plants in Texas in April 2002.
Hedging Activity. Mark-to-market losses on hedging activities were $16 million in 2003 compared to a gain of $6 million in 2002.
Other. Other increases in purchased power and fuel were primarily due to additional nuclear fuel amortization of $16 million in 2003 resulting from under-performing fuel which was completely replaced
341
in May 2003 at the Quad Cities Unit 1 and $10 million due to the write-down of coal inventory in 2003 as a result of a fuel burn analysis.
Generation’s average margins per MWh sold for the years ended December 31, 2003 and 2002 were as follows:
| ($/MWh) |
2003 |
2002 |
% Change |
||||||
| Average revenue |
|||||||||
| Wholesale sales to affiliates (a) |
$ | 34.38 | $ | 33.98 | 1.2 | % | |||
| Wholesale electric sales |
35.99 | 29.80 | 20.8 | % | |||||
| Total—excluding the trading portfolio |
35.15 | 32.30 | 8.8 | % | |||||
| Average supply cost—excluding the trading portfolio (b) |
22.79 | 20.49 | 11.2 | % | |||||
| Average margin—excluding the trading portfolio |
12.36 | 11.81 | 4.7 | % | |||||
| (a) | Includes sales to Exelon Energy Company. |
| (b) | Average supply cost includes purchased power and fuel costs. |
Operating and Maintenance
The changes in operating and maintenance expense in 2003 as compared to 2002 consisted of the following:
| Variance |
||||
| Adoption of SFAS No. 143 (a) |
$ | 118 | ||
| Increased costs due to generating asset acquisitions in 2002 |
78 | |||
| Severance, pension and postretirement benefit costs associated with The Exelon Way |
60 | |||
| Increased employee fringe benefits primarily due to increased health care costs |
54 | |||
| Decreased refueling outage costs (b) |
(49 | ) | ||
| 2002 executive severance |
(19 | ) | ||
| Other |
(32 | ) | ||
| Increase in operating and maintenance expense |
$ | 210 | ||
| (a) | Due to a reclassification of decommissioning-related expenses upon the adoption of SFAS No. 143. |
| (b) | Includes cost savings of $19 million related to one of Generation’s co-owned facilities. Refueling outage days, not including Generation’s co-owned facilities, decreased from 202 in 2002 to 157 in 2003. |
The increase in operating and maintenance expense is primarily due to the decision to transition out of the ownership of Boston Generating during the third quarter of 2003, Generation recorded a long-lived asset impairment charge of $945 million ($573 million net of income taxes) in the third quarter of 2003. The remaining increase is due to payroll-related costs due to implementation of the programs associated with The Exelon Way, costs incurred due to generating asset acquisitions made in 2002, offset by lower refueling outage cost.
Nuclear fleet operating data and purchased power cost data for 2003 as compared to 2002 was as follows:
| 2003 |
2002 |
|||||||
| Nuclear fleet capacity factor (a) |
93.4 | % | 92.7 | % | ||||
| Nuclear fleet production cost per MWh (a) |
$ | 12.53 | $ | 13.00 | ||||
| Average purchased power cost for wholesale operations per MWh (b) |
$ | 43.29 | $ | 41.85 | ||||
| (a) | Including AmerGen and excluding Salem, which is operated by PSEG Nuclear. |
| (b) | Including PPAs with AmerGen. |
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The higher nuclear capacity factor and decreased production costs were primarily due to 56 fewer planned refueling outage days, resulting in a $36 million decrease in outage costs, including a $6 million decrease related to AmerGen, in 2003 as compared to 2002. The years ended 2003 and 2002 included 30 and 26 unplanned outages, respectively, resulting in a $2 million increase in non-refueling outage costs in 2003 as compared to 2002.
Impairment of the Long-Lived Assets of Boston Generating
In connection with the decision to transition out of the ownership of Boston Generating during the third quarter of 2003, Generation recorded a long-lived asset impairment charge of $945 million ($573 million net of income taxes). See Note 2 of Generation’s Notes to Consolidated Financial Statements for further discussion of the sale of Generation’s ownership interest in Boston Generating.
Depreciation and Amortization
The decrease in depreciation and amortization expense in 2003 as compared to 2002 was primarily attributable to a $130 million reduction in decommissioning expense net of ARC depreciation, as these costs are included in operating and maintenance expense after the adoption of SFAS No. 143, and a $12 million decrease due to life extensions of assets acquired in 2002. The decrease was partially offset by $65 million of additional depreciation expense on capital additions placed in service in 2002, of which $18 million of expense is related to plant acquisitions made after the third quarter of 2002.
Taxes Other Than Income
Taxes other than income decreased in 2003 compared to 2002 due primarily to a $20 million decrease in property taxes, a $13 million decrease in the Pennsylvania capital stock tax and the Texas franchise tax, and a $6 million decrease in payroll taxes.
Interest Expense
The increase in interest expense in 2003 as compared to 2002 is due to $18 million of higher interest related to the Boston Generating project debt outstanding in 2003 as well as the outstanding Sithe note. The increase was partially offset by a $14 million decrease resulting from interest expense no longer being recorded to offset decommissioning interest income in 2003. This offset is currently included as accretion expense in operating and maintenance expense.
Equity in Earnings of Unconsolidated Affiliates
The decrease in equity in earnings of unconsolidated affiliates in 2003 as compared to 2002 was due to a decrease of $21 million in the equity in earnings of Sithe, which was primarily the result of the sale of Sithe New England’s assets to Generation in November 2002. A decrease of $17 million in the equity in earnings of AmerGen also contributed to the overall decrease, which was primarily due to lower PPA revenues at AmerGen and increases in severance costs during 2003.
Other, Net
The decrease in other, net in 2003 as compared to 2002 was primarily a result of impairment charges related to Generation’s equity investment in Sithe due to an other-than-temporary decline in value of $255 million and a $25 million loss resulting from the purchase and subsequent sale of 50% of the assets of Sithe to Reservoir. See Note 3 of Generation’s Notes to Consolidated Financial Statements.
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Effective Income Tax Rate
The effective income tax rate was 43.0% for 2003 compared to 35.7% for 2002. This increase was primarily attributable to the impairment charges recorded in 2003 related to the long-lived assets of Boston Generating and Generation’s investment in Sithe, which resulted in a pre-tax loss. Other adjustments that affected income taxes include a decrease in tax-exempt interest in 2003 and an increase in nuclear decommissioning investment income for 2003.
Cumulative Effect of Changes in Accounting Principles
On January 1, 2003, Generation adopted SFAS No. 143 resulting in a benefit of $108 million (net of income taxes of $70 million).
On January 1, 2002, Generation adopted SFAS No. 142 resulting in a benefit of $13 million (net of income taxes of $9 million).
Liquidity and Capital Resources
Generation’s business is capital intensive and requires considerable capital resources. Generation’s capital resources are primarily provided by internally generated cash flows from operations and, to the extent necessary, external financing, including the issuance of commercial paper, participation in the intercompany money pool or capital contributions from Exelon. Generation’s access to external financing at reasonable terms is dependent on its credit ratings and general business conditions, as well as that of the utility industry in general. If these conditions deteriorate to the extent that Generation no longer has access to external financing sources at reasonable terms, Generation has access to a revolving credit facility, which Generation currently utilizes to support its commercial paper program. See the Credit Issues section of Liquidity and Capital Resources for further discussion. Capital resources, including cash, are used primarily to fund Generation’s capital requirements, including construction expenditures, investments in new and existing ventures, repayments of maturing debt, the payment of distributions to Exelon and contributions to Exelon’s pension plans. Any future acquisitions could require external financing or borrowings or capital contributions from Exelon.
Cash Flows from Operating Activities
Generation’s cash flows from operating activities primarily result from the sale of electric energy to wholesale customers, including Generation’s affiliated companies, as well as settlements arising from Generation’s trading activities. Generation’s future cash flow from operating activities will depend upon future demand and market prices for energy and the ability to continue to produce and supply power at competitive costs. Cash flows from operations have been and are expected to continue to provide a reliable, steady source of cash flow, sufficient to meet operating and capital expenditures requirements for the foreseeable future. See Business Outlook and Challenges in Managing the Business.
Cash flows provided by operations for the years ended December 31, 2004 and 2003 were $1,947 million and $1,453 million, respectively. Changes in Generation’s cash flows from operations are generally consistent with changes in its results of operations, as further adjusted by changes in working capital in the normal course of business and non-cash charges.
In addition to the items mentioned in Results of Operations, Generation’s operating cash flows in 2004 were affected by the following items:
| • | Receivables from Energy Delivery under the PPAs increased $28 million for 2004, compared to a decrease of $177 million in 2003. The decrease in 2003 was primarily due to the payment of certain trade receivables from ComEd. |
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| • | Net cash received for collateral for 2004 was $73 million, compared to $68 million paid in 2003. The year over year increase in cash flows of $141 million was primarily due to the reduction of cash collateral requirements for certain counterparties as a result of Generation negotiating the acceptance of letters of credit during 2004 to satisfy current and future collateral obligations. |
| • | At December 31, 2004 and 2003, Generation had income tax receivables of $87 million and $290 million, respectively. In 2003, Generation established an income tax receivable primarily associated with special depreciation allowances, which was received in 2004, resulting in the primary change in cash in 2004 as compared to 2003 associated with income taxes. |
| • | In December 2004, TXU and Generation terminated a tolling agreement and entered into a new agreement. Upon termination of the original agreement, Generation received a cash payment of $172 million. The resulting gain was deferred and will be recognized as income over the contractual term of the new agreement. See Note 2 of Generation’s Notes to Consolidated Financial Statements for further information regarding the transaction with TXU. |
| • | Discretionary contributions to Exelon’s defined benefit pension plans were $180 million in 2004 compared to $145 million in 2003. Generation’s minimum funding requirement to satisfy ERISA for 2004 was $11 million. See Note 14 of Generation’s Notes to Consolidated Financial Statements for further information regarding pension and postretirement benefits. |
Generation participates in Exelon’s defined benefit pension plans. Exelon’s plans currently meet the minimum funding requirements of ERISA; however, Exelon expects to make a discretionary pension plan contribution up to approximately $2 billion in 2005, of which $853 million is expected to be funded by Generation. Of the $853 million expected to be contributed to the pension plan during 2005, $13 million is estimated to be needed to satisfy ERISA minimum funding requirements for the pension plan obligations.
Cash Flows from Investing Activities
Cash flows used in investing activities were $1,103 million in 2004, compared to $1,301 million in 2003. Capital expenditures, including investment in nuclear fuel, were $960 million and $861 million in 2004 and 2003, respectively, and primarily represent additions to nuclear fuel and additions and upgrades to existing facilities. Capital expenditures for 2003 are stated net of proceeds from liquidated damages of $92 million received from Raytheon as a result of Raytheon not meeting the expected completion date and certain contractual performance criteria in connection with Raytheon’s construction of the Boston Generating facilities.
In addition to the recurring investing activities presented on the face of the Consolidated Statement of Cash Flows, significant investing activities during 2004 and 2003 were as follows:
| • | Generation received cash proceeds of $42 million from the January 2004 sale of three gas turbines that were classified as assets held for sale at December 31, 2003. |
| • | Generation received $24 million as a result of the transfer of Exelon Energy Company to Generation, effective January 1, 2004, and the consolidation of Sithe in accordance with FIN 46-R on March 31, 2004. See Notes 2 and 3 of Generation’s Notes to Consolidated Financial Statements for additional information on the transfer of Exelon Energy and the consolidation of Sithe, respectively. |
| • | Sithe collected a $20 million note receivable during 2004 related to the sale of certain businesses of Sithe during the fourth quarter of 2003 and the first quarter of 2004. |
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| • | On November 25, 2003, Generation, Reservoir and Sithe completed a series of transactions resulting in Generation and Reservoir each indirectly owning a 50% interest in Sithe. Net cash proceeds from the series of transactions were $44 million. In addition, a note was received from EXRES SHC, Inc. for $92 million. See Notes 3 and 20 of Generation’s Notes to Consolidated Financial Statements for further information regarding this transaction and Generation’s sale of Sithe. |
| • | In December 2003, Generation purchased the 50% interest in AmerGen held by British Energy plc for $240 million, net of cash acquired of $36 million. The acquisition was funded with cash provided by operations. |
Capital expenditures for 2005 are projected to be $1,073 million. Generation anticipates that nuclear refueling outages, including co-owned facilities, will increase from ten in 2004 to eleven in 2005. Generation’s capital expenditures are expected to be funded by internally generated funds.
Cash Flows from Financing Activities
Cash flows used in financing activities were $739 million in 2004 compared to $52 million in 2003. The increase in cash flows used in financing activities was primarily a result of a $500 million issuance of unsecured notes in 2003, a net repayment of intercompany borrowings of $162 million during 2004, compared to a $87 million net increase in intercompany borrowings in 2003 and a $316 million increase in dividend distributions to Exelon during 2004 as compared to 2003. In 2004, Generation paid $27 million of a note payable to Sithe, compared to $446 million paid in 2003. At December 31, 2004, Generation had repaid $473 million of the note payable, resulting in a remaining balance of $63 million, which was paid upon the completion of a series of transactions that resulted in Generation’s exit from its investment in Sithe on January 31, 2005. See Note 20 of Generation’s Notes to Consolidated Financial Statements for further information regarding the sale of Sithe. In October 2004, Generation issued $157 million of pollution control notes, the proceeds of which were distributed to Exelon.
From time to time and as market conditions warrant, Generation may engage in long-term debt retirements via tender offers, open market repurchases or other viable options to strengthen its balance sheet.
Credit Issues
Exelon Credit Facility. A description of Exelon’s credit agreements, and Generation’s participation therein, is set forth above under “Credit Issues—Exelon Credit Facility” in “Exelon Corporation—Liquidity and Capital Resources.”
Capital Structure. At December 31, 2004, Generation’s capital structure consisted of 51% member’s equity, 5% notes payable and 44% long-term debt. Long-term debt includes $1.2 billion of senior unsecured notes and $819 million related to Sithe Energies, Inc. debt, representing 14% of capitalization.
Generation Revolving Credit Facilities. On September 29, 2003, Generation closed on an $850 million revolving credit facility that replaced a $550 million revolving credit facility that had originally closed on June 13, 2003. Generation used the facility to make the first payment to Sithe relating to the $536 million note that was used to purchase Exelon New England. This note was restructured in June 2003 to provide for a payment of $210 million of the principal on June 16, 2003, payment of $236 million of the principal on the earlier of December 1, 2003 or upon a change of control of Generation and payment of the remaining principal on the earlier of December 1, 2005, upon reaching certain
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Sithe liquidity requirements, or upon a change of control of Generation. Generation paid $27 million on the note to Sithe in 2004. Generation terminated the $850 million revolving credit facility on December 22, 2003.
Intercompany Money Pool. A description of the intercompany money pool, and Generation’s participation therein, is set forth above under “Credit Issues—Intercompany Money Pool” in “Exelon Corporation—Liquidity and Capital Resources.” For the year ended December 31, 2004, Generation paid $3 million in interest to the money pool and earned less than $1 million in interest from its contributions to the intercompany money pool.
Security Ratings. A description of Generation’s security ratings is set forth above under “Credit Issues—Security Ratings” in “Exelon Corporation—Liquidity and Capital Resources.”
Fund Transfer Restrictions. Under applicable law, Generation can only pay dividends from undistributed or current earnings. Generation is precluded from lending or extending credit or indemnity to Exelon. At December 31, 2004, Generation had undistributed earnings of $761 million.
Contractual Obligations and Off-Balance Sheet Obligations
The following table summarizes Generation’s future estimated cash payments under existing contractual obligations, including payments due by period.
| Payment Due within |
Due 2010 and beyond | ||||||||||||||
| (in millions) |
Total |
2005 |
2006-2007 |
2008-2009 |
|||||||||||
| Long-term debt |
$ | 2,688 | $ | 44 | $ | 98 | $ | 120 | $ | 2,426 | |||||
| Intercompany money pool |
283 | 283 | — | — | — | ||||||||||
| Interest obligations related to |
|||||||||||||||
| long-term debt (a, b) |
1,955 | 159 | 306 | 286 | 1,204 | ||||||||||
| Capital leases |
50 | 3 | 5 | 4 | 38 | ||||||||||
| Operating leases |
723 | 45 | 87 | 80 | 511 | ||||||||||
| Purchase power obligations |
9,497 | 2,024 | 1,973 | 1,288 | 4,212 | ||||||||||
| Fuel purchase agreements |
3,639 | 639 | 985 | 616 | 1,399 | ||||||||||
| Other purchase commitments (c) |
230 | 66 | 75 | 57 | 32 | ||||||||||
| Obligation to minority shareholders |
49 | 3 | 5 | 5 | 36 | ||||||||||
| Pension ERISA minimum funding requirement |
13 | 13 | — | — | — | ||||||||||
| Spent nuclear fuel obligations |
878 | — | — | — | 878 | ||||||||||
| Total contractual obligations |
$ | 20,005 | $ | 3,279 | $ | 3,534 | $ | 2,456 | $ | 10,736 | |||||
| (a) | Interest payments are estimated based on final maturity dates of debt securities outstanding at December 31, 2004 and do not reflect anticipated future refinancing, early redemptions or debt issuances. Variable rate interest obligations are estimated based on rates as of December 31, 2004. |
| (b) | Includes Sithe-related interest payments of $71 million, $132 million, $115 million and $849 million for payments due in 2005, 2006-2007, 2008-2009, and 2010 and beyond, respectively. See Note 20 of Generation’s Notes to Consolidated Financial Statements for a discussion of the sale of Generation’s investment in Sithe. |
| (c) | Commitments for services and materials. |
See ITEM 8. Financial Statements and Supplementary Data—Generation’s Notes to Consolidated Financial Statements for additional information about:
| • | Long-term debt, see Note 11. |
| • | Capital lease obligations, see Note 11. |
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| • | Spent nuclear fuel obligation, see Note 13. |
| • | Pension ERISA minimum funding requirement, see Note 14. |
| • | Operating leases, see Note 16. |
| • | Purchase power obligations, see Note 16. |
| • | Obligation to minority shareholders, see Note 16. |
| • | Intercompany money pool, see Note 18. |
Mystic Development LLC (Mystic) a former affiliate of Exelon New England has a long-term agreement through January 2020 with Distrigas of Massachusetts Corporation (Distrigas) for gas supply, primarily for the Boston Generating units. Under the agreement, gas purchase prices from Distrigas are indexed to the New England gas markets. Exelon New England has guaranteed Mystic’s financial obligations to Distrigas under the long-term supply agreement. Exelon New England’s guarantee to Distrigas remained in effect following the transfer of ownership interest in Boston Generating in May 2004. Under FIN 45, approximately $16 million is included as a liability within the Consolidated Balance Sheet of Generation as of December 31, 2004 related to this guarantee. The terms of the guarantee do not limit the potential future payments that Exelon New England could be required to make under the guarantee.
Generation has an obligation to decommission its nuclear power plants. Upon adoption of SFAS No. 143, Generation was required to re-measure its decommissioning liabilities at fair value and recorded an asset retirement obligation of $2.4 billion on January 1, 2003. Increases in the asset retirement obligation resulting from the passage of time, are recorded as operating and maintenance expense. Increases in the asset retirement obligation resulting from a remeasurement are recorded with a corresponding asset retirement cost, which is a component of property, plant and equipment. At December 31, 2004, the asset retirement obligation recorded within Generation’s Consolidated Balance Sheet was $4.0 billion. Decommissioning expenditures are expected to occur primarily after the plants are retired. Based on current licenses and anticipated renewals, decommissioning expenditures for plants in operation are currently estimated to begin in 2029. To fund future decommissioning costs, Generation held $5.3 billion of investments in trust funds, including net unrealized gains and losses, at December 31, 2004. See ITEM 8. Financial Statements and Supplementary Data—Generation’s Notes to Consolidated Financial Statements for further discussion of Generation’s decommissioning obligation.
See Note 16 of Generation’s Notes to Consolidated Financial Statements for discussion of Generation’s commercial commitments as of December 31, 2004.
Variable Interest Entities. As of December 31, 2004, Generation was a 50% owner of Sithe. In accordance with FIN 46-R, Generation consolidated Sithe, within the financial statements as of March 31, 2004. The determination that Sithe qualified as a variable interest entity and that Generation was the primary beneficiary under FIN 46-R required analysis of the economic benefits accruing to all parties pursuant to their ownership interests supplemented by management’s judgment. See Note 3 and Note 20 of Generation’s Notes to Consolidated Financial Statements for additional information regarding the consolidation and sale of Sithe.
Other
Generation’s cash-flow hedges are affected by commodity prices. These hedge contracts primarily represent forward sales of Generation’s excess capacity that it expects to deliver. The majority of these contracts are expected to settle within the next three years. These contracts have specified credit limits pursuant to standardized contract terms and require that cash collateral be posted when the limits are
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exceeded. When power prices increase relative to Generation’s forward sales prices, it can be subject to collateral calls if Generation exceeds its credit limits; however, when power prices return to previous levels or when Generation delivers the power under its forward contracts, the collateral would be returned to Generation with no impact on its results of operations. Generation will satisfy its margin call obligations with the use of working capital or drawing on its available letters of credit. Generation believes that it has sufficient capability to fund any collateral requirements that could be reasonably expected to occur.
Critical Accounting Policies and Estimates
See Exelon, ComEd, PECO and Generation—Critical Accounting Policies and Estimates above for a discussion of Generation’s critical accounting policies and estimates.
Business Outlook and the Challenges in Managing the Business
The U.S. electric generation, transmission and distribution industry is in the midst of a fundamental and, at this point, uncertain transition from a fully regulated industry offering bundled service to an industry with unbundled services, some of which are regulated and others of which are priced in competitive markets. Generation operates in a highly competitive environment that is capital intensive.
A description of the business outlook and challenges in managing Generation’s business is set forth above under “Business Outlook and the Challenges in Managing the Business—Generation and General Business” in “Exelon Corporation—Management’s Discussion and Analysis of Financial Condition and Results of Operation.”
Further discussion of Generation’s liquidity position and capital resources and related challenges is included in the Liquidity and Capital Resources section.
New Accounting Pronouncements
See Note 1 of Generation’s Notes to Consolidated Financial Statements for information regarding new accounting pronouncements.
| ITEM 7A. | QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK—Generation |
Generation is exposed to market risks associated with commodity price, credit, interest rates and equity prices. These risks are described above under “Quantitative and Qualitative Disclosures about Market Risk—Exelon.”
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| ITEM 8. | FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA |
Report of Independent Registered Public Accounting Firm
To the Member and Board of Directors of Exelon Generation Company, LLC:
In our opinion, the consolidated financial statements listed in the index appearing under Item 15(a)(4)(i) present fairly, in all material respects, the financial position of Exelon Generation Company, LLC and Subsidiary Companies (Generation) at December 31, 2004 and 2003, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2004, in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedule listed in the index appearing under Item 15(a)(4)(ii) presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements. These financial statements and the financial statement schedule are the responsibility of Generation’s management. Our responsibility is to express an opinion on these financial statements and financial statement schedule based on our audits. We conducted our audits of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
As discussed in Note 1 to the consolidated financial statements, Generation changed its method of accounting for asset retirement obligations as of January 1, 2003 and its method of accounting for variable interest entities during 2004.
PricewaterhouseCoopers LLP
Chicago, Illinois
February 22, 2005
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Exelon Generation Company, LLC and Subsidiary Companies
Consolidated Statements of Income
| For the Year Ended December 31, |
||||||||||||
| (in millions) |
2004 |
2003 |
2002 |
|||||||||
| Operating revenues |
||||||||||||
| Operating revenues |
$ | 4,097 | $ | 4,010 | $ | 2,631 | ||||||
| Operating revenues from affiliates |
3,841 | 4,125 | 4,227 | |||||||||
| Total operating revenues |
7,938 | 8,135 | 6,858 | |||||||||
| Operating expenses |
||||||||||||
| Purchased power |
2,315 | 3,158 | 2,980 | |||||||||
| Purchased power from affiliates |
10 | 429 | 314 | |||||||||
| Fuel |
1,845 | 1,533 | 959 | |||||||||
| Impairment of Boston Generating, LLC long-lived assets |
— | 945 | — | |||||||||
| Operating and maintenance |
2,034 | 1,717 | 1,504 | |||||||||
| Operating and maintenance from affiliates |
239 | 149 | 152 | |||||||||
| Depreciation and amortization |
294 | 199 | 276 | |||||||||
| Taxes other than income |
171 | 120 | 164 | |||||||||
| Total operating expense |
6,908 | 8,250 | 6,349 | |||||||||
| Operating income (loss) |
1,030 | (115 | ) | 509 | ||||||||
| Other income and deductions |
||||||||||||
| Interest expense |
(164 | ) | (75 | ) | (68 | ) | ||||||
| Interest expense to affiliates |
(3 | ) | (13 | ) | (7 | ) | ||||||
| Equity in earnings (losses) of unconsolidated affiliates |
(14 | ) | 49 | 87 | ||||||||
| Interest income from affiliates |
— | 1 | 6 | |||||||||
| Other, net |
143 | (263 | ) | 80 | ||||||||
| Total other income and deductions |
(38 | ) | (301 | ) | 98 | |||||||
| Income (loss) before income taxes, minority interest, and cumulative effect of changes in accounting principle |
992 | (416 | ) | 607 | ||||||||
| Income taxes |
372 | (179 | ) | 217 | ||||||||
| Income (loss) before minority interest and cumulative effect of changes in accounting principle |
620 | (237 | ) | 390 | ||||||||
| Minority interest |
21 | (4 | ) | (3 | ) | |||||||
| Income (loss) before cumulative effect of changes in accounting principle |
641 | (241 | ) | 387 | ||||||||
| Cumulative effect of changes in accounting principle (net of income taxes of $22, $70 and $9, respectively) |
32 | 108 | 13 | |||||||||
| Net income (loss) |
$ | 673 | $ | (133 | ) | $ | 400 | |||||
See Notes to Consolidated Financial Statements
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Exelon Generation Company, LLC and Subsidiary Companies
Consolidated Statements of Cash Flows
| For the Year Ended December 31, |
||||||||||||
| (in millions) |
2004 |
2003 |
2002 |
|||||||||
| Cash flows from operating activities |
||||||||||||
| Net income (loss) |
$ | 673 | $ | (133 | ) | $ | 400 | |||||
| Adjustments to reconcile net income (loss) to net cash flows provided by operating activities: |
||||||||||||
| Depreciation, amortization and accretion, including nuclear fuel |
923 | 754 | 650 | |||||||||
| Cumulative effect of changes in accounting principles (net of income taxes) |
(32 | ) | (108 | ) | (13 | ) | ||||||
| Impairment of investment in Sithe Energies, Inc. |
— | 255 | — | |||||||||
| Impairment of long-lived assets |
— | 952 | — | |||||||||
| Deferred income taxes and amortization of investment tax credits |
124 | 60 | 132 | |||||||||
| Provision for uncollectible accounts |
2 | (2 | ) | 26 | ||||||||
| (Gain) loss on sale of investments |
(91 | ) | 25 | — | ||||||||
| Other decommissioning-related activities |
169 | 37 | — | |||||||||
| Equity in (earnings) losses of unconsolidated affiliates |
14 | (49 | ) | (87 | ) | |||||||
| Net realized (gains) losses on nuclear decommissioning trust funds |
(72 | ) | 16 | 32 | ||||||||
| Other non-cash operating activities |
(47 | ) | (10 | ) | 57 | |||||||
| Changes in assets and liabilities: |
||||||||||||
| Accounts receivable |
(67 | ) | (23 | ) | (159 | ) | ||||||
| Receivables and payables to affiliates, net |
11 | 195 | (72 | ) | ||||||||
| Inventories |
(35 | ) | (29 | ) | (33 | ) | ||||||
| Other current assets |
64 | (35 | ) | (71 | ) | |||||||
| Accounts payable, accrued expenses and other current liabilities |
76 | 16 | 124 | |||||||||
| Income taxes |
228 | (361 | ) | 129 | ||||||||
| Net realized and unrealized mark-to-market and hedging transactions |
37 | (9 | ) | 26 | ||||||||
| Pension and non-pension postretirement benefits obligations |
(92 | ) | (50 | ) | (60 | ) | ||||||
| Other noncurrent assets and liabilities |
62 | (48 | ) | 69 | ||||||||
| Net cash flows provided by operating activities |
1,947 | 1,453 | 1,150 | |||||||||
| Cash flows from investing activities |
||||||||||||
| Capital expenditures |
(960 | ) | (953 | ) | (990 | ) | ||||||
| Proceeds from liquidated damages |
— | 92 | — | |||||||||
| Proceeds from nuclear decommissioning trust fund sales |
2,320 | 2,341 | 1,612 | |||||||||
| Investment in nuclear decommissioning trust funds |
(2,587 | ) | (2,564 | ) | (1,824 | ) | ||||||
| Acquisition of businesses, net of cash acquired |
— | (272 | ) | (445 | ) | |||||||
| Proceeds from sales of investments |
24 | 82 | — | |||||||||
| Net cash increase from consolidation of Sithe Energies, Inc. and Exelon Energy Company |
24 | — | — | |||||||||
| Change in restricted cash |
36 | (63 | ) | (12 | ) | |||||||
| Other investing activities |
40 | 36 | (27 | ) | ||||||||
| Net cash flows used in investing activities |
(1,103 | ) | (1,301 | ) | (1,686 | ) | ||||||
| Cash flows from financing activities |
||||||||||||
| Issuance of long-term debt |
157 | 1,066 | 30 | |||||||||
| Retirement of long-term debt |
(62 | ) | (570 | ) | (5 | ) | ||||||
| Change in note payable, affiliate |
(162 | ) | 87 | 329 | ||||||||
| Payment on acquisition note payable to Sithe Energies, Inc. |
(27 | ) | (446 | ) | — | |||||||
| Distribution to member |
(662 | ) | (189 | ) | (27 | ) | ||||||
| Contribution from member |
17 | — | — | |||||||||
| Contribution from minority interest of consolidated subsidiary |
— | — | 43 | |||||||||
| Net cash flows (used in) provided by financing activities |
(739 | ) | (52 | ) | 370 | |||||||
| Increase (decrease) in cash and cash equivalents |
105 | 100 | (166 | ) | ||||||||
| Cash and cash equivalents at beginning of period |
158 | 58 | 224 | |||||||||
| Cash and cash equivalents at end of period |
$ | 263 | $ | 158 | $ | 58 | ||||||
See Notes to Consolidated Financial Statements
352
Exelon Generation Company, LLC and Subsidiary Companies
Consolidated Balance Sheets
| December 31, |
||||||||
| (in millions) |
2004 |
2003 |
||||||
| Assets |
||||||||
| Current assets |
||||||||
| Cash and cash equivalents |
$ | 263 | $ | 158 | ||||
| Restricted cash and investments |
26 | 75 | ||||||
| Accounts receivable, net |
||||||||
| Customer |
525 | 389 | ||||||
| Other |
209 | 402 | ||||||
| Mark-to-market derivative assets |
403 | 322 | ||||||
| Receivables from affiliates |
332 | 421 | ||||||
| Inventories, at average cost |
||||||||
| Fossil fuel |
112 | 98 | ||||||
| Materials and supplies |
255 | 259 | ||||||
| Assets held for sale |
— | 36 | ||||||
| Deferred income taxes |
48 | 40 | ||||||
| Prepayments and other current assets |
148 | 238 | ||||||
| Total current assets |
2,321 | 2,438 | ||||||
| Property, plant and equipment, net |
7,536 | 7,106 | ||||||
| Deferred debits and other assets |
||||||||
| Nuclear decommissioning trust funds |
5,262 | 4,721 | ||||||
| Investments |
103 | 65 | ||||||
| Receivable from affiliate |
11 | 22 | ||||||
| Prepaid pension asset |
199 | 79 | ||||||
| Mark-to-market derivative asset |
373 | 100 | ||||||
| Other |
633 | 118 | ||||||
| Total deferred debits and other assets |
6,581 | 5,105 | ||||||
| Total assets |
$ | 16,438 | $ | 14,649 | ||||
| Liabilities and Member’s equity |
||||||||
| Current liabilities |
||||||||
| Long-term debt due within one year |
$ | 47 | $ | 1,068 | ||||
| Accounts payable |
856 | 848 | ||||||
| Mark-to-market derivative liabilities |
598 | 581 | ||||||
| Payables to affiliates |
42 | 1 | ||||||
| Notes payable to affiliates |
283 | 506 | ||||||
| Accrued expenses |
367 | 423 | ||||||
| Other |
223 | 126 | ||||||
| Total current liabilities |
2,416 | 3,553 | ||||||
| Long-term debt |
2,583 | 1,649 | ||||||
| Deferred credits and other liabilities |
||||||||
| Asset retirement obligation |
3,980 | 2,996 | ||||||
| Pension obligation |
21 | 21 | ||||||
| Non-pension postretirement benefits obligation |
584 | 555 | ||||||
| Spent nuclear fuel obligation |
878 | 867 | ||||||
| Deferred income taxes |
506 | 195 | ||||||
| Unamortized investment tax credits |
210 | 218 | ||||||
| Payables to affiliates |
1,479 | 1,195 | ||||||
| Mark-to-market derivative liabilities |
323 | 133 | ||||||
| Other |
375 | 308 | ||||||
| Total deferred credits and other liabilities |
8,356 | 6,488 | ||||||
| Total liabilities |
13,355 | 11,690 | ||||||
| Commitments and contingencies |
||||||||
| Minority interest of consolidated subsidiary |
44 | 3 | ||||||
| Member’s equity |
||||||||
| Membership interest |
2,361 | 2,490 | ||||||
| Undistributed earnings |
761 | 602 | ||||||
| Accumulated other comprehensive loss |
(83 | ) | (136 | ) | ||||
| Total Member’s equity |
3,039 | 2,956 | ||||||
| Total liabilities and Member’s equity |
$ | 16,438 | $ | 14,649 | ||||
See Notes to Consolidated Financial Statements
353
Exelon Generation Company, LLC and Subsidiary Companies
Consolidated Statements of Changes in Membership Interest
| (in millions) |
Membership Interest |
Undistributed Earnings |
Accumulated Other Comprehensive Income (Loss) |
Total Member’s Equity |
||||||||||||
| Balance, December 31, 2001 |
$ | 2,315 | $ | 524 | $ | (31 | ) | $ | 2,808 | |||||||
| Net income |
— | 400 | — | 400 | ||||||||||||
| Distribution to member |
(30 | ) | — | — | (30 | ) | ||||||||||
| Allocation of tax benefit from Member |
11 | — | — | 11 | ||||||||||||
| Other comprehensive loss, net of income taxes of $(223) |
— | — | (290 | ) | (290 | ) | ||||||||||
| Balance, December 31, 2002 |
2,296 | 924 | (321 | ) | 2,899 | |||||||||||
| Net loss |
— | (133 | ) | — | (133 | ) | ||||||||||
| Non-cash distribution to Member |
(17 | ) | — | — | (17 | ) | ||||||||||
| Distribution to Member |
— | (189 | ) | — | (189 | ) | ||||||||||
| Cumulative effect of FAS 143 adoption |
210 | — | — | 210 | ||||||||||||
| Contribution from Member |
1 | — | — | 1 | ||||||||||||
| Other comprehensive income, net of income taxes of $179 |
— | — | 185 | 185 | ||||||||||||
| Balance, December 31, 2003 |
2,490 | 602 | (136 | ) | 2,956 | |||||||||||
| Net income |
— | 673 | — | 673 | ||||||||||||
| Non-cash distribution to Member |
— | (9 | ) | — | (9 | ) | ||||||||||
| Distribution to Member |
(157 | ) | (505 | ) | — | (662 | ) | |||||||||
| Transfer of Exelon Energy |
(4 | ) | — | 2 | (2 | ) | ||||||||||
| Consolidation of Sithe in accordance with |
— | — | (6 | ) | (6 | ) | ||||||||||
| Contribution from Member |
6 | — | — | 6 | ||||||||||||
| Allocation of tax benefit from Member |
26 | — | — | 26 | ||||||||||||
| Other comprehensive income, net of income taxes of $30 |
— | — | 57 | 57 | ||||||||||||
| Balance, December 31, 2004 |
$ | 2,361 | $ | 761 | $ | (83 | ) | $ | 3,039 | |||||||
See Notes to Consolidated Financial Statements
354
Exelon Generation Company, LLC and Subsidiary Companies
Consolidated Statements of Comprehensive Income
| For the Years Ended December 31, |
|||||||||||
| (in millions) |
2004 |
2003 |
2002 |
||||||||
| Net income (loss) |
$ | 673 | $ | (133 | ) | $ | 400 | ||||
| Other comprehensive income (loss) |
|||||||||||
| SFAS No. 143 transition adjustment, net of income taxes of $167 |
— | 168 | — | ||||||||
| Change in net unrealized gain (loss) on cash-flow hedges, net of income taxes of $8, $(15) and $(104), respectively |
7 | (21 | ) | (164 | ) | ||||||
| Foreign currency translation, net of income taxes of $0, $0 and $0, respectively |
1 | — | — | ||||||||
| Unrealized gain (loss) on marketable securities, net of income taxes of $31, $27 and $(118), respectively |
49 | 38 | (126 | ) | |||||||
| Total other comprehensive income (loss) |
57 | 185 | (290 | ) | |||||||
| Total comprehensive income |
$ | 730 | $ | 52 | $ | 110 | |||||
See Notes to Consolidated Financial Statements
355
Exelon Generation Company, LLC and Subsidiary Companies
Notes to Consolidated Financial Statements
(Dollars in millions, unless otherwise noted)
1. Significant Accounting Policies
Description of Business
Exelon Generation Company, LLC (Generation) is a limited liability company engaged principally in the production and wholesale marketing and sale of electricity in various regions of the United States. Generation is wholly owned by Exelon Corporation (Exelon). Generation has numerous wholly owned subsidiaries. These subsidiaries were primarily established to hold certain nuclear, hydroelectric, intermediate and peaking-unit facilities, as well as the 50% interest in Sithe Energies, Inc. (Sithe), and 49.5% interests in Termoeléctrica del Golfo (TEG) and Termoeléctrica Peñoles (TEP), two 230 MW projects in Mexico that commenced commercial operations in the second quarter of 2004. The interests in TEG and TEP were acquired from Sithe in the fourth quarter of 2004. In addition, Generation also has a finance company subsidiary, Generation Finance Company, LLC, which provides certain financing for Generation’s other subsidiaries. Effective January 1, 2004, Exelon Enterprises Company, LLC’s (Enterprises) competitive retail sales business, Exelon Energy Company, became part of Generation. See Note 2—Acquisitions and Dispositions for information regarding the disposition of businesses within the Enterprises segment and Note 20—Subsequent Events for information regarding the sale of Sithe.
Basis of Presentation
The consolidated financial statements of Generation include the accounts of its majority-owned subsidiaries after the elimination of intercompany transactions. Investments and joint ventures in which a 20% to 50% interest is owned and a significant influence is exerted are accounted for under the equity method of accounting. The proportionate interests in jointly owned electric plants are consolidated. Investments in which less than a 20% interest is owned are primarily accounted for under the cost method of accounting.
Generation owns 100% of all significant consolidated subsidiaries, either directly or indirectly, except for Southeast Chicago Energy Project, LLC (SCEP) and Sithe, of which Generation owns 71% and 50%, respectively. See Note 3—Sithe and Note 20—Subsequent Events for information regarding transactions that resulted in the ultimate sale of Generation’s investment in Sithe on January 31, 2005. Generation has reflected the third-party interests in the above majority-owned investments as minority interests in its Consolidated Financial Statements. As a result of the adoption of Statement of Financial Accounting Standards (SFAS) No. 150, “Accounting for Certain Financial Instruments with Characteristics of Both Liabilities and Equity” (SFAS No. 150) on July 1, 2003, Generation reclassified the minority interest associated with SCEP to a long-term liability. The total minority interest related to SCEP was $49 million and $51 million as of December 31, 2004 and 2003, respectively. Prior periods were not restated.
In accordance with Financial Accounting Standards Board (FASB) Interpretation No. (FIN) 46 (revised December 2003), “Consolidation of Variable Interest Entities” (FIN 46-R), Sithe, a 50% owned subsidiary of Generation, was consolidated in Generation’s financial statements as of March 31, 2004. See below for further discussion of the adoption of FIN 46-R and the resulting consolidation of Sithe.
Reclassifications
Certain prior year amounts have been reclassified for comparative purposes. The reclassifications did not affect net income or member’s equity.
356
Exelon Generation Company, LLC and Subsidiary Companies
Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, unless otherwise noted)
Use of Estimates
The preparation of financial statements in conformity with accounting principles generally accepted in the United States (GAAP) requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. Areas in which significant estimates have been made include, but are not limited to, the accounting for derivatives, nuclear decommissioning costs and asset retirement obligations, inventory reserves, allowance for doubtful accounts, fixed asset depreciation, asset impairments, severance, pension and other postretirement benefits, taxes, unbilled energy revenues and environmental costs.
Variable Interest Entities
FIN 46-R addressed the requirements for consolidating certain variable interest entities. FIN 46 was effective for Exelon’s variable interest entities created after January 31, 2003. FIN 46-R was effective December 31, 2003 for Exelon’s other variable interest entities that were considered to be special-purpose entities and as of March 31, 2004 for all other variable interest entities.
Generation consolidated Sithe, a 50% owned subsidiary, as of March 31, 2004 pursuant to the provisions of FIN 46-R and recorded income of $32 million (net of income taxes) as a result of this consolidation, which included the reversal of guarantees of Sithe’s commitments previously recorded by Generation. This income was reported as a cumulative effect of a change in accounting principle in the first quarter of 2004. As of March 31, 2004, Generation was a 50% owner of Sithe and had accounted for Sithe as an unconsolidated equity method investment prior to March 31, 2004. Sithe owns and operates power-generating facilities and was sold by Generation on January 31, 2005. See Note 3—Sithe and Note 20—Subsequent Events for additional information on the consolidation of Sithe, and the subsequent sale of Generation’s investment in Sithe.
Revenues
Operating Revenues. Operating revenues are recorded as energy is delivered to customers. At the end of each month, Generation accrues an estimate for the unbilled amount of energy delivered to its customers. See Note 5—Accounts Receivable for further discussion.
Option Contracts, Swaps, and Commodity Derivatives. Premiums received and paid on option contracts and swap arrangements considered “normal” derivatives pursuant to SFAS No. 133, “Accounting for Derivatives and Hedging Activities” (SFAS No. 133) are amortized to revenue and expensed over the lives of the contracts. Certain option contracts and swap arrangements are considered derivative instruments and are recorded at fair value with subsequent changes in fair value recognized as revenues and expenses unless hedge accounting is applied. Commodity derivatives used for trading purposes are accounted for using the mark-to-market method with the unrealized gains and losses recognized in current period income.
Trading Activities. Generation accounts for its trading activities under the provisions of Emerging Issues Task Force (EITF) Issue No. 02-3, “Accounting for Contracts Involved in Energy Trading and Risk Management Activities” (EITF 02-3), which requires revenues and energy costs related to energy trading contracts to be presented on a net basis in the income statement.
357
Exelon Generation Company, LLC and Subsidiary Companies
Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, unless otherwise noted)
Physically Settled Derivative Contracts. Generation accounts for realized gains and losses on physically settled derivative contracts not “held for trading purposes” in accordance with EITF Issue No. 03-11, “Reporting Realized Gains and Losses on Derivative Instruments That Are Subject to FASB Statement No. 133, ‘Accounting for Derivative Instruments and Hedging Activities,’ and Not ‘Held for Trading Purposes’ as Defined in EITF Issue No. 02-3, ‘Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities’” (EITF 03-11).
EITF 03-11 was ratified by the FASB in August 2003. The EITF concluded that determining whether realized gains and losses on physically settled derivative contracts not “held for trading purposes” should be reported in the income statement on a gross or net basis is a matter of judgment that depends on the relevant facts and circumstances. Generation adopted EITF 03-11 as of January 1, 2004 and presented $966 million of purchased power and $14 million of fuel expense net within revenues during 2004. Prior periods were not reclassified. The adoption of EITF 03-11 had no effect on Exelon’s net income. Had EITF 03-11 been retroactively applied to 2003, operating revenues, purchased power and fuel expense would have been affected as follows:
| 2003 |
As Reported |
EITF 03-11 Impact |
Pro Forma | |||||||
| Operating revenue |
$ | 8,135 | $ | (996 | ) | $ | 7,139 | |||
| Purchased power |
3,587 | (943 | ) | 2,644 | ||||||
| Fuel expense |
1,533 | (53 | ) | 1,480 | ||||||
Generation is unable to determine the impact on operating revenues, purchased power and fuel expense, had EITF 03-11 been applied retroactively to 2002 results of operations, due to system constraints.
Stock-Based Compensation
Generation participates in Exelon’s stock-based compensation plans. Exelon accounts for its stock-based compensation plans under the intrinsic method prescribed by Accounting Principles Board No. 25, “Accounting for Stock Issued to Employees” and related interpretations and follows the disclosure requirements of SFAS No. 123, “Accounting for Stock-Based Compensation” (SFAS No. 123), and SFAS No. 148, “Accounting for Stock-Based Compensation—Transition and Disclosure—an amendment of FASB Statement No. 123.” Accordingly, no compensation expense for stock options has been recognized within the Consolidated Statements of Income. The table below shows the effect on Generation’s net income for 2004, 2003 and 2002 had Exelon elected to account for its stock-based compensation plans using the fair-value method under SFAS No. 123:
| 2004 |
2003 |
2002 | ||||||||
| Net income (loss)—as reported |
$ | 673 | $ | (133 | ) | $ | 400 | |||
| Deduct: Total stock-based compensation expense determined under fair-value method for all awards, net of income taxes(a) |
12 | 11 | 15 | |||||||
| Pro forma net income (loss) |
$ | 661 | $ | (144 | ) | $ | 385 | |||
| (a) | The fair value of options granted was estimated using a Black-Scholes option pricing model. |
Income Taxes
Deferred Federal and state income taxes are provided on all significant temporary differences between the book basis and the tax basis of assets and liabilities and for tax benefits carried forward.
358
Exelon Generation Company, LLC and Subsidiary Companies
Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, unless otherwise noted)
Investment tax credits previously utilized for income tax purposes have been deferred on the Consolidated Balance Sheets and are recognized in book income over the life of the related property.
Exelon and its subsidiaries, including Generation, file a consolidated return for Federal and certain state income tax returns. Income taxes of the Exelon consolidated group are allocated to Generation based on the separate return method. Generation estimates its income tax valuation allowance by assessing which deferred tax assets are more likely than not to be realized in the future. See Note 12—Income Taxes for further discussion.
Generation is a party to an agreement (Tax Sharing Agreement) with Exelon and other subsidiaries of Exelon that provides for the allocation of consolidated tax liabilities. The Tax Sharing Agreement generally provides that each party is allocated an amount of tax similar to that which would be owed had the party been separately subject to tax. Any net benefit attributable to the parent is reallocated to other members. That allocation is treated as a contribution to the capital of the party receiving the benefit.
Comprehensive Income
Comprehensive income includes all changes in equity during a period except those resulting from investments by and distributions to the member. Other comprehensive income primarily relates to unrealized gains or losses on securities held in nuclear decommissioning trust funds and unrealized gains and losses on cash-flow hedge instruments. Comprehensive income is reflected in the Consolidated Statements of Changes in Membership Interest and the Consolidated Statements of Comprehensive Income.
Cash and Cash Equivalents
Generation considers all temporary cash investments purchased with an original maturity of three months or less to be cash equivalents.
Restricted Cash and Investments
As of December 31, 2004, restricted cash and investments primarily represented restricted cash related to Sithe’s Independence Plant partnership distribution fund. As of December 31, 2003, the balance related to liquidated damages receipts, which were restricted as to use for the construction of the Exelon New England facilities.
Restricted cash and investments not available for general operations or to satisfy current liabilities are classified as noncurrent assets. As of December 31, 2004, $93 million of Sithe’s restricted cash and investments were classified within deferred debits and other assets, which includes $83 million of debt service reserves, major overhaul reserves of $7 million and lease service reserves of $3 million. As of December 31, 2003, there were no restricted cash and investments classified as noncurrent assets.
Allowance for Doubtful Accounts
The allowance for doubtful accounts reflects Generation’s best estimate of probable losses in the accounts receivable balances. The allowance is based on known uncollateralized troubled accounts, historical experience and other currently available evidence.
359
Exelon Generation Company, LLC and Subsidiary Companies
Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, unless otherwise noted)
Inventories
Inventory is recorded at the lower of cost or market, and provisions are made for excess and obsolete inventory when appropriate.
Fossil Fuel. Fossil fuel inventory includes the weighted average costs of stored natural gas, coal and oil. The costs of natural gas, coal and oil are generally included in inventory when purchased and charged to fuel expense when used.
Materials and Supplies. Materials and supplies inventory generally includes the average costs of generating plant materials. Materials are generally charged to inventory when purchased and then expensed or capitalized to plant, as appropriate, when installed.
Emission Allowances
Emission allowances are included in inventories and other assets and are carried at the lower of weighted average cost or market and charged to fuel expense as they are used in operations. Generation’s emission allowance balances as of December 31, 2004 and 2003 were $106 million and $105 million, respectively.
Marketable Securities
Marketable securities are classified as available-for-sale securities and reported at fair value pursuant to SFAS No. 115, “Accounting for Certain Investments in Debt and Equity Securities” (SFAS No. 115). Unrealized gains and losses, net of tax, on nuclear decommissioning trust funds transferred to Generation from PECO Energy Company (PECO) and Commonwealth Edison Company (ComEd) are reflected in the payables to affiliates on Generation’s Consolidated Balance Sheets. Unrealized gains and losses on nuclear decommissioning trust funds for the AmerGen Energy Company, LLC (AmerGen) units are reported in other comprehensive income. Prior to the adoption of SFAS No. 143, “Accounting for Asset Retirement Obligations” (SFAS No. 143) on January 1, 2003, unrealized gains and losses on marketable securities held in the nuclear decommissioning trust funds were reported in accumulated depreciation for operating units transferred to Generation from PECO and as other comprehensive income for operating and retired units transferred to Generation from ComEd. At December 31, 2004 and 2003, Generation had no held-to-maturity securities.
Property, Plant and Equipment
Property, plant and equipment is recorded at cost. The cost of maintenance, repairs and minor replacements of property is charged to maintenance expense as incurred.
Upon retirement, the cost of property, including net salvage cost, is charged to accumulated depreciation. See Note 6—Property, Plant and Equipment and Note 17—Supplemental Financial Information for further discussion.
Leases
Generation accounts for leases in accordance with SFAS No. 13 “Accounting for Leases” and determines whether its long-term power purchase and sales contracts are leases pursuant to EITF
360
Exelon Generation Company, LLC and Subsidiary Companies
Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, unless otherwise noted)
Issue No. 01-8, “Determining Whether an Arrangement is a Lease” (EITF 01-8) which applies to arrangements initiated or modified after October 1, 2003. At the inception of the lease, or subsequent modification, Generation determines whether the lease is an operating or capital lease based upon its terms and characteristics. Several of Generation’s long-term power purchase agreements which have been determined to be operating leases have significant contingent rental payments which are dependent on the future operating characteristics of the associated plants such as plant availability. Generation recognizes contingent rental expense when it becomes probable of payment.
Nuclear Fuel
The cost of nuclear fuel is capitalized and charged to fuel expense using the unit-of-production method. The estimated cost of disposal of Spent Nuclear Fuel (SNF) is established per the Standard Waste Contract with the Department of Energy (DOE) and is expensed at one mill ($.001) per kWh of net nuclear generation. On-site SNF storage costs are capitalized or expensed, as incurred, based upon the nature of the work performed.
Nuclear Outage Costs
Costs associated with nuclear outages are recorded in the period incurred.
Capitalized Software Costs
Costs incurred during the application development stage of software that is developed or obtained for internal use are capitalized. At December 31, 2004 and 2003, unamortized capitalized software costs totaled $30 million and $42 million, respectively. Such capitalized amounts are amortized ratably over the expected lives of the projects when they become operational, generally not to exceed ten years. During 2004, 2003 and 2002, Generation amortized capitalized software costs of $16 million, $8 million and $10 million, respectively.
Depreciation and Amortization
Depreciation is provided over the estimated service lives of property, plant and equipment on a straight-line basis using the composite method. Annual depreciation provisions for financial reporting purposes, expressed as a percentage of average service life for electric generating assets, are presented in the table below.
| Asset Category |
2004 |
2003 |
2002 |
||||||
| Electric-generation |
3.34 | % | 2.90 | % | 3.58 | % |
Nuclear Generating Station Decommissioning
Generation accounts for the costs of decommissioning its nuclear generating stations in accordance with SFAS No. 143. See Note 13—Nuclear Decommissioning and Spent Fuel Storage for information regarding the adoption and application of SFAS No. 143 and Cumulative Effect of Changes in Accounting Principle below for pro forma net income for the year ended December 31, 2002, adjusted as if SFAS No. 143 had been applied during that period.
361
Exelon Generation Company, LLC and Subsidiary Companies
Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, unless otherwise noted)
Capitalized Interest
Generation uses SFAS No. 34, “Capitalizing Interest Costs,” to calculate the costs during construction of debt funds used to finance its construction projects. Generation recorded capitalized interest of $11 million, $15 million and $24 million in 2004, 2003 and 2002, respectively.
Guarantees
Beginning February 1, 2003, pursuant to FIN 45, “Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness to Others” (FIN 45), Generation recognizes, at the inception of a guarantee, a liability for the fair market value of the obligations it has undertaken in issuing the guarantee, including its ongoing obligation to perform over the term of the guarantee in the event that the specified triggering events or conditions occur.
The liability that is initially recognized at the inception of the guarantee is reduced as Generation is released from risk under the guarantee. Depending on the nature of the guarantee, Generation’s release from risk may be recognized only upon the expiration or settlement of the guarantee or by a systematic and rational amortization method over the term of the guarantee. The recognition and subsequent adjustment of the liability is highly dependent upon the nature of the associated guarantee.
Asset Impairments
Long-Lived Assets. Generation evaluates the carrying value of long-lived assets to be held and used for impairment whenever indications of impairment exist in accordance with the requirements of SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets” (SFAS No. 144). The carrying value of long-lived assets is considered impaired when the projected undiscounted cash flows are less than the carrying value. In that event, a loss would be recognized based on the amount by which the carrying value exceeds the fair value. Fair value is determined primarily by available market valuations or, if applicable, discounted cash flows. See Note 2—Acquisitions and Dispositions for a description of the impairment charge recorded in 2003 related to the long-lived assets of Boston Generating, LLC (Boston Generating).
Upon meeting certain criteria defined by SFAS No. 144, the assets and liabilities that compose a disposal group are classified as held for sale and the carrying value of these assets is adjusted downward, if necessary, to the estimated sales price, less cost to sell. The assets and associated liabilities that are part of a disposal group are classified as held for sale. See Note 2—Acquisitions and Disposition for a description of assets and liabilities classified as held for sale during 2004. Generation held no assets or liabilities classified as held for sale as of December 31, 2004.
Investments. Investments are considered to be impaired when a decline in fair value is judged to be other-than-temporary. If the cost of an investment exceeds its fair value, Generation evaluates, among other factors, general market conditions, the duration and extent to which the fair value is less than cost, as well as Generation’s intent and ability to hold the investment. Generation also considers specific adverse conditions related to the financial health of and business outlook for the investee. Once a decline in fair value is determined to be other-than-temporary, an impairment charge is recorded and a new cost basis is established. See Note 3—Sithe for a description of the impairments recorded in 2003 related to Generation’s investment in Sithe and Note 15—Fair Value of Financial Assets and Liabilities for a description of the other-than-temporary impairments in the nuclear decommissioning trust funds determined in 2004.
362
Exelon Generation Company, LLC and Subsidiary Companies
Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, unless otherwise noted)
Derivative Financial Instruments
Generation enters into derivatives to manage its exposure to fluctuations in interest rates, changes in interest rates related to planned future debt issuances and changes in the fair value of outstanding debt. Generation utilizes derivatives with respect to energy transactions to manage the utilization of its available generating capability and provisions of wholesale energy to its affiliates. Generation also utilizes energy option contracts and energy financial swap arrangements to limit the market price risk associated with forward energy commodity contracts. Additionally, Generation enters into energy-related derivatives for trading purposes. Generation’s derivative activities are in accordance with Exelon’s Risk Management Policy (RMP).
Generation accounts for derivative financial instruments under SFAS No. 133. Under the provisions of SFAS No. 133, all derivatives are recognized on the balance sheet at their fair value unless they qualify for a normal purchases or normal sales exception. Derivatives on the balance sheet are presented as current or noncurrent mark-to-market derivative assets or liabilities. Changes in the fair value of derivatives are recognized in earnings unless specific hedge accounting criteria are met, in which case those changes are recorded in earnings as an offset to the changes in fair value of the exposure being hedged or deferred in accumulated other comprehensive income and recognized in earnings as hedged transactions occur. Amounts recorded in earnings are included in revenue, purchased power or other, net on the consolidated statements of income.
Revenues and expenses on contracts that qualify as normal purchases or normal sales are recognized when the underlying physical transaction is completed. “Normal” purchases and sales are contracts where physical delivery is probable, quantities are expected to be used or sold in the normal course of business over a reasonable period of time, and price is not tied to an unrelated underlying derivative. As part of Generation’s energy marketing business, Generation enters into contracts to buy and sell energy to meet the requirements of its customers. These contracts include short-term and long-term commitments to purchase and sell energy and energy-related products in the retail and wholesale markets with the intent and ability to deliver or take delivery. While these contracts are considered derivative financial instruments under SFAS No. 133, the majority of these transactions have been designated as “normal” purchases or “normal” sales and are thus not required to be recorded at fair value, but on an accrual basis of accounting.
A derivative financial instrument can be designated as a hedge of the fair value of a recognized asset or liability or of an unrecognized firm commitment (fair-value hedge), or a hedge of a forecasted transaction or the variability of cash flows to be received or paid related to a recognized asset or liability (cash-flow hedge). Changes in the fair value of a derivative that is highly effective as, and is designated and qualifies as, a fair-value hedge, are recognized in earnings as offsets to the changes in fair value of the exposure being hedged. Changes in the fair value of a derivative that is highly effective as, and is designated as and qualifies as, a cash-flow hedge are deferred in accumulated other comprehensive income and are recognized in earnings as the hedged transactions occur. Any ineffectiveness is recognized in earnings immediately. On an ongoing basis, the Company assesses the hedge effectiveness of all derivatives that are designated as hedges for accounting purposes in order to determine that each derivative continues to be highly effective in offsetting changes in fair values or cash flows of hedged items. If it is determined that the derivative is not highly effective as a hedge, hedge accounting will be discontinued prospectively.
Generation enters into contracts to buy and sell energy for trading purposes subject to limits. These contracts are recognized on the balance sheet at fair value and changes in the fair value of these derivative financial instruments are recognized in earnings.
363
Exelon Generation Company, LLC and Subsidiary Companies
Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, unless otherwise noted)
Severance Benefits
Generation participates in Exelon’s ongoing severance plans, which are accounted for in accordance with SFAS No. 112, “Employer’s Accounting for Postemployment Benefits, an amendment of FASB Statements No. 5 and 43” (SFAS No. 112) and SFAS No. 88, “Employers’ Accounting for Settlements and Curtailments of Defined Benefit Pension Plans and for Termination Benefits.” Amounts associated with severance benefits that are considered probable and can be reasonably estimated are accrued. See Note 9—Severance Accounting for further discussion of Generation’s accounting for severance benefits.
Retirement Benefits
Generation participates in Exelon’s defined benefit pension plans and postretirement welfare benefit plans in addition to sponsoring a plan. Exelon’s and Generation’s defined benefit pension plans and postretirement welfare benefit plans are accounted for in accordance with SFAS No. 87, “Employer’s Accounting for Pensions” (SFAS No. 87), SFAS No. 106, “Employers’ Accounting for Postretirement Benefits Other than Pensions” (SFAS No. 106) and FASB Staff Position (FSP) FAS 106-2, “Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003” (FSP FAS 106-2) and are disclosed in accordance with SFAS No. 132, “Employers’ Disclosures about Pensions and Other Postretirement Benefits—an Amendment of FASB Statements No. 87, 88, and 106” (revised 2003) (SFAS No. 132). See Note 14—Retirement Benefits for further discussion of retirement benefits.
FSP FAS 106-2. Through Exelon’s postretirement benefit plans, Generation provides retirees with prescription drug coverage. The Medicare Prescription Drug, Improvement and Modernization Act of 2003 (the Prescription Drug Act) was enacted on December 8, 2003. The Prescription Drug Act introduced a prescription drug benefit under Medicare as well as a Federal subsidy to sponsors of retiree health care benefit plans that provide a benefit that is at least actuarially equivalent to the Medicare prescription drug benefit. Management believes the prescription drug benefit provided under Exelon’s postretirement benefit plans is at least actuarially equivalent to the Medicare prescription drug benefit. In response to the enactment of the Prescription Drug Act, in May 2004, the FASB issued FASB Staff Position (FSP) FAS 106-2, “Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003” (FSP FAS 106-2), which provides transition guidance for accounting for the effects of the Prescription Drug Act and supersedes FSP FAS 106-1, which had been issued in January 2004. FSP FAS 106-1 permitted a plan sponsor of a postretirement health care plan that provides a prescription drug benefit to make a one-time election to defer the accounting for the effects of the Prescription Drug Act. Exelon made the one-time election allowed by FSP FAS 106-1 during the first quarter of 2004.
During the second quarter of 2004, Exelon early adopted the provisions of FSP FAS 106-2, resulting in a remeasurement of its postretirement benefit plans’ assets and accumulated postretirement benefit obligations (APBO) as of December 31, 2003. Historical financial information for the three months ended March 31, 2004 has been adjusted in Note 19—Quarterly Data.
Foreign Currency Translation
The financial statements of Generation’s foreign subsidiaries were prepared in their respective local currencies and translated into U.S. dollars based on the current exchange rates at the end of the periods for the Consolidated Balance Sheets and on weighted-average rates for the periods for the
364
Exelon Generation Company, LLC and Subsidiary Companies
Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, unless otherwise noted)
Consolidated Statements of Income. Foreign currency translation adjustments, net of deferred income tax benefits, are reflected as a component of other comprehensive income on the Consolidated Statements of Comprehensive Income and, accordingly, have no effect on net income.
New Accounting Pronouncements
EITF 03-1. In March 2004, the EITF reached a consensus on and the FASB ratified EITF Issue No. 03-1, “The Meaning of Other-Than-Temporary Impairment and Its Application to Certain Investments” (EITF 03-1). EITF 03-1 provides guidance for evaluating whether an investment is other-than-temporarily impaired. Generation adopted the disclosure requirements of EITF 03-1 for investments accounted for under SFAS No. 115, “Accounting for Certain Investments in Debt and Equity Securities,” within its financial statements for the year ended December 31, 2003. On September 30, 2004, the FASB issued FSP EITF 03-1-1, “Effective Date of Paragraphs 10-20 of EITF Issue No. 03-1, ‘The Meaning of Other-Than-Temporary Impairment and its Application to Certain Investments,’” which delayed the effective date of the application guidance on impairment of securities included within EITF 03-1. The EITF and the FASB are reconsidering the conclusions reached within EITF 03-1.
SFAS No. 151. In November 2004, the FASB issued FASB Statement No. 151, “Inventory Costs—an amendment of ARB No. 43, Chapter 4” (SFAS No. 151), which is the result of its efforts to converge U.S. accounting standards for inventories with International Accounting Standards. SFAS No. 151 requires abnormal amounts of idle facility expense, freight, handling costs and wasted material or spoilage to be recognized as current-period charges. It also requires that allocation of fixed production overheads to the costs of conversion be based on the normal capacity of the production facilities. SFAS No. 151 will be effective for inventory costs incurred during fiscal years beginning after June 15, 2005. Generation is assessing the impact SFAS No. 151 will have on its consolidated financial statements.
SFAS No. 123-R. In December 2004, the FASB issued FASB Statement No. 123 (revised 2004), “Share-Based Payment” (SFAS No. 123-R). SFAS No. 123-R replaces SFAS No. 123 and supersedes APB No. 25. SFAS No. 123-R requires that the compensation cost relating to share-based payment transactions be recognized in the financial statements. That cost will be measured based on the fair value of the equity or liability instruments issued. Exelon will no longer be permitted to follow the intrinsic value accounting method of APB No. 25, which resulted in no expense being recorded for stock option grants for which the strike price was equal to the fair value of the underlying stock on the date of grant. Exelon has not elected to early adopt SFAS No. 123-R. As a result, SFAS No. 123-R will be effective for Exelon in the third quarter of 2005 and will apply to all of Exelon’s outstanding unvested share-based payment awards as of July 1, 2005 and all prospective awards. Exelon is assessing the impact SFAS No. 123-R will have on its consolidated financial statements and which of three transition methods allowed by SFAS No. 123-R will be elected.
SFAS No. 153. In December 2004, the FASB issued FASB Statement No. 153, “Exchanges of Nonmonetary Assets, an amendment of APB Opinion No. 29, ‘Accounting for Nonmonetary Transactions’” (SFAS No. 153). Previously, APB Opinion No. 29 had required that the accounting for an exchange of a productive asset for a similar productive asset or an equivalent interest in the same or similar productive asset should be based on the recorded amount of the asset relinquished. The amendments made by SFAS No. 153 are based on the principle that exchanges of nonmonetary assets should be measured based on the fair value of the assets exchanged. Further, the amendments eliminate the narrow exception for nonmonetary exchanges of similar productive assets and replace it
365
Exelon Generation Company, LLC and Subsidiary Companies
Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, unless otherwise noted)
with a broader exception for exchanges of nonmonetary assets that do not have commercial substance. SFAS No. 153 will be effective for Generation in the third quarter of 2005 and earlier application is permitted for nonmonetary asset exchanges occurring after the issuance of SFAS No. 153. The provisions of SFAS No. 153 are applied prospectively. Generation is assessing the impact SFAS No. 153 will have on its consolidated financial statements.
FSP FAS 109-1 and FSP FAS 109-2. In December 2004, the FASB issued FSP FAS 109-1, “Application of FASB Statement No. 109, ‘Accounting for Income Taxes,’ to the Tax Deduction on Qualified Production Activities Provided by the American Jobs Creation Act of 2004” (FSP FAS 109-1) and FSP FAS 109-2, “Accounting and Disclosure Guidance for the Foreign Earnings Repatriation Provisions within the American Jobs Creation Act of 2004” (FSP FAS 109-2). FSP FAS 109-1 and FSP FAS 109-2 were effective upon issuance. The American Jobs Creation Act of 2004 (Act), signed into law on October 22, 2004, provided, generally, for a tax deduction for domestic manufacturing activities of up to nine percent (when fully phased-in) of the lesser of “qualified production activities income,” as defined in the Act, or taxable income. FSP FAS 109-1 clarified that the tax deduction for domestic manufacturing activities under the Act should be accounted for as a special deduction in accordance with SFAS No. 109, “Accounting for Income Taxes” (SFAS No. 109). The Act also provided a special limited-time dividends received deduction on the repatriation of certain foreign earnings to a U.S. taxpayer, provided certain criteria are met. FSP FAS 109-2 provides a registrant more time to evaluate the Act’s impact on the registrant’s plan for reinvestment or repatriation of certain foreign earnings for purposes of applying SFAS No. 109. Generation is assessing the impact, if any, that the Act and these standards may have on its consolidated financial statements in future periods.
Cumulative Effect of Changes in Accounting Principles
FIN 46-R. See discussion of the adoption of FIN 46-R within the “Variable Interest Entities” discussion above.
SFAS No. 143. SFAS No. 143 provides accounting requirements for retirement obligations (whether statutory, contractual or as a result of principles of promissory estoppel) associated with tangible long-lived assets. Generation adopted SFAS No. 143 as of January 1, 2003. After considering interpretations of the transitional guidance included in SFAS No. 143, Generation recorded income of $108 million (net of income taxes) as a cumulative effect of a change in accounting principle in connection with its adoption of this standard in the first quarter of 2003. The cumulative effect of a change in accounting principle included $28 million (net of income taxes of $18 million) associated with Generation’s investments in AmerGen and Sithe.
366
Exelon Generation Company, LLC and Subsidiary Companies
Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, unless otherwise noted)
The following tables set forth Generation’s net income for the years ended December 31, 2004, 2003 and 2002, adjusted as if SFAS No. 143 had been applied effective January 1, 2002 and FIN 46-R had been effective during those periods. SFAS No. 143 was adopted as of January 1, 2003. FIN 46-R was adopted as of March 31, 2004.
| 2004 |
2003 |
2002 |
||||||||||
| Reported income (loss) before cumulative effect of changes in accounting principles |
$ | 641 | $ | (241 | ) | $ | 387 | |||||
| Pro forma earnings effects: |
||||||||||||
| FIN 46-R |
— | 32 | — | |||||||||
| SFAS No. 143 |
— | — | 27 | |||||||||
| Pro forma income (loss) before cumulative effect of changes in accounting principles |
$ | 641 | $ | (209 | ) | $ | 414 | |||||
| Reported net income (loss) |
$ | 673 | $ | (133 | ) | $ | 400 | |||||
| Pro forma earnings effects: |
||||||||||||
| FIN 46-R |
— | 32 | — | |||||||||
| SFAS No. 143 |
— | — | 27 | |||||||||
| Reported cumulative effects of changes in accounting principles: FIN 46-R |
(32 | ) | — | — | ||||||||
| SFAS No. 143 |
— | (108 | ) | — | ||||||||
| SFAS No. 142 |
— | — | (13 | ) | ||||||||
| Pro forma net income (loss) |
$ | 641 | (209 | ) | 414 | |||||||
2. Acquisitions and Dispositions
Sale of Ownership Interest in Boston Generating, LLC
On May 25, 2004, Generation completed the sale, transfer and assignment of ownership of their indirect wholly owned subsidiary Boston Generating, which owns the companies that own Mystic 4-7, Mystic 8 and 9 and Fore River generating facilities, to a special purpose entity owned by the lenders under Boston Generating’s $1.25 billion credit facility (Boston Generating Credit Facility).
The sale was pursuant to a settlement agreement reached with Boston Generating’s lenders on February 23, 2004. The Federal Energy Regulatory Commission (FERC) approved the sale of Boston Generating on May 25, 2004. Responsibility for plant operations and power marketing activities were transferred to the lenders’ special purpose entity on September 1, 2004.
In connection with the settlement reached on February 23, 2004, Exelon, Generation, the lenders and Raytheon Company (Raytheon), the guarantor of the obligations of the turnkey contractor under the projects’ engineering, procurement and construction agreements, entered into a global settlement of all disputes relating to the construction of the Mystic 8 and 9 and Fore River generating facilities.
In connection with the decision to transition out of Boston Generating and the generating units, Generation recorded during the third quarter of 2003 an impairment charge of its long-lived assets pursuant to SFAS No. 144 of $945 million ($573 million net of income taxes) in operating expenses within its Consolidated Statements of Income. At the date of the sale, Boston Generating had
367
Exelon Generation Company, LLC and Subsidiary Companies
Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, unless otherwise noted)
approximately $1.2 billion in assets, primarily consisting of property, plant and equipment, and approximately $1.3 billion of liabilities of which approximately $1.0 billion was debt outstanding under the Boston Generating Credit Facility. As of the date of transfer, these amounts were eliminated from the Consolidated Balance Sheet of Generation. As a result of Boston Generating’s liabilities being greater than its assets at the time of the sale, transfer and assignment of ownership, Generation recorded a net gain of $85 million ($52 million net of income taxes) in other income and deductions within the Consolidated Statement of Income in the second quarter of 2004. In connection with the sale, Generation recorded a liability associated with an existing guarantee to Distrigas by its subsidiary Exelon New England Holdings, LLC (Exelon New England) of fuel purchase obligations of Boston Generating. Due to the existence of this guarantee and in accordance with SFAS No. 144 and EITF Issue No. 03-13, “Applying the Conditions in Paragraph 42 of FASB Statement No. 144, ‘Accounting for the Impairment or Disposal of Long-Lived Assets,’ in Determining Whether to Report Discontinued Operations,” Generation determined that it had retained risk and continuing involvement associated with the operations of Boston Generating and, as a result, the results of Boston Generating have not been classified as a discontinued operation within Generation’s Consolidated Statements of Income. See Note 16—Commitments and Contingencies for further information regarding the guarantee.
Generation’s Consolidated Statements of Income include the following results related to Boston Generating:
| 2004 |
2003 |
2002 |
||||||||||
| Operating revenues |
$ | 248 | $ | 618 | $ | 39 | ||||||
| Operating loss(a) |
(49 | ) | (954 | ) | (2 | ) | ||||||
| Net income (loss)(b) |
21 | (583 | ) | (3 | ) | |||||||
| (a) | The operating loss in 2003 included an impairment loss of $945 million ($573 million after-tax) related to Boston Generating’s long-lived assets. |
| (b) | Net income for 2004 included an after-tax gain of $52 million related to the sale of Boston Generating in the second quarter of 2004. |
See Note 4—Selected Pro Forma and Consolidating Financial Information for the effect of the sale of Boston Generating as if the transaction had occurred on January 1, 2003 and was excluded from Generation’s results from that date.
Sithe and Sithe International
See Note 3—Sithe for additional information regarding Sithe and Sithe International.
Exelon Energy Company
Effective January 1, 2004, Exelon contributed its interest in Exelon Energy Company (Exelon Energy) to Generation. The transaction had no effect on the assets and liabilities of Exelon Energy, which were previously reported as a part of the Enterprises segment. Beginning in 2004, Exelon Energy’s assets and liabilities and results of operations are included in Generation’s financial statements.
368
Exelon Generation Company, LLC and Subsidiary Companies
Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, unless otherwise noted)
The following summary represents the assets and liabilities of Exelon Energy that were transferred to Generation at book value as of January 1, 2004:
| Current assets (including $5 million of cash) |
$ | 119 | ||
| Property, plant and equipment |
2 | |||
| Deferred debits and other assets |
13 | |||
| Total assets |
$ | 134 | ||
| Current liabilities |
126 | |||
| Deferred credits and other liabilities |
10 | |||
| Member’s equity |
(2 | ) | ||
| Total liabilities and member’s equity |
$ | 134 | ||
See Note 4—Selected Pro Forma and Consolidating Financial Information for the effect of the transfer of Exelon Energy to Generation as if the transaction had occurred on January 1, 2003 and was included in Generation’s results from that date.
AmerGen Energy Company, LLC
On December 22, 2003, Generation purchased British Energy plc’s (British Energy) 50% interest in AmerGen. The resolution of purchase price contingencies related to the valuation of long-lived assets was finalized during the fourth quarter of 2004, reflecting the final purchase price of $267 million after working capital adjustments.
Prior to the purchase, Generation was a 50% owner of AmerGen and had accounted for the investment as an unconsolidated equity investment. From January 1, 2003 through the date of closing, Generation recorded $47 million ($28 million, net of tax) of equity in earnings of unconsolidated affiliates related to its investment in AmerGen and recorded $382 million of purchased power from AmerGen. The book value of Generation’s investment in AmerGen prior to the purchase was $316 million.
The transaction was accounted for as a step acquisition. As such, upon consolidation, Generation was required to allocate its $316 million book value to 50% of AmerGen’s equity book value. The difference between Generation’s investment in AmerGen and 50% of AmerGen’s equity book value of approximately $227 million was primarily due to Generation not recognizing a significant portion of the cumulative effect of the change in accounting principle at AmerGen related to the adoption of SFAS No. 143. Generation reduced AmerGen’s equity book value through the reduction of the book value of AmerGen’s long-lived assets.
369
Exelon Generation Company, LLC and Subsidiary Companies
Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, unless otherwise noted)
Generation recorded the acquired assets and liabilities of AmerGen (remaining 50%) at fair value as of the date of purchase. The following assets and liabilities, after final purchase accounting adjustments, reflecting the equity basis and fair value adjustments discussed above, of AmerGen were recorded within Generation’s Consolidated Balance Sheets as of the date of purchase:
| Current assets (including $36 million of cash acquired) |
$ | 116 | ||
| Property, plant and equipment, including nuclear fuel |
111 | |||
| Nuclear decommissioning trust funds |
1,108 | |||
| Deferred debits and other assets |
30 | |||
| Current liabilities |
(140 | ) | ||
| Asset retirement obligation |
(496 | ) | ||
| Deferred credits and other liabilities |
(106 | ) | ||
| Long-term debt |
(40 | ) | ||
| Total equity |
$ | 583 | ||
The assets and liabilities of AmerGen were included in Generation’s Consolidated Balance Sheets as of December 31, 2004 and 2003 and AmerGen’s results of operations were included in Generation’s Consolidated Statements of Income for the year ended December 31, 2004.
In connection with the purchase of Unit No. 1 of the Three Mile Island (TMI) facility by AmerGen in 2000, AmerGen entered into an agreement with the seller whereby the seller would receive additional consideration based upon future power purchase prices through 2009. Under the terms of the agreement, approximately $7 million had been accrued at December 31, 2004 which will be payable to the former owner of the TMI facility in the first quarter of 2005. This payment represents contingent consideration for the original acquisition and has accordingly been reflected as an increase to the long-lived assets associated with the TMI facility, and will be depreciated over the remaining useful life of the facility.
Acquisition of Generating Plants from TXU
On April 25, 2002, Generation acquired two natural-gas generation plants with a total of 2,334 MWs of capacity from TXU Corp. (TXU) for an aggregate purchase price of $443 million. Substantially the entire purchase price was allocated to property, plant and equipment. The transaction included a tolling agreement that provided for TXU to purchase power from the plants during the months of May through September from 2002 through 2006. In December 2004, TXU and Generation terminated the original tolling agreement and entered into a new agreement whereby TXU agreed to purchase 1,900 MWs of capacity and related energy/ancillary services from Generation through 2006. Upon termination of the original agreement, Generation received a cash payment of $172 million. As the termination of the original agreement and the execution of the new agreement were negotiated simultaneously and had similar terms, Generation determined that the culmination of the earnings process related to the termination payment had not occurred in 2004, and the resulting gain was deferred and will be recognized as income over the contractual term of the new agreement.
Assets and Liabilities Held for Sale
Generation classified three gas turbines with a book value of $36 million as held for sale as of December 31, 2003. These turbines were sold during the first of 2004 for proceeds of $42 million, resulting in a gain of $6 million. In anticipation of their sale in 2004, these turbines had been classified as other long-term assets as they had not been placed into service.
370
Exelon Generation Company, LLC and Subsidiary Companies
Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, unless otherwise noted)
3. Sithe
Sithe is primarily engaged in the ownership and operation of electric wholesale generating facilities in North America. At December 31, 2004, Sithe operated nine power plants with total average net capacity of 1,323 megawatts (MWs). Described below is a series of transactions in 2004 and 2003 that ultimately resulted in the sale of Generation’s ownership interest in Sithe to a third party on January 31, 2005. See Note 20—Subsequent Events for further discussion of these transactions.
Exercise of Call Option and Subsequent Agreement to Sell. On November 25, 2003, Generation, Reservoir Capital Group (Reservoir) and Sithe completed a series of transactions resulting in Generation and Reservoir each indirectly owning a 50% interest in Sithe. (Generation owned 49.9% prior to November 25, 2003). See below for further details regarding these 2003 transactions.
Both Generations and Reservoir’s 50% interests in Sithe were subject to put and call options. On September 29, 2004, Generation exercised its call option and entered into an agreement to acquire Reservoir’s 50% interest in Sithe for $97 million. On November 1, 2004, Generation entered into an agreement to sell Sithe to Dynegy Inc. (Dynegy) for $135 million in cash. On January 31, 2005, Generation completed the closing of the call exercise and the sale of the resulting 100% interest in Sithe. The sale did not include Sithe International, Inc., which was sold to a subsidiary of Generation in a separate transaction described below.
Acquisition of Sithe International, Inc. Sithe International, through its subsidiaries, had 49.5% interests in two Mexican business trusts that own TEG and TEP power stations, two 230 MW petcoke-fired generating facilities in Tamuín, Mexico that commenced commercial operations in the second quarter of 2004. On October 13, 2004, Sithe transferred all of the shares of Sithe International, Inc. and its subsidiaries to a subsidiary of Generation in exchange for cancellation of a $92 million note, which is eliminated as part of the consolidation of Sithe. Effective January 26, 2005, Sithe International’s name was changed to Tamuin International, Inc.
2003 Transactions. On November 25, 2003, Generation, Reservoir and Sithe completed a series of transactions resulting in Generation and Reservoir each indirectly owning a 50% interest in Sithe. Immediately prior to these transactions, Sithe was owned 49.9% by Generation, 35.2% by Apollo Energy, LLC (Apollo), and 14.9% by subsidiaries of Marubeni Corporation (Marubeni).
On November 25, 2003, entities controlled by Reservoir purchased certain Sithe entities holding six U.S. generating facilities, each a qualifying facility under the Public Utility Regulatory Policies Act, in exchange for $37 million ($21 million in cash and a $16 million two-year note); and entities controlled by Marubeni purchased all of Sithe’s entities and facilities outside of North America (other than Sithe Energies Australia (SEA) of which it purchased a 49.9% interest on November 24, 2003 and the remaining 50.1% on May 27, 2004 for separate consideration) for $178 million.
Following the sales of the above entities, Generation transferred its wholly owned subsidiary that held the Sithe investment to a newly formed holding company, EXRES SHC, Inc. The subsidiary holding the Sithe investment acquired the remaining Sithe interests from Apollo and Marubeni for $612 million using proceeds from a $580 million bridge financing and available cash. Generation sold a 50% interest in the newly formed holding company for $76 million to an entity controlled by Reservoir on November 25, 2003. On November 26, 2003, Sithe distributed $580 million of available cash to its parent, which then utilized the distributed funds to repay the bridge financing.
371
Exelon Generation Company, LLC and Subsidiary Companies
Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, unless otherwise noted)
Guarantees. In connection with the 2003 transactions, Generation recorded obligations related to $39 million of guarantees in accordance with FIN 45. These guarantees were issued to protect Reservoir from credit exposure of certain counter-parties through 2015 and other indemnities. In determining the value of the FIN 45 guarantees, Generation utilized probabilistic models to assess the possibilities of future payments under the guarantees. These guarantees were reversed upon the consolidation of Sithe in accordance with FIN 45 as this liability was associated with guarantees for the performance of a consolidated entity. The consolidation of Sithe in accordance with FIN 46-R resulted in Generation recording income of $32 million (net of income taxes), which included the reversal of the aforementioned guarantees, as a cumulative effect of a change in accounting principle during the first quarter of 2004.
Accounting Prior to the Consolidation of Sithe on March 31, 2004. Generation had accounted for the investment in Sithe as an unconsolidated equity method investment prior to its consolidation on March 31, 2004 pursuant to FIN 46-R. See Note 1—Significant Accounting Policies for further discussion. In 2003, Generation recorded impairment charges of $255 million (before income taxes) in other income and deductions within the Consolidated Statements of Income associated with a decline in the fair value of the Sithe investment, which was considered to be other-than-temporary. Generation’s management considered various factors in the decision to impair this investment, including management’s negotiations to sell its interest in Sithe. The discussions surrounding the sale indicated that the fair value of the Sithe investment was below its book value and, as such, impairment charges were required.
The book value of Generation’s investment in Sithe immediately prior to its consolidation on March 31, 2004 was $49 million. For the year ended December 31, 2004, Generation recorded $2 million of equity method losses from Sithe prior to its consolidation. For the year ended December 31, 2003 and 2002, Generation recorded $2 million and $23 million of equity method income, respectively, related to its investment in Sithe.
Consolidation of Sithe as of March 31, 2004. As a result of the 2003 transactions referred to above, the consolidation of Sithe at March 31, 2004 was accounted for as a step acquisition pursuant to purchase accounting policies. Under the provisions of FIN 46-R, the operating results of Sithe were included in Generation’s results of operations beginning April 1, 2004.
The condensed consolidating financial information included in Note 4—Selected Pro Forma and Consolidating Financial Information (Unaudited) presents the financial position of Generation and Sithe, as well as consolidating entries related primarily to acquisition notes payables and receivables between Generation and Sithe.
Intangible Assets. Sithe had entered into a tolling arrangement (Tolling Agreement) with Dynegy Power Marketing and its affiliates with respect to Sithe’s Independence Station. The Tolling Agreement commenced on July 1, 2001 and runs through 2014. Additionally, Sithe has entered into an energy purchase agreement (Energy Purchase Agreement) with a counterparty relating to the Independence Station, which continues through 2014. As a result of the acquisition accounting described above, values were assigned to the Tolling Agreement and the Energy Purchase Agreement of approximately $73 million and $384 million, respectively, which have been recorded as intangible assets on Generation’s Consolidated Balance Sheets in deferred debits and other assets. These amounts were determined based on fair value techniques utilizing the contract terms and various other estimates, including forward power prices, discount rates and option pricing models.
372
Exelon Generation Company, LLC and Subsidiary Companies
Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, unless otherwise noted)
The intangible assets representing the Tolling Agreement and the Energy Purchase Agreement are being amortized on a straight-line basis over the lives of the associated agreements. See Note 8—Intangible Assets for further information regarding Generation’s intangible assets.
Long-Term Debt and Letters of Credit. Substantially all of Sithe’s property, plant and equipment and project agreements secure Sithe’s outstanding long-term debt, which consists primarily of project debt. During 2003, Sithe entered into an agreement with Exelon and Generation under which Exelon obtained letters of credit to support contractual obligations of Sithe and its subsidiaries. As of December 31, 2004, Exelon had obtained $61 million of letters of credit in support of Sithe’s obligations not including a $50 million letter of credit that is not guaranteed by Exelon. With the exception of the issuance of letters of credit to support contractual obligations, the creditors of Sithe have no recourse against the general credit of Exelon or Generation.
4. Selected Pro Forma and Consolidating Financial Information
The following unaudited pro forma financial information gives effect to the acquisition on December 22, 2003 of the remaining 50% interest in AmerGen, the transfer of Exelon Energy to Generation on January 1, 2004 and the sale of Boston Generating on May 25, 2004, in each case, as if the transaction had occurred on January 1, 2003.
| 2004 |
Generation As Reported |
Sale of Boston Generating |
Eliminating Entries |
Pro Forma Generation Consolidated | |||||||||
| Total operating revenues |
$ | 7,938 | $ | 248 | $ | — | $ | 7,690 | |||||
| Operating income (loss) |
1,030 | (49 | ) | — | 1,079 | ||||||||
| Income before cumulative effect of changes in accounting principle |
641 | 21 | — | 620 | |||||||||
| 2003 |
Generation As Reported |
Businesses Acquired (a) |
Sale of Boston Generating |
Eliminating Entries (b) |
Pro Forma Generation Consolidated | |||||||||||||
| Total operating revenue |
$ | 8,135 | $ | 1,457 | $ | 618 | $ | (591 | ) | $ | 8,383 | |||||||
| Operating income (loss) |
(115 | ) | 76 | (954 | ) | — | 915 | |||||||||||
| Income (loss) before cumulative effect of changes in accounting principle |
(241 | ) | 71 | (583 | ) | (47 | ) | 366 | ||||||||||
| (a) | Consists of the acquisition of the remaining 50% interest in AmerGen and the transfer of Exelon Energy to Generation. |
| (b) | Represents the elimination of intercompany revenues at AmerGen and Exelon Energy and equity in earnings from AmerGen in 2003. |
The above unaudited, pro forma financial information should not be relied upon as being indicative of the historical results that would have been obtained if these transactions had actually occurred in prior periods nor of the results that might be obtained in the future.
373
Exelon Generation Company, LLC and Subsidiary Companies
Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, unless otherwise noted)
Condensed Consolidating Balance Sheet at December 31, 2004
The following condensed consolidating financial information presents the financial position of Generation, Sithe and Exelon Energy, as well as eliminating entries related primarily to acquisition notes payables and receivables between Generation and Sithe.
| December 31, 2004 |
Pro Forma Generation |
Sithe |
Exelon Energy |
Eliminating Entries |
Generation Consolidated (As Reported) | |||||||||||
| Assets |
||||||||||||||||
| Current assets |
$ | 2,238 | $ | 336 | $ | 128 | $ | (381 | ) | $ | 2,321 | |||||
| Property, plant and equipment, net |
7,265 | 270 | 1 | — | 7,536 | |||||||||||
| Other noncurrent assets |
5,849 | 750 | 13 | (31 | ) | 6,581 | ||||||||||
| Total assets |
$ | 15,352 | $ | 1,356 | $ | 142 | $ | (412 | ) | $ | 16,438 | |||||
| Liabilities and member’s equity |
||||||||||||||||
| Current liabilities |
$ | 2,348 | $ | 323 | $ | 126 | $ | (381 | ) | $ | 2,416 | |||||
| Long-term debt |
1,798 | 785 | — | — | 2,583 | |||||||||||
| Other long-term liabilities (a) |
8,180 | 181 | 3 | 36 | 8,400 | |||||||||||
| Member’s equity |
3,026 | 67 | 13 | (67 | ) | 3,039 | ||||||||||
| Total liabilities and member’s equity |
$ | 15,352 | $ | 1,356 | $ | 142 | $ | (412 | ) | $ | 16,438 | |||||
| (a) | Includes minority interest of consolidated subsidiaries. |
5. Accounts Receivable
Customer accounts receivable at December 31, 2004 and 2003 included $449 million and $366 million, respectively, of unbilled revenues for amounts of energy delivered to customers in the month of December, including $64 million as of December 31, 2004 related to unread meters for Exelon Energy customers. The allowance for uncollectible accounts at December 31, 2004 and 2003 was $19 million and $14 million, respectively. The allowance for uncollectible accounts at December 31, 2004 includes $3 million for Exelon Energy.
374
Exelon Generation Company, LLC and Subsidiary Companies
Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, unless otherwise noted)
6. Property, Plant and Equipment
A summary of property, plant and equipment by classification as of December 31, 2004 and 2003 is as follows:
| Asset Category |
2004 |
2003 | ||||
| Electric-generation |
$ | 7,125 | $ | 7,968 | ||
| Nuclear fuel |
2,926 | 2,568 | ||||
| Asset retirement cost (ARC) |
1,023 | 202 | ||||
| Construction work in progress |
357 | 428 | ||||
| Other property, plant and equipment (a) |
54 | 54 | ||||
| Total property, plant and equipment |
11,485 | 11,220 | ||||
| Less accumulated depreciation (including accumulated amortization of nuclear fuel of $1,976 and $1,596 as of December 31, 2004 and 2003, respectively) |
3,949 | 4,114 | ||||
| Property, plant and equipment, net |
$ | 7,536 | $ | 7,106 | ||
| (a) | Includes buildings under capital lease with a net carrying value of $43 million and $46 million at December 31, 2004 and 2003, respectively. The original cost basis of the buildings was $53 million and total accumulated amortization was $10 million and $6 million at December 31, 2004 and 2003, respectively. |
Service Life Extensions. Upon the December 2003 acquisition of the remaining 50% interest in AmerGen, Generation changed its accounting estimates related to the depreciation of certain AmerGen generating facilities to conform with Generation’s depreciation policies. The estimated service lives were extended by 20 years for the three AmerGen stations. These changes were based on engineering and economic feasibility analyses performed by Generation. The service life extensions are subject to approval by the United States Nuclear Regulatory Commission (NRC) of the renewals of the existing NRC operating licenses. Generation has not applied for license renewals at the AmerGen facilities, but has announced its plan to file a renewal request in 2005 for the Oyster Creek Nuclear Generating Station (Oyster Creek) and is planning on filing for license renewals for TMI Unit 1 and the Clinton Nuclear Power Station (Clinton) on a timeline consistent and integrated with the other planned license filings for the Generation nuclear fleet.
License Renewals. In December 2004, the NRC issued an order that will permit Oyster Creek to operate beyond its license expiration in April 2009 if the NRC has not completed reviewing the application for renewal. The application for Oyster Creek’s license renewal is anticipated to be filed by August 2005 in order to comply with this agreement. On October 28, 2004, the NRC approved 20-year renewals of the operating licenses for Generation’s Dresden and Quad Cities generating stations. The licenses for Dresden Unit 2, Dresden Unit 3 and Quad Cities Units 1 and 2 were renewed to 2029, 2031 and 2032, respectively. On May 7, 2003, the operating licenses for Peach Bottom Unit 2 and Peach Bottom Unit 3 were renewed to 2033 and 2034, respectively. Depreciation provisions are based on the estimated useful lives of the stations, which assumes the renewal of the licenses for all nuclear generating stations. As a result, these license renewals had no impact on the Consolidated Statements of Income.
375
Exelon Generation Company, LLC and Subsidiary Companies
Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, unless otherwise noted)
7. Jointly Owned Electric Utility Plants
Generation’s undivided ownership interests in jointly owned generation plants as of December 31, 2004 and 2003 were as follows:
| Nuclear generation |
Fossil fuel generation |
|||||||||||||||||||||||
| Quad Cities |
Peach Bottom |
Salem (b) |
Keystone |
Conemaugh |
Wyman |
|||||||||||||||||||
| PSEG Nuclear |
||||||||||||||||||||||||
| Operator | Generation | Generation | Reliant | Reliant | FP&L | |||||||||||||||||||
| Ownership interest |
75.00 | % | 50.00 | % | 42.59 | % | 20.99 | % | 20.72 | % | 5.89 | % | ||||||||||||
| Generation’s share at December 31, 2004: (a) |
||||||||||||||||||||||||
| Plant |
$ | 287 | $ | 438 | $ | 127 | $ | 167 | $ | 212 | $ | 2 | ||||||||||||
| Accumulated depreciation |
54 | 231 | 33 | 102 | 133 | — | ||||||||||||||||||
| Construction work in progress |
39 | 16 | 81 | 5 | 1 | — | ||||||||||||||||||
| Generation’s share at December 31, 2003: (a) |
||||||||||||||||||||||||
| Plant |
$ | 191 | $ | 453 | $ | 106 | $ | 168 | $ | 210 | $ | 2 | ||||||||||||
| Accumulated depreciation |
18 | 239 | 24 | 106 | 138 | — | ||||||||||||||||||
| Construction work in progress |
40 | 1 | 48 | 2 | 1 | — | ||||||||||||||||||
| (a) | Generation also has a 44.24% ownership interest in Merrill Creek Reservoir located in New Jersey with a book value of $1 million at December 31, 2004 and 2003, which is not included in the table above. |
| (b) | Generation also owns a proportionate share in the fossil fuel combustion turbine, which is fully depreciated. The gross book value was $3 million at December 31, 2004 and 2003. |
Generation’s undivided ownership interests are financed with Generation funds and all operations are accounted for as if such participating interests were wholly owned facilities. Direct expenses of the jointly owned plants are included in the corresponding operating expenses on the Consolidated Statements of Income.
376
Exelon Generation Company, LLC and Subsidiary Companies
Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, unless otherwise noted)
8. Intangible Assets
Intangible Assets. Generation’s intangible assets, included in deferred debits and other assets, other, consisted of the following:
| December 31, 2004 |
December 31, 2003 | ||||||||||||||||||
| Gross |
Accumulated Amortization |
Net |
Gross |
Accumulated Amortization |
Net | ||||||||||||||
| Amortized intangible assets: |
|||||||||||||||||||
| Energy purchase agreement (a) |
$ | 384 | $ | (27 | ) | $ | 357 | $ | — | $ | — | $ | — | ||||||
| Tolling agreement (a) |
73 | (5 | ) | 68 | — | — | — | ||||||||||||
| Other |
6 | (6 | ) | — | 6 | — | 6 | ||||||||||||
| Total |
$ | 463 | $ | (38 | ) | $ | 425 | $ | 6 | $ | — | $ | 6 | ||||||
| (a) | See Note 3—Sithe and Note 20—Subsequent Events for a description of Sithe’s intangible assets that are reflected in Generation’s balance sheet at December 31, 2004 and a description of the sale of Sithe that was completed on January 31, 2005. |
Amortization related to amortized intangible assets was $38 million for the year ended December 31, 2004, which has been reflected as a reduction in revenues. Of the $38 million, $32 million was attributable to the energy purchase agreement and tolling agreement, both of which relate to Generation’s consolidation of Sithe. In 2004, Generation entered into an agreement to sell its ownership interest in Sithe, which was completed on January 31, 2005 and will result in the elimination of the intangible assets related to Sithe’s energy purchase agreement and tolling agreement from the Consolidated Balance Sheets in future periods. See Note 20—Subsequent Events for further information regarding this sale.
9. Severance Accounting
Generation provides severance and health and welfare benefits to terminated employees pursuant to pre-existing severance plans primarily based upon each individual employee’s years of service with Generation and compensation level.
During the years ended December 31, 2004 and 2003, Generation identified approximately 99 and 470 positions, respectively, for elimination. As of December 31, 2004, approximately 85 of the identified positions had not been eliminated. Generation recorded charges for salary continuance severance of $2 million and $38 million during 2004 and 2003, respectively, which represented salary continuance severance that were probable and could be reasonably estimated at the end of the year. During 2004 and 2003, Generation recorded charges of $4 million and $12 million (before income taxes) associated with special health and welfare severance benefits. Additionally, Generation incurred curtailment costs in 2004 and 2003, associated with pension and postretirement benefit plans of $3 million and $15 million, as a result of personnel reductions. These amounts are net of $11 million in charges billed to co-owners of generating facilities in 2003. Amounts billed to co-owners in 2004 were not significant. In total, Generation recorded charges of $9 million and $65 million in 2004 and 2003, net of co-owner billings. See Note 14—Retirement Benefits for a description of the curtailment charges for the pension and postretirement benefit plans.
377
Exelon Generation Company, LLC and Subsidiary Companies
Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, unless otherwise noted)
In 2004, Generation recorded a charge of $9 million for new positions identified and reversed $7 million for accruals in excess of the reserve for individuals previously identified under The Exelon Way. Charges in 2004 included a $1 million increase in the reserve for liabilities acquired upon consolidation of Exelon Energy. Generation based its estimate of the number of positions to be eliminated on management’s current plans and its ability to determine the appropriate staffing levels to effectively operate the business. Generation may incur further severance costs if additional positions are identified for elimination. These costs will be recorded in the period in which the costs can be reasonably estimated.
The following table details Generation’s total salary continuance severance expense, recorded as an operating and maintenance expense, for the years ended December 31, 2004, 2003 and 2002:
| Salary continuance severance charges |
|||
| Expense recorded—2004 (a) |
$ | 2 | |
| Expense recorded—2003 (a) |
38 | ||
| Expense recorded—2002 (b) |
2 | ||
| (a) | Severance expense in 2004 and 2003 reflects severance costs associated with The Exelon Way and other severance costs incurred in the normal course of business. In 2004, Generation recorded charges of $9 million for new positions identified and reversed $7 million to reduce accruals for individuals previously identified under The Exelon Way. 2004 charges included $1 million for the transfer of Exelon Energy to Generation, effective January 1, 2004. |
| (b) | Severance expense in 2002 generally represents severance activity associated with the October 20, 2000 merger and in the normal course of business. |
The following table provides a roll forward of Generation’s salary continuance severance obligation from January 1, 2003 through December 31, 2004.
| Salary continuance severance obligation |
||||
| Balance as of January 1, 2003 |
$ | 11 | ||
| Severance charges recorded |
38 | |||
| Cash payments |
(9 | ) | ||
| Liability acquired upon consolidation of AmerGen |
3 | |||
| Balance as of January 1, 2004 |
43 | |||
| Severance charges recorded (a) |
2 | |||
| Cash payments |
(29 | ) | ||
| Balance as of December 31, 2004 |
$ | 16 | ||
| (a) | In 2004, Generation recorded charges of $9 million for new positions identified and reversed $7 million to reduce accruals for individuals previously identified under The Exelon Way. 2004 charges included $1 million for the transfer of Exelon Energy to Generation, effective January 1, 2004. |
378
Exelon Generation Company, LLC and Subsidiary Companies
Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, unless otherwise noted)
10. Short-Term Debt
| 2004 |
2003 |
2002 | ||||||||
| Average borrowings |
$ | 72 | $ | — | $ | — | ||||
| Maximum borrowings outstanding |
326 | — | — | |||||||
| Average interest rates, computed on a daily basis |
1.14 | % | — | — | ||||||
| Average interest rates, at December 31 |
— | — | — | |||||||
At December 31, 2003, Exelon, along with ComEd, PECO and Generation, participated with a group of banks in a $750 million 364-day unsecured revolving credit agreement and a $750 million three-year unsecured revolving credit agreement. On July 16, 2004, the $750 million 364-day facility was replaced with a $1 billion unsecured revolving facility maturing on July 16, 2009 and the $750 million three-year facility was reduced to $500 million maturing on October 31, 2006. Both revolving credit agreements are used principally to support the commercial paper programs at Exelon, ComEd, PECO and Generation and to issue letters of credit.
At December 31, 2004, Generation’s aggregate sublimit under the credit agreements was $600 million. Sublimits under the credit agreements can change upon written notification to the bank group. Generation had approximately $444 million of unused bank commitments, net of outstanding letters of credit, under the credit agreements at December 31, 2004. Generation did not have any commercial paper outstanding at December 31, 2004 or 2003. Interest rates on advances under the credit facilities are based on either prime or the London Interbank Offering Rate (LIBOR) plus an adder based on the credit rating of the borrower as well as the total outstanding amounts under the agreement at the time of borrowing. The maximum LIBOR adder is 170 basis points.
The credit agreements require Generation to maintain a minimum cash from operations to interest expense ratio for the twelve-month period ended on the last day of any quarter. The ratio excludes revenues and interest expenses attributable to securitization debt, certain changes in working capital distributions on preferred securities of subsidiaries and revenues from Sithe and interest on the debt of its project subsidiaries. Generation’s minimum cash from operations to interest expense ratio is 3.25 to 1. At December 31, 2004, Generation was in compliance with this threshold.
379
Exelon Generation Company, LLC and Subsidiary Companies
Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, unless otherwise noted)
11. Long-Term Debt
Long-term debt is comprised of the following:
| December 31, 2004 |
December 31, |
||||||||||||
| Rates |
Maturity Date |
2004 |
2003 |
||||||||||
| Boston Generating Credit Facility (a) |
– | – | $ | — | $ | 1,037 | |||||||
| Senior unsecured notes |
5.35 | %-6.95% | 2011-2014 | 1,200 | 1,200 | ||||||||
| Non-recourse secured project debt |
8.50 | %-9.00% (b) | 2007-2013 | 499 | — | ||||||||
| Subordinated notes |
7.00% (b) | 2013-2034 | 419 | — | |||||||||
| Pollution control notes, floating rates |
1.71 | %-2.04% | 2016-2034 | 520 | 363 | ||||||||
| Notes payable and other (c) |
6.20 | %-18.00% | 2005-2020 | 100 | 128 | ||||||||
| Total long-term debt (d) |
2,738 | 2,728 | |||||||||||
| Unamortized debt discount and premium, net |
(108 | ) | (11 | ) | |||||||||
| Due within one year |
(47 | ) | (1,068 | ) | |||||||||
| Long-term debt |
$ | 2,583 | $ | 1,649 | |||||||||
| (a) | Approximately $1.0 billion of debt was outstanding under the non-recourse Boston Generating Credit Facility at December 31, 2003, all of which was reflected in the Consolidated Balance Sheet of Generation as a current liability due to certain events of default under the Boston Generating Credit Facility. The outstanding debt under the Boston Generating Credit Facility was eliminated from Generation’s Consolidated Balance Sheets in May 2004 following the sale Generation’s ownership interest in Boston Generating. See Note 2 – Acquisitions and Dispositions for additional information regarding the sale. |
| (b) | In addition to the stated interest rate, an additional 1.97% and 0.99% of interest on the carrying amount of the secured bonds payable is being credited due to debt premiums and 1.63% of interest on the carrying amount of the subordinated debt is being incurred due to the debt discount recorded at the time of the purchase. There is $100 million of unamortized debt discount associated with this debt. These amounts represent obligations of Sithe and will be removed from the Generation’s Consolidated Balance Sheet following the sale of Sithe, which was completed on January 31, 2005. See Note 20 – Subsequent Events for additional information. |
| (c) | Includes capital lease obligations of $50 million at December 31, 2004 and December 31, 2003. Lease payments of approximately $3 million, $3 million, $2 million, $2 million and $40 million will be made in 2005, 2006, 2007, 2008 and thereafter, respectively. |
| (d) | Long-term debt maturities in the periods 2005 through 2009 and thereafter are as follows: |
| 2005 |
$ | 47 | |
| 2006 |
51 | ||
| 2007 |
52 | ||
| 2008 |
56 | ||
| 2009 |
68 | ||
| Thereafter |
2,464 | ||
| Total |
$ | 2,738 | |
Included in the table above are maturities of Sithe’s debt of $34, $38, $40, $44, $57 and $706 in 2005, 2006, 2007, 2008, 2009 and thereafter, respectively. In connection with Generation’s sale of Sithe on January 31, 2005, Generation is no longer obligated to fulfill these debt maturities, and the related obligations will be removed from the Consolidated Balance Sheets. See Note 20—Subsequent Events for a further discussion of the sale of Sithe.
380
Exelon Generation Company, LLC and Subsidiary Companies
Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, unless otherwise noted)
Debt Issuances. The following long-term debt was issued during 2004:
| Type |
Interest Rate |
Maturity |
Amount | ||||
| Pollution Control Revenue Bonds |
Variable | April 1, 2021 | $ | 51 | |||
| Pollution Control Revenue Bonds |
Variable | October 1, 2030 | 92 | ||||
| Pollution Control Revenue Bonds |
Variable | October 1, 2034 | 14 | ||||
| Total issuances |
$ | 157 | |||||
Debt Retirements and Redemptions. The following debt was retired, through tender, open market purchases, optional redemption, or payment at maturity, during 2004:
| Type |
Interest Rate |
Maturity |
Amount | |||||
| Note—AmerGen |
6.33 | % | August 8, 2009 | $ | 10 | |||
| Note—AmerGen |
6.20 | % | December 20, 2004 | 16 | ||||
| Note—Sithe |
8.50 | % | June 30, 2007 | 32 | ||||
| Other |
4 | |||||||
| Total retirements |
$ | 62 | ||||||
See Note 2—Acquisitions and Dispositions for information regarding debt classified as held for sale as of December 31, 2003.
See Note 15—Fair Value of Financial Assets and Liabilities for additional information regarding interest-rate swaps.
12. Income Taxes
Income tax expense (benefit) is comprised of the following components:
| For the Year Ended December 31, |
||||||||||||
| 2004 |
2003 |
2002 |
||||||||||
| Included in operations: |
||||||||||||
| Federal |
||||||||||||
| Current |
$ | 228 | $ | (227 | ) | $ | 67 | |||||
| Deferred |
88 | 81 | 123 | |||||||||
| Investment tax credit |
(8 | ) | (8 | ) | (8 | ) | ||||||
| State |
||||||||||||
| Current |
20 | (4 | ) | 18 | ||||||||
| Deferred |
44 | (21 | ) | 17 | ||||||||
| Total income tax expense (benefit) |
$ | 372 | $ | (179 | ) | $ | 217 | |||||
| Included in cumulative effects of changes in accounting principles: |
|
|||||||||||
| Federal |
||||||||||||
| Deferred |
$ | 17 | $ | 58 | $ | 7 | ||||||
| State |
||||||||||||
| Deferred |
5 | 12 | 2 | |||||||||
| Total income tax expense |
$ | 22 | $ | 70 | $ | 9 | ||||||
381
Exelon Generation Company, LLC and Subsidiary Companies
Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, unless otherwise noted)
The effective income tax rate differed from the U.S. Federal statutory rate principally due to the following:
| For the Year Ended December 31, |
|||||||||
| 2004 |
2003 |
2002 |
|||||||
| U.S. Federal statutory rate |
35.0 | % | 35.0 | % | 35.0 | % | |||
| Increase (decrease) due to: |
|||||||||
| State income taxes, net of Federal income tax benefit |
4.3 | 3.9 | 3.7 | ||||||
| Tax-exempt interest |
(1.0 | ) | 1.8 | (2.3 | ) | ||||
| Qualified nuclear decommissioning trust fund income |
(0.7 | ) | (2.1 | ) | 0.9 | ||||
| Amortization of investment tax credit |
(0.5 | ) | 1.2 | (0.9 | ) | ||||
| Deferred expense/revenue option adjustment |
— | 1.6 | — | ||||||
| Other |
0.4 | 1.6 | (0.7 | ) | |||||
| Effective income tax rate |
37.5 | % | 43.0 | % | 35.7 | % | |||
The tax effect of temporary differences giving rise to significant portions of Generation’s deferred tax assets and liabilities are presented below:
| December 31, |
||||||||
| 2004 |
2003 |
|||||||
| Deferred tax assets: |
||||||||
| Decommissioning and decontamination obligations |
$ | 153 | $ | 108 | ||||
| Deferred pension and postretirement obligations |
69 | 170 | ||||||
| Unrealized gains on derivative financial instruments |
66 | 83 | ||||||
| Excess of tax value over book value of impaired assets (a) |
– | 159 | ||||||
| Other, net |
115 | 80 | ||||||
| Total deferred tax assets |
403 | 600 | ||||||
| Deferred tax liabilities: |
||||||||
| Plant basis difference |
(822 | ) | (715 | ) | ||||
| Emission allowances |
(39 | ) | (40 | ) | ||||
| Total deferred tax liabilities |
(861 | ) | (755 | ) | ||||
| Deferred income taxes (net) on the Consolidated Balance Sheets |
$ | (458 | ) | $ | (155 | ) | ||
| (a) | Includes impairments related to Generation’s investment in Sithe and Boston Generating. |
The Internal Revenue Service (IRS) and certain state tax authorities are currently auditing certain tax returns of Exelon’s predecessor entities, Unicom and PECO. The current audits are not expected to have an adverse effect on financial condition or results of operations of Generation.
In 2004, Generation received $26 million from Exelon related to Generation’s allocation of tax benefits under the Tax Sharing Agreement. Generation received no allocation of tax benefits under the Tax Sharing Agreement in 2003. In 2002, Generation received $11 million from Exelon related to Generation’s allocation of tax benefits under the Tax Sharing Agreement.
Generation had unamortized investment tax credits of $210 million and $218 million at December 31, 2004 and December 31, 2003, respectively.
382
Exelon Generation Company, LLC and Subsidiary Companies
Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, unless otherwise noted)
As of December 31, 2004, Generation (excluding Sithe) had capital loss carry forwards for income tax purposes of approximately $163 million, which expire beginning in 2009. Sithe had capital loss carry forwards for income tax purposes of approximately $21 million, which will expire beginning in 2007. Additionally, Sithe International had capital loss carry forwards for income tax purposes of approximately $8 million, which will expire beginning in 2007 and is subject to the limitations under Internal Revenue Code Section 382 due to the change in ownership of Sithe International on October 13, 2004. As of December 31, 2004, a valuation allowance has been recorded for approximately $8 million with respect to the Sithe International capital loss carry forward.
As of December 31, 2004, Sithe had domestic and Mexican net operating loss carry forwards of approximately $101 million and $57 million, respectively. Such carry forwards will expire beginning in 2020 and 2011, respectively.
As of December 31, 2004, Sithe had an Alternative Minimum Tax carry forward of approximately $26 million which can be carried forward indefinitely.
As of December 31, 2004, Generation had recorded valuation allowances of approximately $5 million with respect to deferred taxes associated with separate company state taxes.
13. Nuclear Decommissioning and Spent Fuel Storage
Nuclear Decommissioning
Overview
Generation has a legal obligation to decommission its nuclear power plants following the expiration of their operating licenses. This obligation is reflected as an asset retirement obligation (ARO), which is classified as a noncurrent liability. Based on the actual or anticipated extended license lives of the nuclear plants, decommissioning expenditures for Generation’s nuclear power plants currently operating are expected to occur primarily during the period 2029 through 2056. Generation owns three nuclear units that are retired and currently incur certain costs associated with decommissioning. The cost of nuclear decommissioning will be funded by investments held in trust funds that have been established for each nuclear station. Generation had nuclear decommissioning trust funds totaling $5,262 million and $4,721 million as of December 31, 2004 and 2003, respectively. See Note 15 – Fair Value of Financial Assets and Liabilities for more information regarding Generation’s nuclear decommissioning trust funds.
Cost Recovery and Decommissioning Responsibilities
Former ComEd plants. Generation currently recovers in revenues funds for decommissioning the former ComEd nuclear plants through regulated rates collected by ComEd. The amounts recovered from customers are remitted to Generation and deposited into the trust accounts to fund the future decommissioning costs. Under a December 2000 Illinois Commerce Commission Order issued to ComEd, amended February 2001 (ICC Order), ComEd is permitted to collect up to $73 million annually through 2006 from ratepayers to decommission the former ComEd nuclear plants. The amount of decommissioning revenue collections for 2005 and 2006 are anticipated to be slightly lower than $73 million. Under the current ICC Order, ComEd will not collect amounts for decommissioning subsequent to 2006.
Based on the provisions of the ICC Order and NRC regulations, Generation is financially responsible for the decommissioning obligations related to these plants. If trust assets plus future
383
Exelon Generation Company, LLC and Subsidiary Companies
Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, unless otherwise noted)
collections permitted by the ICC Order are exceeded by the ultimate ARO, Generation is responsible for any shortfall in funding; however, if amounts remain in the trust funds for these units following the completion of the decommissioning activities, those amounts will be returned to the ComEd ratepayers. At the end of each financial reporting period, Generation assesses the amounts currently recorded in trust assets plus future collections less amounts recorded in the ARO. At December 31, 2004 and 2003, Generation recorded a noncurrent affiliate payable to ComEd, who in turn, recorded an equal regulatory liability for the amount of decommissioning-related assets in excess of the ARO.
Former PECO plants. Generation currently recovers costs for decommissioning the former PECO nuclear plants through regulated rates collected by PECO. The amounts recovered from customers are remitted to Generation and deposited into the trust accounts to fund the future decommissioning costs. Under orders from the Pennsylvania Public Utility Commission (PUC), PECO is permitted to collect from ratepayers up to $33 million annually for the full funding of the expected costs to decommission the former PECO nuclear plants. Based on the provisions of the PUC order, the PECO ratepayers are financially responsible for the majority of any shortfalls in the costs to decommission these nuclear units; however, the PECO ratepayers will receive any excess amounts from the trust funds at the completion of decommissioning. Generation is responsible for 1) the first $50 million of the decommissioning costs above a certain threshold established under the PUC order and 2) five percent of the decommissioning costs above that first $50 million of costs that exceed the established threshold. Generation expects total decommissioning costs to exceed this threshold and expects to be held responsible for the entire $50 million over the remaining life of the assets. At the end of each financial reporting period, Generation assesses the amounts currently recorded in trust assets plus future collections less amounts recorded in the ARO. At December 31, 2004 and 2003, Generation recorded a noncurrent affiliate payable to PECO, who in turn, recorded an equal regulatory liability for the amount of decommissioning-related assets in excess of the ARO.
AmerGen plants. Generation is financially responsible for the decommissioning of these plants and bears all risks and benefits related to the funding levels associated with these plants’ decommissioning trust funds.
Adoption of SFAS No. 143
Generation adopted SFAS No. 143 on January 1, 2003, which promulgates the accounting for AROs. In accordance with SFAS No. 143, a probability-weighted, discounted cash flow model with multiple scenarios was used to determine the fair value of the decommissioning obligation. SFAS No. 143 states that the estimated fair value of the decommissioning obligation represents the amount a third party would receive for assuming an entity’s entire obligation. The present value of future estimated cash flows required to decommission the nuclear stations was calculated using credit-adjusted, risk-free rates applicable to the various businesses in order to determine the fair value of the decommissioning obligation at the time of adoption of SFAS No. 143.
Former ComEd plants. The transition provisions of SFAS No. 143 required Exelon to apply the fair value remeasurement back to the historical periods in which AROs were originally incurred, resulting in a remeasurement of these obligations at the date the assets were acquired by Exelon. Since the nuclear plants previously owned by ComEd were acquired by Exelon on October 20, 2000 (and subsequently transferred to Generation as a result of the Exelon corporate restructuring on January 1, 2001), Exelon’s historical accounting for its ARO associated with those plants was revised as if SFAS No. 143 had been in effect at the merger date. The calculation of the SFAS No. 143 ARO yielded
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Exelon Generation Company, LLC and Subsidiary Companies
Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, unless otherwise noted)
decommissioning obligations lower than the value of the corresponding trust assets at January 1, 2003. Since the trust fund assets exceeded the fair value of the ARO, Generation recorded a $948 million noncurrent affiliate payable to ComEd, who in turn, recorded an equal regulatory liability at January 1, 2003. As a result of increases in the trust funds due to market conditions, the noncurrent affiliate payable to ComEd and ComEd’s regulatory liability have increased to $1,433 million at December 31, 2004.
In accordance with the provisions of SFAS No. 143 and regulatory accounting guidance, Generation recorded a SFAS No. 143 transition adjustment to accumulated other comprehensive income to reclassify $168 million, net of tax, of accumulated net unrealized losses in the nuclear decommissioning trust funds associated with the former ComEd plants to its noncurrent affiliate payable to ComEd, and likewise to ComEd’s regulatory liability.
Former PECO plants. In the case of the former PECO plants, the SFAS No. 143 ARO calculation yielded decommissioning obligations greater than the corresponding trust assets at January 1, 2003. As such, Generation recorded a noncurrent affiliate receivable from PECO, who in turn, recorded a regulatory asset of $20 million. As a result of increases in the trust funds due to market conditions and contributions collected from PECO customers, the trust fund assets exceeded the ARO at December 31, 2004 and Generation has a noncurrent affiliate payable to PECO, who in turn has an equal regulatory liability to its ratepayers of $46 million. At December 31, 2003, Generation had a noncurrent affiliate payable to PECO, who in turn had a regulatory liability to its ratepayers of $12 million related to nuclear decommissioning.
Upon adoption, and in accordance with the provisions of SFAS No. 143, Generation capitalized an asset retirement cost (ARC) asset within property, plant and equipment of $172 million related to the establishment of the ARO for the former PECO plants. The ARC is being amortized over the remaining useful lives of the former PECO plants.
Generation believes that all of the decommissioning assets, anticipated earnings thereon and future revenues from decommissioning collections will be used to decommission the former ComEd and PECO nuclear plants. As such, Generation expects the regulatory liabilities to be reduced to zero at the conclusion of the decommissioning activities.
AmerGen plants. At the time of the adoption of SFAS No. 143 on January 1, 2003, Generation had a 50% ownership of AmerGen. Generation recorded income of $29 million (after income taxes) as the cumulative effect of changes in accounting principles.
Impact of Contractual Construct with Regulated Affiliates on the Application of SFAS No. 143
Increases in the ARO due to the passage of time are recorded in operating and maintenance expense as accretion expense. Increases in the ARO resulting from revisions to the estimated future cash flows are generally recorded with a corresponding adjustment to the basis of plant value, by recording an ARC asset. The ARC is depreciated on a straight-line basis over the remaining life of the unit to which it relates. Changes in the nuclear decommissioning trust funds are discussed in Note 15 -Fair Value of Financial Assets and Liabilities.
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Exelon Generation Company, LLC and Subsidiary Companies
Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, unless otherwise noted)
Former ComEd plants. As of December 31, 2004, the trust assets associated with the former ComEd plants exceeded the ARO for those plants. Until such time, if ever, that the ARO exceeds the decommissioning-related assets, Generation’s net income should not reflect the impacts of any income or expenses associated with decommissioning the former ComEd nuclear units. As such, decommissioning revenues collected, nuclear decommissioning trust fund investment income, accretion expense and depreciation of the ARC are not reflected in net income as they are offset by the adjustment to the noncurrent affiliate payable to ComEd, and likewise ComEd’s regulatory liability, to the extent the decommissioning-related assets exceed the ARO.
Former PECO plants. As of December 31, 2004, the trust assets associated with the former PECO plants exceeded the ARO for those plants. The regulatory order associated with the former PECO units ensures that Generation will not be financially responsible for the decommissioning of these units, with the exception of certain amounts described above. As such, Generation’s net income should not reflect the impacts of any income or expenses associated with decommissioning the former PECO nuclear units, except for the accretion expense associated with its decommissioning cost responsibility above the decommissioning cost thresholds established by the PUC, as previously discussed. The net effect of decommissioning revenues collected, nuclear decommissioning trust fund investment income, accretion expense and depreciation of the ARC is adjusted so that the amounts net to an insignificant amount in Generation’s Consolidated Statements of Income. This adjustment is reflected as a change in the noncurrent affiliate payable to PECO, and in turn, PECO’s regulatory liability.
AmerGen plants. Beginning in 2004, decommissioning activity related to the AmerGen units is reflected in Generation’s Consolidated Statements of Income. The AmerGen units are not subject to any cost recovery regulation and, as such, Generation will be required to fund any shortfall of trust assets below the decommissioning obligations. Similarly, Generation will not be required to refund any excess trust funds to customers if the obligation is less than the available trust funds. As such, the impacts of nuclear decommissioning trust fund investment income, accretion expense and depreciation of the ARC are all included in Generation’s Consolidated Statements of Income. Prior to December 2003 and Generation’s acquisition of British Energy’s 50% interest in AmerGen, the impact to Generation for accounting for the decommissioning of the AmerGen plants was recorded within Generation’s equity in earnings of AmerGen. In addition, Generation’s proportionate share of unrealized gains and losses on AmerGen’s decommissioning trust funds were reflected in Generation’s other comprehensive income.
2004 Update of ARO
Generation updates its ARO on a periodic basis. During 2004, Generation recorded a $780 million net increase to the ARO resulting from revisions to estimated future nuclear decommissioning cash flows. This update also resulted in an adjustment to the basis of property, plant and equipment of $780 million by recording a corresponding net increase to the ARC. This increase to the ARO was primarily a result of updated decommissioning cost studies and changes in cost escalation factors used to estimate future undiscounted costs, both of which are provided by independent third-party appraisers. Cost estimates are updated every three to five years in accordance with NRC regulations and industry practice. The net increase in the ARO for the former ComEd units, the former PECO units and the AmerGen units resulting from revisions to estimated cash flows during 2004 was $563 million, $142 million and $75 million, respectively. As of December 31, 2004, the ARO balances for the former ComEd, the former PECO and the AmerGen units totaled approximately $2.3 billion, $1.0 billion and $0.6 billion, respectively.
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Exelon Generation Company, LLC and Subsidiary Companies
Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, unless otherwise noted)
The following table provides a roll forward reconciliation of the ARO reflected on Generation’s Consolidated Balance Sheets from January 1, 2003 to December 31, 2004:
| Asset retirement obligation at January 1, 2003 |
$ | 2,363 | ||
| Consolidation of AmerGen |
487 | |||
| Accretion expense |
160 | |||
| Payments to decommission retired plants |
(14 | ) | ||
| Asset retirement obligation at December 31, 2003 |
2,996 | |||
| Net increase resulting from updates to estimated future cash flows |
780 | |||
| Accretion expense |
210 | |||
| Additional liabilities incurred (a) |
6 | |||
| Payments to decommission retired plants |
(12 | ) | ||
| Asset retirement obligation at December 31, 2004 |
$ | 3,980 | ||
| (a) | Additional liabilities incurred are primarily due to the consolidation of Sithe. |
Accounting Prior to the Adoption of SFAS No. 143
Prior to January 1, 2003, Generation accounted for the current period’s cost of decommissioning related to generating plants previously owned by PECO in accordance with common regulatory accounting practices by recording a charge to depreciation expense and a corresponding liability in accumulated depreciation concurrently with recognizing decommissioning collections. Financial activity of the decommissioning trust (e.g., investment income and realized and unrealized gains and losses on trust investments) was reflected in nuclear decommissioning trust funds in Generation’s Consolidated Balance Sheets with a corresponding offset recorded to accumulated depreciation.
Regulatory accounting practices for the nuclear generating stations previously owned by ComEd were discontinued as a result of an ICC Order capping ComEd’s ultimate recovery of decommissioning costs. The difference between the decommissioning cost estimate and the decommissioning liability recorded in accumulated depreciation for the former ComEd operating stations was previously amortized to depreciation expense on a straight-line basis over the remaining lives of the stations. The decommissioning cost estimate (adjusted annually to reflect inflation) for the former ComEd retired units recorded in deferred credits and other liability was previously accreted to depreciation expense. Financial activity of the decommissioning trust funds related to Generation’s nuclear generating stations no longer accounted for under common regulatory practices was reflected in nuclear decommissioning trust funds in Generation’s Consolidated Balance Sheets with a corresponding gain or expense recorded in Generation’s Consolidated Income Statements or in other comprehensive income.
Spent Nuclear Fuel
Under the Nuclear Waste Policy Act of 1982 (NWPA), the U.S. Department of Energy (DOE) is responsible for the development of a repository for the disposal of spent nuclear fuel (SNF) and high-level radioactive waste. As required by the NWPA, Generation is a party to contracts with the DOE (Standard Contracts) to provide for disposal of SNF from its nuclear generating stations. In accordance with the NWPA and the Standard Contracts, Generation pays the DOE one mill ($.001) per kilowatt-hour of net nuclear generation for the cost of nuclear fuel long-term disposal. This fee may be adjusted
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Exelon Generation Company, LLC and Subsidiary Companies
Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, unless otherwise noted)
prospectively in order to ensure full cost recovery. The NWPA and the Standard Contracts required the DOE to begin taking possession of SNF generated by nuclear generating units by no later than January 31, 1998. The DOE, however, failed to meet that deadline and its performance will be delayed significantly. The DOE’s current estimate for opening a SNF facility is 2012. This extended delay in SNF acceptance by the DOE has led to Generation’s adoption of dry cask storage at its Dresden, Quad Cities, Oyster Creek and Peach Bottom stations and its consideration of dry cask storage at other stations.
The Standard Contracts with the DOE also required the payment to the DOE a one-time fee applicable to nuclear generation through April 6, 1983. PECO’s fee has been paid. Pursuant to the Standard Contracts, ComEd elected to pay the one-time fee of $277 million, with interest to the date of payment, just prior to the first delivery of SNF to the DOE. As of December 31, 2004, the unfunded liability for the one-time fee with interest was $878 million. Interest accrues at the 13-week Treasury Rate, which was 1.987% at December 31, 2004. The liabilities for spent nuclear fuel disposal costs, including the one-time fee, were transferred to Generation as part of the corporate restructuring. The one-time fee obligation for the AmerGen units remains with the prior owner. The Clinton Unit has no outstanding obligation.
In July 1998, ComEd filed a complaint against the United States Government (Government) in the United States Court of Federal Claims (Court) seeking to recover damages caused by the DOE’s failure to honor its contractual obligation to begin disposing of SNF in January 1998. In August 2001, the Court granted ComEd’s motion for partial summary judgment for liability on ComEd’s breach of contract claim. In November 2001, the Government filed two partial summary judgment motions relating to certain damage issues in the case as well as two motions to dismiss claims other than ComEd’s breach of contract claim. On June 10, 2003, the Court granted the Government’s motion to dismiss claims other than the breach of contract claims. Also on June 10, 2003, the Court denied the Government’s summary judgment motions and set the case for trial on damages for November 2004.
In July 2000, PECO entered into an agreement (Amendment) with the DOE relating to PECO’s Peach Bottom nuclear generating unit to address the DOE’s failure to begin removal of SNF in January 1998 as required by the Standard Contracts. Under the Amendment, the DOE agreed to provide PECO with credits against PECO’s future contributions to the Nuclear Waste Fund to compensate PECO for SNF storage costs incurred as a result of the DOE’s breach of the contract. The Amendment also provided that, upon PECO’s request, the DOE will take title to the SNF and the interim storage facility at Peach Bottom provided certain conditions are met. Generation assumed this contract in the 2001 corporate restructuring.
In November 2000, eight utilities with nuclear power plants filed a Joint Petition for Review against the DOE with the United States Court of Appeals for the Eleventh Circuit seeking to invalidate that portion of the Amendment providing for credits to PECO against nuclear waste fund payments on the ground that such provision is a violation of the NWPA. PECO intervened as a defendant in that case and Generation assumed the claim in the 2001 corporate restructuring. On September 24, 2002, the United States Court of Appeals for the Eleventh Circuit ruled that the fee adjustment provision of the Amendment violates the NWPA and therefore is null and void. The Court did not hold that the Amendment as a whole is invalid. Article XVI(I) of the Amendment provides that if any portion of the Amendment is found to be void, the DOE and Generation agree to negotiate in good faith and attempt to reach an enforceable agreement consistent with the spirit and purpose of the Amendment. That provision further provided that should a major term be declared void, and the DOE and Generation
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Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, unless otherwise noted)
cannot reach a subsequent agreement, the entire Amendment would be rendered null and void, the original Peach Bottom Standard Contracts would remain in effect and the parties would return to pre-Amendment status. Under the Amendment, Generation has received approximately $40 million in credits against contributions to the nuclear waste fund.
On August 14, 2003, Generation received a letter from the DOE demanding repayment of $40 million of previously received credits from the Nuclear Waste Fund. The letter also demanded $1.5 million of interest that was accrued as of that date and Generation continued to record an interest expense each subsequent month. Generation reserved its 50% ownership share of these amounts. Because Generation expenses the dry storage casks and capitalizes the permanent components of its spent fuel storage facilities, these reserves increased Generation’s operating and maintenance expense approximately $11 million and its capital base approximately $9 million during 2003.
On July 21, 2004, Exelon and the U.S. Department of Justice, in close consultation with the DOE, reached a settlement under which the government will reimburse Generation for costs associated with storage of spent fuel at Generation’s nuclear stations pending DOE’s fulfillment of its obligations. Under the agreement, Generation immediately received $80 million in gross reimbursements for storage costs already incurred ($53 million net after considering amounts due from Generation to co-owners of certain nuclear stations), with additional amounts to be reimbursed annually for future costs. In all cases, reimbursements will be made only after costs are incurred and only for costs resulting from DOE delays in accepting the fuel. As of December 31, 2004, the amount of spent fuel storage costs for which reimbursement will be requested in mid-2005 from the DOE under the settlement agreement is $33 million net, which is recorded within accounts receivable, other. This amount is comprised of $14 million, which has been recorded as a reduction to operating and maintenance expense, and $12 million, which has been recorded as a reduction to capital expenditures. The remaining $7 million represents amounts owed to the co-owners of the Peach Bottom and Quad Cities generating facilities.
14. Retirement Benefits
Generation participates in defined benefit pension plans and postretirement welfare benefit plans sponsored by Exelon. Substantially all eligible Generation employees participate in the Exelon sponsored plans. Benefits under these pension plans generally reflect each employee’s compensation, years of service, and age at retirement. Employees of AmerGen participate in separate defined benefit pension plans and postretirement welfare benefit plans sponsored by AmerGen. AmerGen is currently offering its employees a choice to remain in their traditional benefit formula or convert to a cash balance formula.
The prepaid pension asset, pension obligation and non-pension postretirement benefits obligation on Generation’s Consolidated Balance Sheets reflect Generation’s obligations from and to the plan sponsors, Exelon and AmerGen. Employee-related assets and liabilities, including both pension and SFAS No. 106, “Employers’ Accounting for Postretirement Benefits Other than Pensions,” postretirement welfare liabilities, were allocated by Exelon to its subsidiaries based on the number of active employees as of January 1, 2001 as part of Exelon’s corporate restructuring. Exelon allocates the components of pension expense to the participating employers based upon several factors, including the percentage of active employees in each participating unit. See Note 15 – Retirement Benefits of Exelon’s Notes to Consolidated Financial Statements for pension and other postretirement benefits information for the Exelon plans.
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(Dollars in millions, unless otherwise noted)
Approximately $126 million, $75 million and $37 million were included in capital and operating and maintenance expense, excluding curtailment and special termination costs, in 2004, 2003 and 2002, respectively, for Generation’s allocated portion of Exelon’s pension and postretirement benefit expense. The 2004 amounts include a reduction in net periodic postretirement benefit cost resulting from the adoption of FSP FAS 106-2. Generation contributed $180 million, $145 million and $60 million to the Exelon-sponsored pension plans in 2004, 2003 and 2002. Generation expects to contribute up to $853 million to the pension plans in 2005.
During 2004 and 2003, Generation recognized curtailment charges of $3 million and $18 million, respectively, associated with an overall reduction in participants in Exelon’s pension and postretirement benefit plans due to employee reductions associated with The Exelon Way. During 2004 and 2003, Generation recognized special termination benefit costs of $4 million and $20 million, respectively.
Included in Generation’s 2004 results are costs associated with pension benefit and other postretirement benefit plans sponsored by AmerGen. Costs associated with the pension and postretirement benefits were $11 million and $11 million, respectively for 2004. At December 31, 2004 and 2003, Generation’s balance sheet included a liability of $21 million and $21 million, respectively, related to the pension obligation and $94 million and $80 million, respectively, related to other postretirement benefit obligations.
The accumulated benefit obligation (ABO) for the AmerGen pension plan was $77 million and $55 million at December 31, 2004 and 2003, respectively. The projected benefit obligation (PBO) for the AmerGen pension plan was $90 million and $67 million at December 31, 2004 and 2003, respectively. The fair value of plan assets related to this obligation was $53 million and $41 million at December 31, 2004 and 2003, respectively
The postretirement benefit plan for AmerGen is unfunded. At December 31, 2004 and 2003, the ABO related to postretirement benefits was $94 million and $80 million, respectively.
Generation participates in a 401(k) savings plan sponsored by Exelon. The plan allows employees to contribute a portion of their pre-tax income in accordance with specified guidelines. Generation matches a percentage of employee contributions to the plan up to certain limits. The cost of Generation’s matching contributions to the savings plan totaled $27 million, $24 million and $31 million for 2004, 2003 and 2002, respectively.
15. Fair Value of Financial Assets and Liabilities
Non-Derivative Financial Assets and Liabilities
Fair Value. As of December 31, 2004 and 2003, Generation’s carrying amounts of cash and cash equivalents, accounts receivable, vendor accounts payable and accrued liabilities are representative of fair value because of the short-term nature of these instruments. Fair values of the trust accounts for decommissioning nuclear plants are estimated based on quoted market valuation model which is based on conventional discounted cash flow methodology and utilizes assumptions of current market pricing curves.
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Exelon Generation Company, LLC and Subsidiary Companies
Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, unless otherwise noted)
The carrying amounts and fair values of Generation’s financial liabilities as of December 31, 2004 and 2003 were as follows:
| 2004 |
2003 | |||||||||||
| Carrying Amount |
Fair Value |
Carrying Amount |
Fair Value | |||||||||
| Liabilities |
||||||||||||
| Long-term debt (including amounts due within one year) |
$ | 2,630 | $ | 3,002 | $ | 2,717 | $ | 2,930 | ||||
Credit Risk. Financial instruments that potentially subject Generation to concentrations of credit risk consist principally of cash equivalents and customer accounts receivable. Generation places its cash equivalents with high-credit quality financial institutions. Generally, such investments are in excess of the Federal Deposit Insurance Corporation limits. Concentrations of credit risk with respect to customer accounts receivable are limited due to Generation’s large number of customers.
Derivative Instruments
Fair Value. The fair values of Generation’s interest-rate swaps and power purchase and sale contracts are determined using quoted exchange prices, external dealer prices, or internal valuation models which utilize assumptions of future energy prices and available market pricing curves.
Interest-Rate Swaps. Generation enters into interest-rate swaps to hedge exposure to interest rate changes. Swaps related to variable-rate securities or forecasted transactions are accounted for as cash-flow hedges. The swaps are generally structured to mirror the terms of the hedged debt instruments; therefore, no material ineffectiveness has been recorded in earnings. The gain or loss in fair value of cash-flow hedges is recorded in other comprehensive income and will be recognized in earnings over the life of the hedged items. The gain or loss in fair value of fair-value hedges, along with the gain or loss on the hedged asset or liability that is attributable to the hedged risk, is recorded in earnings.
Generation had no interest-rate swaps designated as cash-flow hedges outstanding at December 31, 2004. At December 31, 2003, Generation had $861 million of notional amounts of interest-rate swaps designated as cash flow hedges outstanding with net deferred losses of $77 million.
Energy-Related Derivatives. Generation utilizes derivatives to manage the utilization of its available generating capacity and the provision of wholesale energy to its affiliates. Generation also utilizes energy option contracts and energy financial swap arrangements to limit the market price risk associated with forward energy commodity contracts. Additionally, Generation enters into certain energy-related derivatives for trading or speculative purposes. At December 31, 2004 and 2003, Generation had $145 million and $216 million, respectively, of energy derivatives recorded as net liabilities at fair value on its Consolidated Balance Sheets.
For the years ended December 31, 2004, 2003 and 2002, Generation recognized net unrealized losses of $42 million, net unrealized losses of $16 million and net unrealized gains of $6 million, respectively, relating to mark-to-market activity of certain non-trading power purchase and sale contracts pursuant to SFAS No. 133. Mark-to-market activity on non-trading power purchase and sale contracts are reported in fuel and purchased power. For the years ended December 31, 2004, 2003 and 2002, Generation recognized net unrealized gains of $3 million and net unrealized losses of $3
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Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, unless otherwise noted)
million and $9 million, respectively, relating to mark-to-market activity on derivative instruments entered into for trading purposes. Gains and losses associated with financial trading are reported as revenue in the Consolidated Statements of Income.
As of December 31, 2004, $194 million of deferred net losses on derivative instruments in accumulated other comprehensive income are expected to be reclassified to earnings during the next twelve months. Amounts in accumulated other comprehensive income related to changes in interest-rate cash-flow hedges are reclassified into earnings when the interest payment occurs or when ineffectiveness has been determined. Amounts in accumulated other comprehensive income related to changes in energy commodity cash-flow hedges are reclassified into earnings when the forecasted purchase or sale of the energy commodity occurs. The majority of Generation’s cash-flow hedges are expected to settle within the next three years.
Credit Risk Associated with Derivative Instruments. Generation would be exposed to credit-related losses in the event of non-performance by counterparties that issue derivative instruments. The credit exposure of derivatives contracts is represented by the fair value of contracts at the reporting date. For energy-related derivative instruments, Generation has entered into payment netting agreements or enabling agreements that allow for payment netting with the majority of its large counterparties, which reduce Generation’s exposure to counterparty risk by providing for the offset of amounts payable to the counterparty against amounts receivable from the counterparty. The notional amount of derivatives does not represent amounts that are exchanged by the parties and, thus, is not a measure of Generation’s exposure. The amounts exchanged are calculated on the basis of the notional or contract amounts, as well as on the other terms of the derivatives, which relate to interest rates and the volatility of these rates.
Nuclear Decommissioning Trust Fund Investments
Investments as of December 31, 2004 and 2003. Generation classifies investments in the trust accounts for decommissioning nuclear plants as available-for-sale and estimates fair value based on quoted market prices for the securities held in trust funds. These investments are held to fund Generation’s decommissioning obligation for its nuclear plants. Decommissioning expenditures are expected to occur primarily after the plants are retired. Based on current licenses and anticipated renewals, decommissioning expenditures for plants in operation are currently estimated to begin in 2029. See Note 13—Nuclear Decommissioning and Spent Fuel Storage for further information regarding the decommissioning of Generation’s nuclear plants.
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Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, unless otherwise noted)
The following tables show the fair values, gross unrealized gains and losses and amortized cost bases of the securities held in these trust accounts as of December 31, 2004 and 2003.
| December 31, 2004 | |||||||||||||
| Amortized Cost |
Gross Unrealized Gains |
Gross Unrealized Losses |
Estimated Fair Value | ||||||||||
| Cash and cash equivalents |
$ | 184 | $ | — | $ | — | $ | 184 | |||||
| Equity securities |
2,194 | 538 | (37 | ) | 2,695 | ||||||||
| Debt securities |
|||||||||||||
| Federal government obligations |
1,447 | 51 | (4 | ) | 1,494 | ||||||||
| Other debt securities |
855 | 37 | (3 | ) | 889 | ||||||||
| Total debt securities |
2,302 | 88 | (7 | ) | 2,383 | ||||||||
| Total available-for-sale securities |
$ | 4,680 | $ | 626 | $ | (44 | ) | $ | 5,262 | ||||
| December 31, 2003 | |||||||||||||
| Amortized Cost |
Gross Unrealized Gains |
Gross Unrealized Losses |
Estimated Fair Value | ||||||||||
| Cash and cash equivalents |
$ | 84 | $ | — | $ | — | $ | 84 | |||||
| Equity securities |
2,402 | 300 | (294 | ) | 2,408 | ||||||||
| Debt securities |
|||||||||||||
| Federal government obligations |
1,574 | 65 | (4 | ) | 1,635 | ||||||||
| Other debt securities |
567 | 29 | (2 | ) | 594 | ||||||||
| Total debt securities |
2,141 | 94 | (6 | ) | 2,229 | ||||||||
| Total available-for-sale securities |
$ | 4,627 | $ | 394 | $ | (300 | ) | $ | 4,721 | ||||
The fixed-income available-for-sale securities held at December 31, 2004 have an average maturity range of six to thirteen years. The cost of these securities was determined on the basis of specific identification.
Impairment Evaluation in 2004. At December 31, 2004, Generation had gross unrealized gains of $626 million and gross unrealized losses of $44 million related to the nuclear decommissioning trust fund investments. At December 31, 2003, Generation had gross unrealized gains of $394 million and gross unrealized losses of $300 million related to the nuclear decommissioning trust fund investments. With the exception of the portion of these amounts related to AmerGen, as a result of ComEd’s and PECO’s regulatory arrangements for decommissioning costs, approximately $469 million of these net unrealized gains were recorded as an increase in Generation’s noncurrent affiliate payables, which resulted in a corresponding increase in ComEd and PECO’s regulatory liabilities.
Generation evaluates decommissioning trust fund investments for other-than-temporary impairments by analyzing the historical performance, cost basis and market value of securities in unrealized loss positions in comparison to related market indices. During 2004, Generation concluded that certain trust fund investments were other-than-temporarily impaired based on various factors assessed in the aggregate, including the duration and severity of the impairment, the anticipated recovery of the securities and consideration of Generation’s ability and intent to hold the investments until the recovery of their cost basis. This determination resulted in an $8 million impairment charge
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Exelon Generation Company, LLC and Subsidiary Companies
Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, unless otherwise noted)
recorded in other income and deductions associated with the trust funds for the decommissioning of the AmerGen plants. Also, Generation realized $260 million of the previously unrealized losses associated with the trust investments for the decommissioning of the former ComEd and PECO plants. As both realized and unrealized losses are included as a reduction in the fair value of the investments and in the fair value of the regulatory liability at ComEd and PECO, and as such, Generation’s noncurrent affiliate payable balance, realization of these losses associated with the former ComEd and PECO plants had no impact on Generation’s results of operations or financial position.
Unrealized Gains and Losses. Net unrealized gains of $582 million were included in noncurrent affiliate payables and other comprehensive income in Generation’s Consolidated Balance Sheets as of December 31, 2004. Net unrealized gains of $94 million were included in noncurrent affiliate payables and other comprehensive income in Generation’s Consolidated Balance Sheets at December 31, 2003.
The following table provides information regarding Generation’s available-for-sale securities in nuclear decommissioning trust funds in an unrealized loss position that are not considered other-than-temporarily impaired. The following tables shows the investments’ gross unrealized losses and fair value, aggregated by investment category and length of time that individual securities have been in a continuous unrealized loss position, at December 31, 2004 and 2003.
| December 31, 2004 | ||||||||||||||||||
| Less than 12 months |
12 months or more |
Total | ||||||||||||||||
| Gross Unrealized Losses |
Fair Value |
Gross Unrealized Losses |
Fair Value |
Gross Unrealized Losses |
Fair Value | |||||||||||||
| Equity securities |
$ | 16 | $ | 197 | $ | 21 | $ | 278 | $ | 37 | $ | 475 | ||||||
| Debt securities |
||||||||||||||||||
| Government obligations |
2 | 207 | 2 | 68 | 4 | 275 | ||||||||||||
| Other debt securities |
2 | 182 | 1 | 22 | 3 | 204 | ||||||||||||
| Total debt securities |
4 | 389 | 3 | 90 | 7 | 479 | ||||||||||||
| Total temporarily impaired securities |
$ | 20 | $ | 586 | $ | 24 | $ | 368 | $ | 44 | $ | 954 | ||||||
| December 31, 2003 | ||||||||||||||||||
| Less than 12 months |
12 months or more |
Total | ||||||||||||||||
| Gross Unrealized Losses |
Fair Value |
Gross Unrealized Losses |
Fair Value |
Gross Unrealized Losses |
Fair Value | |||||||||||||
| Equity securities |
$ | 33 | $ | 231 | $ | 261 | $ | 775 | $ | 294 | $ | 1,006 | ||||||
| Debt securities |
||||||||||||||||||
| Government obligations |
4 | 232 | — | 11 | 4 | 243 | ||||||||||||
| Other debt securities |
2 | 117 | — | 2 | 2 | 119 | ||||||||||||
| Total debt securities |
6 | 349 | — | 13 | 6 | 362 | ||||||||||||
| Total temporarily impaired securities |
$ | 39 | $ | 580 | $ | 261 | $ | 788 | $ | 300 | $ | 1,368 | ||||||
394
Exelon Generation Company, LLC and Subsidiary Companies
Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, unless otherwise noted)
Generation evaluates the historical performance, cost basis and market value of securities in unrealized loss positions in comparison to related market indices to assess whether or not the securities are other-than-temporarily impaired. Generation concluded that the trending of the related market indices, the historical performance of these securities over a long-term time horizon and the level of insignificance of the unrealized loss as a percentage of the cost of the individual securities indicates that the securities are not other-than-temporarily impaired.
Sale of Nuclear Decommissioning Trust Fund Investments. Proceeds from the sale of decommissioning trust fund investments and gross realized gains and losses on those sales were as follows:
| For the Years Ended December 31, |
||||||||||||
| 2004 |
2003 |
2002 |
||||||||||
| Proceeds from sales |
$ | 2,320 | $ | 2,341 | $ | 1,612 | ||||||
| Gross realized gains |
115 | 219 | 56 | |||||||||
| Gross realized losses |
(43 | ) | (235 | ) | (86 | ) | ||||||
Net realized gains of $72 million and net realized losses of $16 million and $32 million were recognized in other income and deductions in Generation’s Consolidated Statements of Income for the years ended December 31, 2004, 2003 and 2002, respectively. Additionally, net realized gains of $2 million were recognized in accumulated depreciation in Generation’s Consolidated Balance Sheets at December 31, 2002. Prior to January 1, 2003, realized gains and losses related to the former PECO units were included in accumulated depreciation. See Note 13—Nuclear Decommissioning and Spent Fuel for further information regarding the nuclear decommissioning trusts.
16. Commitments and Contingencies
Nuclear Insurance
The Price-Anderson Act limits the liability of nuclear reactor owners for claims that could arise from a single incident. As of December 31, 2004, the current limit is $10.76 billion and is subject to change to account for the effects of inflation and changes in the number of licensed reactors. As required by the Price-Anderson Act, Generation carries the maximum available amount of nuclear liability insurance (currently $300 million for each operating site) and the remaining $10.46 billion is provided through mandatory participation in a financial protection pool. Under the Price-Anderson Act, all nuclear reactor licensees can be assessed a maximum charge per reactor per incident. The maximum assessment for all nuclear operators per reactor per incident (including a 5% surcharge) is $100.6 million, payable at no more than $10 million per reactor per incident per year. This assessment is subject to inflation and state premium taxes.
In addition, the U.S. Congress could impose revenue-raising measures on the nuclear industry to pay claims. The Price-Anderson Act expired on August 1, 2002 and was subsequently extended to the end of 2003 by the U.S. Congress. Only facilities applying for NRC licenses subsequent to the expiration of the Price-Anderson Act are affected. Existing commercial generating facilities, such as those owned by Generation, remain subject to the provisions of the Price-Anderson Act and are unaffected by its expiration. However, any new licenses are not covered under the Price-Anderson Act and any new plant initiatives would need to address this exposure.
395
Exelon Generation Company, LLC and Subsidiary Companies
Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, unless otherwise noted)
Generation is a member of an industry mutual insurance company, Nuclear Electric Insurance Limited (NEIL), which provides property damage, decontamination and premature decommissioning insurance for each station for losses resulting from damage to its nuclear plants. In the event of an accident, insurance proceeds must first be used for reactor stabilization and site decontamination. If the decision is made to decommission the facility, a portion of the insurance proceeds will be allocated to a fund, which Generation is required by the NRC to maintain, to provide for decommissioning the facility. Generation is unable to predict the timing of the availability of insurance proceeds to Generation and the amount of such proceeds that would be available. Under the terms of the various insurance agreements, Generation could be assessed up to $168 million for losses incurred at any plant insured by the insurance companies. In the event that one or more acts of terrorism cause accidental property damage within a twelve-month period from the first accidental property damage under one or more policies for all insureds, the maximum recovery for all losses by all insureds will be an aggregate of $3.2 billion plus such additional amounts as the insurer may recover for all such losses from reinsurance, indemnity and any other source, applicable to such losses. The $3.2 billion maximum recovery limit is not applicable, however, in the event of a “certified act of terrorism” as defined in the Terrorism Risk Insurance Act of 2002, as a result of government indemnity. Generally, a “certified act of terrorism” is defined in the Terrorism Risk Insurance Act to be any act, certified by the U.S. government, to be an act of terrorism committed on behalf of a foreign person or interest.
Additionally, NEIL provides replacement power cost insurance in the event of a major accidental outage at a nuclear station. The premium for this coverage is subject to assessment for adverse loss experience. Including the AmerGen sites, Generation’s maximum share of any assessment is $48 million per year. Recovery under this insurance for terrorist acts is subject to the $3.2 billion aggregate limit and secondary to the property insurance described above. This limit would also not apply in cases of certified acts of terrorism under the Terrorism Risk Insurance Act as described above.
In addition, Generation participates in the American Nuclear Insurers Master Worker Program, which provides coverage for worker tort claims filed for bodily injury caused by a nuclear energy accident. This program was modified, effective January 1, 1998, to provide coverage to all workers whose “nuclear-related employment” began on or after the commencement date of reactor operations. Generation will not be liable for a retrospective assessment under this new policy; however, in the event losses incurred under the small number of policies in the old program exceed accumulated reserves, a maximum retroactive assessment of up to $50 million could apply. Generation is self-insured to the extent that any losses may exceed the amount of insurance maintained. Such losses could have a material adverse effect on Generation’s financial condition and results of operations.
For its insured losses, Generation is self-insured to the extent that any losses are within the policy deductible or may exceed the amount of insurance maintained. Such losses could have a material adverse effect on Generation’s financial condition and results of operations.
Energy Commitments
Generation’s wholesale operations include the physical delivery and marketing of power obtained through its generation capacity, and long-, intermediate- and short-term contracts. Generation maintains a net positive supply of energy and capacity, through ownership of generation assets and purchase power and lease agreements, to protect it from the potential operational failure of one of its
396
Exelon Generation Company, LLC and Subsidiary Companies
Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, unless otherwise noted)
owned or contracted power generating units. Generation has also contracted for access to additional generation through bilateral long-term purchase power agreements (PPAs). These agreements are firm commitments related to power generation of specific generation plants and/or are dispatchable in nature. Generation enters into PPAs with the objective of obtaining low-cost energy supply sources to meet its physical delivery obligations to its customers. Generation has also purchased firm transmission rights to ensure that it has reliable transmission capacity to physically move its power supplies to meet customer delivery needs. The primary intent and business objective for the use of its capital assets and contracts is to provide Generation with physical power supply to enable it to deliver energy to meet customer needs. Generation primarily uses financial contracts in its wholesale marketing activities for hedging purposes. Generation also uses financial contracts to manage the risk surrounding trading for profit activities.
Generation has entered into bilateral long-term contractual obligations for sales of energy to load-serving entities, including electric utilities, municipalities, electric cooperatives and retail load aggregators. Generation also enters into contractual obligations to deliver energy to wholesale market participants who primarily focus on the resale of energy products for delivery. Generation provides delivery of its energy to these customers through rights for firm transmission.
At December 31, 2004, Generation’s long-term commitments, relating to the purchase from and sale to unaffiliated utilities and others of energy, capacity and transmission rights as indicated in the following tables:
| Net Capacity Purchases (a) |
Power Only Sales |
Power Only Purchases |
Transmission Rights Purchases (b) | |||||||||
| 2005 |
$ | 578 | $ | 2,551 | $ | 1,446 | $ | 31 | ||||
| 2006 |
581 | 961 | 605 | 3 | ||||||||
| 2007 |
533 | 167 | 254 | – | ||||||||
| 2008 |
462 | 9 | 195 | – | ||||||||
| 2009 |
437 | 9 | 194 | – | ||||||||
| Thereafter |
3,664 | 343 | 548 | – | ||||||||
| Total (c) |
$ | 6,255 | $ | 4,040 | $ | 3,242 | $ | 34 | ||||
| (a) | Net capacity purchases include tolling agreements that are accounted for as operating leases. Amounts presented in the commitments represent Generation’s expected payments under these arrangements at December 31, 2004. Expected payments include certain capacity charges which are contingent on plant availability. |
| (b) | Transmission rights purchases include estimated commitments in 2005 and 2006 for additional transmission rights that will be required to fulfill firm sales contracts. |
| (c) | Included in the totals are $395 million of power only sales commitments related to Sithe, which were not retained by Generation following the sale of Sithe. See Note 3—Sithe and Note 20—Subsequent Events for further discussion of these transactions. |
In connection with the 2001 corporate restructuring, Generation entered into a PPA, as amended, with ComEd under which Generation has agreed to supply all of ComEd’s load requirements through 2006. Prices for this energy vary depending upon the time of day and month of delivery. Subsequent to 2006, ComEd expects to procure all of its supply from market sources, which could include Generation. Additionally, Generation entered into a PPA with PECO under which PECO obtains substantially all of its electric supply from Generation through 2010. Prices for this energy vary depending upon time of day and month of delivery. Subsequent to 2010, PECO expects to procure all of its supply from market sources, which could include Generation.
397
Exelon Generation Company, LLC and Subsidiary Companies
Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, unless otherwise noted)
Other Purchase Obligations
In addition to Generation’s energy commitments as described above, Generation has commitments to purchase fuel supplies for nuclear generation and various other purchase commitments related to the normal day-to-day operations of Generation’s business. As of December 31, 2004, these commitments were as follows:
| Expiration within | |||||||||||||||
| Total |
2005 |
2006-2007 |
2008-2009 |
2010 and beyond | |||||||||||
| Fuel purchase agreements (a) |
$ | 3,639 | $ | 639 | $ | 985 | $ | 616 | $ | 1,399 | |||||
| Other purchase commitments (b) |
230 | 66 | 75 | 57 | 32 | ||||||||||
| (a) | Fuel purchase agreements—Commitments to purchase fuel supplies for nuclear and fossil generation. |
| (b) | Other purchase commitments—Commitments for services and materials. |
Commercial Commitments
Generation’s commercial commitments as of December 31, 2004, representing commitments potentially triggered by future events, are as follows:
| Expiration within | |||||||||||||||
| Total |
2005 |
2006-2007 |
2008-2009 |
2010 and beyond | |||||||||||
| Letters of credit (non-debt) (a) |
$ | 172 | $ | 172 | $ | — | $ | — | $ | — | |||||
| Letters of credit (long-term debt)—interest coverage (b) |
15 | 15 | — | — | — | ||||||||||
| Performance guarantees (c) |
201 | — | — | — | 201 | ||||||||||
| Energy marketing contract guarantees (d) |
261 | 156 | 65 | — | 40 | ||||||||||
| Nuclear insurance premiums (e) |
1,710 | — | — | — | 1,710 | ||||||||||
| Exelon New England guarantees (f) |
17 | — | — | — | 17 | ||||||||||
| Total commercial commitments |
$ | 2,376 | $ | 343 | $ | 65 | $ | — | $ | 1,968 | |||||
| (a) | Letters of credit (non-debt)—Non-debt letters of credit maintained to provide credit support for certain transactions as requested by third parties. Guarantees of $62 million have been issued to provide support for certain letters of credit as required by third parties. Includes letters of credit of $95 million that will be eliminated upon the sale of Sithe to Dynegy. See Note 20—Subsequent Events for further information regarding the sale of Sithe. |
| (b) | Letters of credit (long-term debt)—interest coverage—Reflects the interest coverage portion of letters of credit supporting floating-rate pollution control bonds. The principal amount of the floating-rate pollution control bonds of $520 million is reflected in long-term debt in Generation’s Consolidated Balance Sheet. |
| (c) | Performance guarantees—Guarantees issued to ensure execution under specific contracts. |
| (d) | Energy marketing contract guarantees—Guarantees issued to ensure performance under energy commodity contracts. In connection with the transfer of Exelon Energy to Generation effective January 1, 2004, Generation acquired $162 million in energy marketing contract guarantees. Includes guarantees of $30 million that will be eliminated upon the sale of Sithe to Dynegy. See Note 20—Subsequent Events for further information regarding the sale of Sithe. |
| (e) | Nuclear insurance premiums—Represent the maximum amount that Generation would be required to pay for retrospective premiums in the event of nuclear disaster at any domestic site under the Secondary Financial Protection pool as required under the Price-Anderson Act. |
| (f) | Exelon New England guarantees—Mystic Development LLC (Mystic), a former affiliate of Exelon New England, has a long-term agreement through January 2020 with Distrigas of Massachusetts Corporation (Distrigas) for gas supply, primarily for the Boston Generating units. Under the agreement, gas purchase prices from Distrigas are indexed to the New England gas markets. Exelon New England has guaranteed Mystic’s financial obligations to Distrigas under the long-term supply |
398
Exelon Generation Company, LLC and Subsidiary Companies
Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, unless otherwise noted)
| agreement. Exelon New England’s guarantee to Distrigas remained in effect following the transfer of ownership interest in Boston Generating in May 2004. Under FIN 45, approximately $16 million is included as a liability within the Consolidated Balance Sheet of Exelon as of December 31, 2004 related to this guarantee. The terms of the guarantee do not limit the potential future payments that Exelon New England could be required to make under the guarantee. Other guarantees associated with Exelon New England total less than $1 million. |
Generation acquired a $50 million letter of credit to support the contractual obligations of Sithe and its subsidiaries upon the completion of the November 2003 transaction with Resevoir. See Exelon’s “Management’s Discussion and Analysis of Financial Condition and Results of Operation—Liquidity and Capital Resources—Credit Issues” below for further discussion of Exelon’s credit agreement.
Environmental Issues
General. Under Federal and state environmental laws, Generation is generally liable for the costs of remediating environmental contamination of property now owned and of property contaminated by hazardous substances generated by Generation.
As of December 31, 2004, Generation had accrued $16 million for environmental investigation and remediation costs. Generation cannot reasonably estimate whether it will incur other significant liabilities for additional investigation and remediation costs at these or additional sites identified by Generation, environmental agencies or others, or whether such costs will be recoverable from third parties.
Section 316(b) of the Clean Water Act. In July 2004, the EPA issued the final Phase II rule implementing Section 316(b) of the Clean Water Act. This rule establishes national requirements for reducing the adverse environmental impacts from the entrainment and impingement of aquatic organisms at existing power plants. The rule identifies particular standards of performance with respect to entrainment and impingement and requires each facility to monitor and validate this performance in future years. The requirements will be implemented through state-level National Pollutant Discharge Elimination System (NPDES) permit programs. All of Generation’s power generation facilities with cooling water systems are subject to the regulations. Facilities without closed-cycle recirculating systems are potentially most affected. Those facilities are Clinton, Cromby, Dresden, Eddystone, Fairless Hills, Handley, Mountain Creek, New Boston, Oyster Creek, Peach Bottom, Quad Cities and Salem. Generation is currently evaluating compliance options at its affected plants. At this time, Generation cannot estimate the effect that compliance with the Phase II rule requirements will have on the operation of its generating facilities and its future results of operations, financial condition and cash flows. There are many factors to be considered and evaluated to determine how Generation will comply with the Phase II rule requirements and the extent to which there such compliance may result in financial and operational impacts. The considerations and evaluations include, but are not limited to obtaining clarifying interpretations of the requirements from state regulators, resolving outstanding litigation proceedings concerning the requirements, completing studies to establish biological baselines for each facility and performing environmental and economic cost benefit evaluation of the potential compliance alternatives in accordance with the requirements.
Cotter Corporation. The EPA has advised Cotter Corporation (Cotter), a former ComEd subsidiary, that it is potentially liable in connection with radiological contamination at a site known as the West Lake Landfill in Missouri. On February 18, 2000, ComEd sold Cotter to an unaffiliated third party. As part of the sale, ComEd agreed to indemnify Cotter for any liability incurred by Cotter as a result of any liability arising in connection with the West Lake Landfill. In connection with Exelon’s 2001 corporate
399
Exelon Generation Company, LLC and Subsidiary Companies
Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, unless otherwise noted)
restructuring, this responsibility to indemnify Cotter was transferred to Generation. Cotter is alleged to have disposed of approximately 39,000 tons of soils mixed with 8,700 tons of leached barium sulfate at the site. Cotter, along with three other companies identified by the EPA as potentially responsible parties (PRPs), has submitted a draft feasibility study addressing options for remediation of the site. The PRPs are also engaged in discussions with the State of Missouri and the EPA. The estimated costs of the anticipated remediation strategy for the site range up to $22 million. Once a remedy is selected, it is expected that the PRPs will agree on an allocation of responsibility for the costs. Generation has accrued what it believes to be an adequate amount to cover its anticipated share of the liability.
Leases
Minimum future operating lease payments, including lease payments for real estate and rail cars, as of December 31, 2004 were:
| 2005 |
$ | 45 | |
| 2006 |
45 | ||
| 2007 |
42 | ||
| 2008 |
41 | ||
| 2009 |
39 | ||
| Thereafter |
511 | ||
| Total minimum future lease payments (a) |
$ | 723 | |
| (a) | Generation’s tolling agreements are accounted for as operating leases and are reflected as net capacity purchases in the energy commitments table above. |
Rental expense under operating leases totaled $33 million, $24 million and $25 million for the years ended December 31, 2004, 2003 and 2002, respectively.
Litigation
Real Estate Tax Appeals. Generation is challenging real estate taxes assessed on nuclear plants since 1997. Generation is involved in real estate tax appeals for 2000 through 2004, regarding the valuation of its Limerick and Peach Bottom plants, Quad Cities Station (Rock Island County, IL), Three Mile Island Nuclear Station (Dauphin County, PA) and Oyster Creek Nuclear Generating Station (Forked River, NJ).
During 2003, upon completion of updated nuclear plant appraisal studies, Generation recorded reductions of $15 million to reserves recorded for exposures associated with the real estate taxes. While Generation believes the resulting reserve balances as of December 31, 2004 reflect the most likely probable expected outcome of the litigation and appeals proceedings in accordance with SFAS No. 5, “Accounting for Contingencies,” the ultimate outcome of such matters could result in additional unfavorable or favorable adjustments to the consolidated financial statements of Generation, and such adjustments could be material.
General. Generation is involved in various other litigation matters that are being defended and handled in the ordinary course of business, and Generation maintains accruals for such costs that are probable of being incurred and subject to reasonable estimation. The ultimate outcome of such
400
Exelon Generation Company, LLC and Subsidiary Companies
Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, unless otherwise noted)
matters, as well as the matters discussed above, while uncertain, is not expected to have a material adverse effect on its financial condition or results of operations.
Capital Commitments
SCEP. Generation has a 71% interest in SCEP which owns a peaking facility in Chicago. SCEP is obligated to make total equity distributions of $49 million through 2022 to the party, which is not affiliated with Generation, that owns the remaining 29% interest. This amount reflects a return of that party’s investment in SCEP. Generation has the right to purchase, generally at a premium, and the other party has the right to require Generation to purchase, generally at a discount, the 29% interest in SCEP. Additionally, Generation may be required to purchase the remaining 29% interest upon the occurrence of certain events, including Generation’s failure to maintain an investment grade rating. As a result of the adoption of SFAS No. 150 on July 1, 2003, Generation reclassified the minority interest associated with SCEP to a long-term liability. The total long-term liability related to SCEP was $49 million and $51 million as of December 31, 2004 and 2003, respectively. Prior periods were not restated.
Sithe Call Option. On September 29, 2004, Generation exercised its call option and entered into an agreement to acquire Reservoir’s 50% interest in Sithe for $97 million. The closing of the call required state and Federal regulatory approvals, which were received in January 2005, and the transaction was completed on January 31, 2005. See Note 3—Sithe and Note 20—Subsequent Events for additional information.
Credit Contingencies
Dynegy. As previously disclosed, Generation is counterparty to Dynegy in various energy transactions and had financial and credit risk associated with Dynegy through Generation’s investment in Sithe at December 31, 2004. On January 31, 2005, Generation sold its investment in Sithe and, accordingly, is no longer subject to potential credit risk associated with Dynegy’s performance under the financial swap arrangement that Dynegy had with Sithe. See Note 20—Subsequent Events for further discussion of Generation’s sale of Sithe.
Fund Transfer Restrictions
Under applicable law, Generation can pay dividends only from undistributed or current earnings. At December 31, 2004 and 2003, Generation had undistributed earnings of $761 million and $602 million, respectively.
Jointly Owned Electric Utility Plant
On January 28, 2004, the NRC issued a letter requesting PSEG to conduct a review of its Salem facility, of which Generation owns 42.59%, to assess the workplace environment for raising and addressing safety issues. PSEG responded to the letter on February 28, 2004 and had independent assessments of the work environment at both facilities performed. Assessment results were provided to the NRC in May. The assessments concluded that Salem was safe for continued operation, but also identified issues that need to be addressed. At an NRC public meeting on June 16, 2004, PSEG outlined its action plans to address these issues, which focus on safety conscious work environment, the corrective action program and work management. A letter documenting these plans and
401
Exelon Generation Company, LLC and Subsidiary Companies
Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, unless otherwise noted)
commitments was sent to the NRC on June 25, 2004. PSEG provided the NRC a report of its progress and the progress of its actions to resolve identified issues at public meetings in December 2004 and will hold additional meetings during 2005. PSEG published metrics to demonstrate performance commencing in the fourth quarter of 2004.
In June 2001, the NJDEP issued a renewed National Pollutant Discharge Elimination System (NPDES) permit for Salem, expiring in July 2006, allowing for the continued operation of Salem with its existing cooling water system. An application for renewal of that permit, including a demonstration of compliance with the requirements of the recently published FWPCA Section 316(b) regulations, must be submitted to NJDEP by February 2, 2006 unless the NJDEP grants additional time to collect information to comply with the new regulations. NJDEP advised PSEG in a letter dated July 12, 2004 that it strongly recommends reducing cooling water intake flow commensurate with closed-cycle cooling as a compliance option for Salem. PSEG has not made a determination regarding how it will demonstrate compliance with the Section 316(b) regulations. If application of the Section 316(b) regulations require the retrofitting of Salem’s cooling water intake structure to reduce cooling water intake flow commensurate with closed-cycle cooling, the retrofit and any resulting cost of interim replacement power could result in material costs of compliance to the owners of the facility.
402
Exelon Generation Company, LLC and Subsidiary Companies
Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, unless otherwise noted)
17. Supplemental Financial Information
Supplemental Income Statement Information
The following tables provide additional information about Generation’s Consolidated Statements of Income for the years ended December 31, 2004, 2003 and 2002.
| For the Years Ended December 31, | |||||||||
| 2004 |
2003 |
2002 | |||||||
| Depreciation, amortization and accretion |
|||||||||
| Property, plant and equipment (a) |
$ | 294 | $ | 199 | $ | 156 | |||
| Nuclear fuel (b) |
381 | 395 | 374 | ||||||
| Asset retirement obligation accretion (c) |
210 | 160 | 120 | ||||||
| Amortization of intangibles (d) |
38 | — | — | ||||||
| Total depreciation, amortization and accretion |
$ | 923 | $ | 754 | $ | 650 | |||
| (a) | Includes amortization of capitalized software costs. |
| (b) | Included in fuel expense in the Consolidated Statements of Income. |
| (c) | Prior to the adoption of SFAS No. 143 on January 1, 2003, these amounts were recorded in depreciation expense. Upon adoption of SFAS No. 143, these amounts were recorded in operating and maintenance expense in Generation’s Consolidated Statements of Income. See Note 13—Nuclear Decommissioning and Spent Fuel Storage for further discussion of the adoption of SFAS No. 143. |
| (d) | Reflected as a reduction in revenues in the Consolidated Statements of Income, of which $32 million related to the amortization of Sithe assets. See Note 3—Sithe and Note 20—Subsequent Events for a description of Sithe’s intangible assets that are reflected in Exelon’s Consolidated Balance Sheets at December 31, 2004 and a description of the sale of Sithe that was completed on January 31, 2005. |
| For the Years Ended December 31, | ||||||||||
| 2004 |
2003 |
2002 | ||||||||
| Income (loss) in equity method investments |
||||||||||
| AmerGen (a) |
$ | — | $ | 47 | $ | 64 | ||||
| Sithe (b) |
(2 | ) | 2 | 23 | ||||||
| Sithe (c) |
(9 | ) | — | — | ||||||
| TEG and TEP(d) |
(3 | ) | — | — | ||||||
| Total |
$ | (14 | ) | $ | 49 | $ | 87 | |||
| (a) | Prior to the acquisition of British Energy’s 50% interest in December 2003. |
| (b) | Prior to consolidation of EXRES SHC, Inc. in March 2004. |
| (c) | Prior to acquisition of EXRES SHC, Inc. 49.5% interests in TEG and TEP in October 2004. |
| (d) | After acquisition of EXRES SHC, Inc. 49.5% interests in TEG and TEP in October 2004. |
403
Exelon Generation Company, LLC and Subsidiary Companies
Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, unless otherwise noted)
| For the Years Ended December 31, | ||||||||||
| 2004 |
2003 |
2002 | ||||||||
| Taxes other than income |
||||||||||
| Real estate |
$ | 112 | $ | 83 | $ | 102 | ||||
| Payroll |
48 | 39 | 46 | |||||||
| Other |
11 | (2 | ) | 16 | ||||||
| Total |
$ | 171 | $ | 120 | $ | 164 | ||||
| For the Years Ended December 31, | |||||||||||
| 2004 |
2003 |
2002 | |||||||||
| Other, net |
|||||||||||
| Gain on sale of Boston Generating (a) |
$ | 85 | $ | — | $ | — | |||||
| Decommissioning-related activities: |
|||||||||||
| Decommissioning trust fund income (b) |
194 | 79 | 77 | ||||||||
| Decommissioning trust fund income—AmerGen (b) |
43 | — | — | ||||||||
| Other-than-temporary impairment of decommissioning trust funds (c) |
(268 | ) | — | — | |||||||
| Contractual offset to non-operating decommissioning-related activities (d) |
66 | (79 | ) | — | |||||||
| Gain on sale of Sithe-related assets |
6 | — | — | ||||||||
| Impairment of investment in Sithe |
— | (255 | ) | — | |||||||
| Other income (expense) |
17 | (8 | ) | 3 | |||||||
| Total |
$ | 143 | $ | (263 | ) | $ | 80 | ||||
| (a) | See Note 2—Acquisitions and Dispositions for further discussion of Generation’s sale of Boston Generating. |
| (b) | Includes investment income and realized gains/(losses). |
| (c) | Includes other-than-temporary impairments totaling $255 million, $5 million and $8 million on nuclear decommissioning trust funds for the former ComEd units, the former PECO units and AmerGen units, respectively. |
| (d) | Includes the elimination of non-operating decommissioning-related activity for those units that are subject to contractual accounting, including the elimination of decommissioning trust fund income and other-than-temporary impairments for certain nuclear units. See Note 13—Nuclear Decommissioning and Spent Fuel Storage and Note 15—Fair Value of Financial Assets and Liabilities for more information regarding the contractual accounting applied for certain nuclear units. |
404
Exelon Generation Company, LLC and Subsidiary Companies
Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, unless otherwise noted)
Supplemental Cash Flow Information
The following table provides additional information about Generation’s Consolidated Statements of Cash Flows for the years ended December 31, 2004, 2003 and 2002.
| For the Years Ended December 31, |
||||||||||||
| 2004 |
2003 |
2002 |
||||||||||
| Cash paid (received) during the year |
||||||||||||
| Interest (net of amount capitalized) |
$ | 163 | $ | 57 | $ | 63 | ||||||
| Income taxes (net of refunds) |
20 | (14 | ) | (37 | ) | |||||||
| Non-cash investing and financing activities |
||||||||||||
| Purchase accounting estimate adjustment |
$ | 29 | $ | 59 | $ | — | ||||||
| Consolidation of Sithe pursuant to FIN 46-R |
85 | — | — | |||||||||
| Disposal of Boston Generating (a) |
102 | — | — | |||||||||
| Increase in asset retirement cost asset |
829 | — | — | |||||||||
| Note received in conjunction with the sale of Sithe to Reservoir |
— | 92 | — | |||||||||
| Note cancelled in connection with the acquisition of Sithe International from Sithe |
92 | — | — | |||||||||
| Capital lease obligations |
1 | — | 52 | |||||||||
| Non-cash (distribution) contribution (to) from member |
(4 | ) | (17 | ) | 3 | |||||||
| Contribution of land from minority interest of consolidated subsidiary |
— | — | 12 | |||||||||
| Note issued to Sithe in the Exelon New England acquisition |
— | 2 | 534 | |||||||||
| (a) | See Note 2—Acquisitions and Dispositions for additional information regarding the disposition of Boston Generating. |
Supplemental Balance Sheet Information
The following tables provide additional information about assets recorded within Generation’s Consolidated Balance Sheets as of December 31, 2004 and 2003.
| December 31, | ||||||
| 2004 |
2003 | |||||
| Investments |
||||||
| Investment in EXRES SHC, Inc. (a) |
$ | — | $ | 47 | ||
| Investment in TEG and TEP (b) |
79 | — | ||||
| Investment in Keystone Fuels, LLC and Conemaugh Fuels, LLC |
9 | 9 | ||||
| Other |
15 | 9 | ||||
| Total |
$ | 103 | $ | 65 | ||
| (a) | On November 25, 2003, Generation, Reservoir and Sithe completed a series of transactions that resulted in Generation indirectly owning a 50% interest in Sithe through EXRES SHC, Inc. See Note 3—Sithe and Note 20—Subsequent Events for further information on these transactions and the ultimate disposal of Generation’s investment in Sithe. |
| (b) | Generation acquired a 49.5% interest in two facilities in Mexico on October 13, 2004. See Note 3—Sithe for further information on this transaction. |
405
Exelon Generation Company, LLC and Subsidiary Companies
Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, unless otherwise noted)
| December 31, | ||||||
| 2004 |
2003 | |||||
| Accrued expenses |
||||||
| Payroll and benefits |
$ | 185 | $ | 215 | ||
| Taxes accrued |
98 | 104 | ||||
| Interest |
36 | 10 | ||||
| Other |
48 | 94 | ||||
| Total |
$ | 367 | $ | 423 | ||
| December 31, |
||||||||
| 2004 |
2003 |
|||||||
| Accumulated other comprehensive loss |
||||||||
| Net unrealized loss on cash-flow hedges |
$ | (146 | ) | $ | (149 | ) | ||
| Foreign currency translation adjustment |
1 | (1 | ) | |||||
| Net unrealized gain on marketable securities |
62 | 14 | ||||||
| Total accumulated other comprehensive loss |
$ | (83 | ) | $ | (136 | ) | ||
406
Exelon Generation Company, LLC and Subsidiary Companies
Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, unless otherwise noted)
18. Related-Party Transactions
The financial statements of Generation include related-party transactions with unconsolidated affiliates as presented in the tables below. Generation accounted for its investment in AmerGen as an equity method investment prior to the acquisition of British Energy’s 50% interest in December 2003 and its investment in Sithe as an equity method investment prior to its consolidation as of March 31, 2004. Additionally, effective January 1, 2004, Enterprises’ competitive retail sales business, Exelon Energy, was transferred to Generation.
| For the Years Ended December 31, | |||||||||
| 2004 |
2003 |
2002 | |||||||
| Operating revenues from affiliates |
|||||||||
| ComEd (a) |
$ | 2,374 | $ | 2,479 | $ | 2,559 | |||
| PECO (a) |
1,465 | 1,433 | 1,438 | ||||||
| Exelon Energy (b) |
— | 213 | 247 | ||||||
| BSC |
2 | — | — | ||||||
| Purchased power from affiliates |
|||||||||
| AmerGen (c) |
— | 382 | 273 | ||||||
| ComEd (a) |
9 | 38 | 37 | ||||||
| PECO (a) |
1 | — | 3 | ||||||
| Exelon Energy (b) |
— | 9 | 18 | ||||||
| Operating and Maintenance from affiliates |
|||||||||
| Sithe (d) |
— | — | 13 | ||||||
| ComEd (a) |
8 | 12 | 14 | ||||||
| PECO (a) |
8 | 10 | 9 | ||||||
| BSC (e) |
223 | 127 | 116 | ||||||
| Interest expense to affiliates |
|||||||||
| Sithe (d) |
— | 9 | 2 | ||||||
| Exelon (f) |
1 | 2 | 5 | ||||||
| Exelon intercompany money pool (f) |
2 | 2 | — | ||||||
| Interest income from affiliates |
|||||||||
| AmerGen (c) |
— | 1 | 2 | ||||||
| ComEd (g) |
— | — | 4 | ||||||
| Services provided to affiliates |
|||||||||
| AmerGen (c) |
— | 111 | 70 | ||||||
| Sithe (d) |
— | — | 1 | ||||||
| Cash distribution paid to member |
662 | 189 | 27 | ||||||
407
Exelon Generation Company, LLC and Subsidiary Companies
Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, unless otherwise noted)
| December 31, | ||||||
| 2004 |
2003 | |||||
| Receivables from affiliates (current) |
||||||
| ComEd (a) |
$ | 189 | $ | 171 | ||
| ComEd decommissioning (h) |
11 | 11 | ||||
| PECO (a) |
125 | 115 | ||||
| BSC (e) |
7 | 3 | ||||
| Exelon Energy (b) |
— | 18 | ||||
| Sithe (d) |
— | 3 | ||||
| Other |
— | 8 | ||||
| Note receivable from affiliate (current) |
||||||
| Note receivable from Sithe (d) |
— | 92 | ||||
| Note receivable from affiliate (noncurrent) |
||||||
| ComEd decommissioning (h) |
11 | 22 | ||||
| Payable to affiliate (current) |
||||||
| Exelon (f) |
42 | 1 | ||||
| Notes payable to affiliates (current) |
||||||
| Exelon (f) |
— | 115 | ||||
| Exelon intercompany money pool (f) |
283 | 301 | ||||
| Sithe (d) |
— | 90 | ||||
| Payables to affiliates (noncurrent) |
||||||
| ComEd decommissioning (i) |
1,433 | 1,183 | ||||
| PECO decommissioning (i) |
46 | 12 | ||||
| (a) | Effective January 1, 2001, Generation entered into PPAs with ComEd and PECO, as amended, to provide the full energy requirements of ComEd and PECO. Effective April 1, 2004, Generation entered into a one-year gas supply agreement with PECO. Generation purchases electric and ancillary services from ComEd and buys energy from PECO for Generation’s own use. In order to facilitate payment processing, ComEd processes certain invoice payments on behalf of Generation. Prior to joining PJM Interconnection, LLC (PJM) on May 1, 2004, ComEd also provided transmission services to Generation. Amounts charged by PECO and ComEd to Generation for transmission have been recorded as intercompany purchased power by Generation. |
| (b) | Prior to May 1, 2004, Generation sold power to Exelon Energy and purchased excess power from Exelon Energy. Prior to the transfer of Exelon Energy’s assets to Generation from Enterprises effective January 1, 2004, Exelon Energy was an intercompany affiliate of Generation. |
| (c) | Prior to Generation’s purchase of British Energy’s 50% interest in AmerGen in December 2003, AmerGen was an unconsolidated affiliate of Generation and was considered to be a related party of Generation. Generation entered into PPAs dated June 26, 2003, December 18, 2001 and November 22, 1999 with AmerGen. Under the 2003 PPA, Generation agreed to purchase from AmerGen all the energy from Oyster Creek through April 9, 2009. Under the 2001 PPA, Generation agreed to purchase from AmerGen all the energy from Unit No. 1 at Three Mile Island Nuclear Station from January 1, 2002 through December 31, 2014. Under the 1999 PPA, Generation agreed to purchase from AmerGen all of the residual energy from Clinton Nuclear Power Station (Clinton), through December 31, 2002. Currently, the residual output is approximately 31% of the total output of Clinton. In February 2002, Generation entered into an agreement to loan AmerGen up to $75 million at an interest rate equal to the 1-month London Interbank Offering Rate plus 2.25%. In July 2002, the limit of the loan agreement was increased to $100 million and the maturity date was extended to July 1, 2003. The loan was paid in its entirety during 2003. Under a service agreement dated March 1, 1999, Generation provides AmerGen with certain operation and support services to the nuclear facilities owned by AmerGen. This service agreement has an indefinite term and may be terminated by Generation or AmerGen with 90 days notice. Generation is compensated for these services at cost. |
| (d) | Under a service agreement dated December 18, 2000, Sithe provides Generation certain fuel and project development services. Sithe is compensated for these services at cost. In December 2003, Sithe received letter of credit proceeds of $3 million, which Generation was billed on behalf of Sithe. Under the terms of the agreement to acquire Exelon New England dated November 1, 2002, Generation issued a note to Sithe that was subsequently modified and increased to $536 million. During 2003, Generation repaid $446 million of this note. In the first quarter of 2004, Generation repaid $27 million prior to |
408
Exelon Generation Company, LLC and Subsidiary Companies
Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, unless otherwise noted)
| consolidation of Sithe in accordance with the provisions of FIN 46-R. The balance of the note, which bore interest at the rate of LIBOR plus 0.875%, was paid upon the completion of a series of transactions that resulted in Generation’s sale of Sithe on January 31, 2005. See Note 20—Subsequent Events regarding the sale of Generation’s investment in Sithe. In connection with a series of transactions in November 2003 that restructured the ownership of Sithe (see Note 3—Sithe for additional information), Generation received a $92 million note receivable from EXRES SHC, Inc., which holds the common stock of Sithe. Generation owns 50% of EXRES SHC, Inc. and consolidated its investment pursuant to FIN 46-R effective March 31, 2004. Prior to the consolidation of Sithe in connection with FIN 46-R, Sithe was an unconsolidated affiliate of Exelon and Generation and was considered to be a related party of Exelon and Generation. This note was cancelled in connection with the purchase of Sithe International. See Note 3—Sithe for additional information. |
| (e) | Generation receives a variety of corporate support services from Exelon Business Services Company (BSC), including legal, human resources, financial, information technology and supply management services. All services are provided at cost, including application overhead. A portion of such services is capitalized. Some third-party reimbursements due Generation are recovered through BSC. Additionally, in 2004, due to the centralization of certain functions, certain employees were transferred from Generation to BSC including supply and information technology support and management of other support services. |
| (f) | Represents the outstanding balance of amounts borrowed under the intercompany money pool and other short-term obligations payable to Exelon. In order to facilitate payment processing, Exelon processes certain invoice payments on behalf of Generation. |
| (g) | Interest income for 2002 is related to unpaid ComEd PPA billings referred to in note (a). |
| (h) | Generation has a short-term and a long-term receivable from ComEd, primarily representing ComEd’s legal requirements to remit collections of nuclear decommissioning costs from its customers to Generation resulting from the 2001 corporate restructuring. |
| (i) | Generation has long-term payables to ComEd and PECO as a result of the nuclear decommissioning contractual construct whereby, to the extent the assets associated with decommissioning are greater than the applicable ARO, such amounts are due back to ComEd and PECO, as applicable, for payment to the ratepayers. |
19. Quarterly Data (Unaudited)
The data shown below includes all adjustments that Generation considers necessary for a fair presentation of such amounts:
| Operating Revenues |
Operating Income (Loss) |
Income (Loss) Before Cumulative Effect of a Change in Accounting Principle |
Net Income (Loss) |
||||||||||||||||||||||||
| 2004 |
2003 |
2004 (a) |
2003 (b) |
2004 |
2003 |
2004 |
2003 |
||||||||||||||||||||
| Quarter ended: |
|||||||||||||||||||||||||||
| March 31 (c) |
$ | 1,953 | $ | 1,879 | $ | 127 | $ | 125 | $ | 70 | $ | (52 | ) | $ | 102 | $ | 56 | ||||||||||
| June 30 |
1,948 | 1,886 | 211 | 223 | 178 | 142 | 178 | 142 | |||||||||||||||||||
| September 30 |
2,253 | 2,537 | 562 | (683 | ) | 319 | (428 | ) | 319 | (428 | ) | ||||||||||||||||
| December 31 |
1,784 | 1,833 | 130 | 220 | 74 | 97 | 74 | 97 | |||||||||||||||||||
| (a) | Operating income (loss) has been adjusted to reflect a reclassification from operating and maintenance expense to other, net of $30 million and $28 million, for the three months ended March 31, 2004 and June 30, 2004, respectively, for comparison purposes related to decommissioning accounting presentation. These reclassifications had no impact on net income as reported. |
| (b) | Operating income (loss) has been adjusted to reflect a reclassification from operating and maintenance expense to other, net of $31 million, $22 million, $23 million and $3 million for the three months ended March 31, 2003, June 30, 2003, September 30, 2003 and December 31, 2003, respectively, for comparison purposes related to decommissioning accounting presentation. These reclassifications had no impact on net income as reported. |
| (c) | Operating income and net income for the three months ended March 31, 2004 has been adjusted to reflect a reduction in net periodic postretirement benefit cost of $3 million due to the adoption of FSP FAS 106-2. See Note 1—Significant Accounting Policies for additional information. |
409
Exelon Generation Company, LLC and Subsidiary Companies
Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, unless otherwise noted)
20. Subsequent Events
On January 31, 2005, subsidiaries of Generation completed a series of transactions that resulted in Generation’s exit from its investment in Sithe. Specifically, subsidiaries of Generation closed on the acquisition of Reservoir’s 50% interest in Sithe and the sale of 100% of Sithe to Dynegy. Prior to closing on the sale to Dynegy, subsidiaries of Generation received from Sithe approximately $65 million in cash distributions. As a result of the sale, Generation will deconsolidate from its balance sheet approximately $820 million of debt and will be released from approximately $125 million of credit support associated with the Independence project. Additionally, Exelon issued certain guarantees to Dynegy that will be taken into account in the final determination of the gain or loss on the sale. See further information regarding Generation’s investment in Sithe at Note 3—Sithe.
410
| ITEM 9. | CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE |
Exelon, ComEd, PECO and Generation
None.
| ITEM 9A. | CONTROLS AND PROCEDURES |
Exelon, ComEd, PECO and Generation
During the fourth quarter of 2004, each registrant’s management, including its principal executive officer and principal financial officer, evaluated that registrant’s disclosure controls and procedures related to the recording, processing, summarizing and reporting of information in that registrant’s periodic reports that it files with the SEC. These disclosure controls and procedures have been designed by each registrant to ensure that (a) material information relating to that registrant, including its consolidated subsidiaries, is made known to that registrant’s management, including its principal executive officer and principal financial officer, by other employees of that registrant and its subsidiaries, and (b) this information is recorded, processed, summarized, evaluated and reported, as applicable, within the time periods specified in the SEC’s rules and forms. Due to the inherent limitations of control systems, not all misstatements may be detected. These inherent limitations include the realities that judgments in decision-making can be faulty and that breakdowns can occur because of simple error or mistake. Additionally, controls could be circumvented by the individual acts of some persons or by collusion of two or more people. Each registrant’s controls and procedures can only provide reasonable, not absolute, assurance that the above objectives have been met.
Accordingly, as of December 31, 2004, the principal executive officer and principal financial officer of each registrant concluded that such registrant’s disclosure controls and procedures were effective to accomplish their objectives. Each registrant continually strives to improve its disclosure controls and procedures to enhance the quality of its financial reporting and to maintain dynamic systems that change as conditions warrant.
Exelon
Since Exelon is an accelerated filer, its management is required to assess and report on the effectiveness of its internal control over financial reporting as of December 31, 2004. As a result of that assessment, we determined that there were no material weaknesses as of December 31, 2004 and, therefore, concluded that Exelon’s internal control over financial reporting was effective. Management’s Report on Internal Control Over Financial Reporting is included in Item 8—Financial Statements and Supplementary Data.
411
PART III
| ITEM 10. | DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT |
Executive Officers
The information required by Item 10 relating to executive officers is set forth above in ITEM 1. Business—Executive Officers of the Registrants at December 31, 2004.
Directors
Nicholas DeBenedictis. Age 59. Director of Exelon Corporation since April 23, 2002. Class I director. Chairman and Chief Executive Officer of Aqua America Inc. (water utility with operations in 12 states). Other directorships: Met-Pro Corporation and Glatfelter Co.
Sue L. Gin. Age 63. Director of Exelon Corporation since October 20, 2000. Class I director. Founder, Owner, Chairman and Chief Executive Officer of Flying Food Group, LLC. (in-flight catering company). Other directorships: Briazz, Inc.; Centerplate, Inc.; and Miavita, LLC.
Edgar D. Jannotta. Age 73. Director of Exelon Corporation since October 20, 2000. Class I director. Chairman of William Blair & Company, L.L.C. (investment banking and brokerage company). Other directorships: Aon Corporation, Bandag, Incorporated and Molex Incorporated.
G. Fred DiBona, Jr. Mr. DiBona was a director of Exelon Corporation from October 20, 2000 until his death on January 11, 2005. He was President and CEO of Independence Blue Cross (health insurance organization). Also Chairman, President and CEO of Keystone Health Plan East, a subsidiary of Independence Blue Cross. Other directorships: Tasty Baking Company, Aqua America Inc., Eclipsys Corporation, Geo Group Inc. and Crown Holdings, Inc.
Edward A. Brennan. Age 71. Director of Exelon Corporation since October 20, 2000. Class II director. Retired Chairman and CEO of Sears, Roebuck and Co. (retail merchandiser). Other directorships: Allstate Corporation, AMR Corporation, 3M Company, McDonald’s Corporation and Morgan Stanley.
Bruce DeMars. Age 69. Director of Exelon Corporation since October 20, 2000. Class II director. Partner, RSD, LLC (introduces new products and services to industry and government). Retired Admiral, United States Navy, and former Director of the Naval Nuclear Propulsion Program. Other directorships: Duratek, Inc., McDermott International Inc. and Oceanworks International, Inc.
Nelson A. Diaz. Age 57. Director of Exelon Corporation since January 27, 2004. Class II director. Partner, Blank Rome LLP (legal services) since March 2004. Former City Solicitor, City of Philadelphia from November 2001 to January 2004; Judge, Court of Common Pleas, First Judicial District of Pennsylvania, 1981 to 1993. Former Partner, Blank Rome Comisky & McCauley (legal services), February 1997 to November 2001; Former General Counsel, United States Department of Housing and Urban Affairs 1993 to 1997.
John W. Rowe. Age 59. Chairman, President and Chief Executive Officer of Exelon Corporation since November 2004; Chairman and Chief Executive Officer since April 2002, serving as President through May 2003; President and co-Chief Executive Officer from October 20, 2000 through April 2002. Class II director. Former Chairman, President and Chief Executive Officer of Unicom Corporation and Commonwealth Edison Company. Former President and Chief Executive Officer of the New
412
England Electric System. Other directorships: UnumProvident Corporation, Sunoco, Inc. and The Northern Trust Company.
Ronald Rubin. Age 73. Director of Exelon Corporation since October 20, 2000. Class II director. Chairman and Chief Executive Officer of the Pennsylvania Real Estate Investment Trust (a real estate management and development company).
M. Walter D’Alessio. Age 71. Director of Exelon Corporation since October 20, 2000. Class III director. Vice Chairman of NorthMarq Capital (real estate investment banking) and President of NorthMarq Advisors (real estate consulting). Director and Non-executive Chairman of Legg Mason Real Estate Services Inc. (commercial mortgage, banking, and pension fund advisors). Other directorships: Legg Mason Real Estate Services, Inc., Independence Blue Cross; Brandywine Real Estate Investment Trust and Point Five Technologies.
Rosemarie B. Greco. Age 58. Director of Exelon Corporation since October 20, 2000. Class III director. Director of the Office of Health Care Reform, Commonwealth of Pennsylvania, since January 2003. Principal of GRECOventures Ltd. Former President of CoreStates Financial Corporation and former Director, President and CEO of CoreStates Bank, N.A. Other directorships: Sunoco, Inc., and Pennsylvania Real Estate Investment Trust. Trustee of SEI I Mutual Funds of SEI Investments.
John M. Palms, Ph.D. Age 69. Director of Exelon Corporation since October 20, 2000. Class III director. Distinguished President Emeritus of the University of South Carolina and Distinguished University Professor of Physics. Former President of Georgia State University; former Vice-President for Academic Affairs and the Charles Howard Chandler Professor of Physics at Emory University. Other directorships: Assurant Inc. (formerly Fortis, Inc. (United States)). SIMCOM International Holdings, Inc., and Computer Task Group, Inc. Also Chairman of the Board of Trustees of the Institute for Defense Analyses, and formerly a member of the National Nuclear Accreditation board and the Advisory Council for the Institute of Nuclear Power Operations.
John W. Rogers, Jr. Age 46. Director of Exelon Corporation since October 20, 2000. Class III director. Founder, Chairman and CEO of Ariel Capital Management, LLC (an institutional money management firm). Trustee of Ariel Investment Trust. Other directorships: Aon Corporation, McDonald’s Corporation and Bally Total Fitness Holding Corporation.
Richard L. Thomas. Age 74. Director of Exelon Corporation since October 20, 2000. Class III director. Retired Chairman of First Chicago NBD Corporation (banking and financial services) and the First National Bank of Chicago. Other directorships: The PMI Group, Inc., Sabre Holdings Corporation, and Sara Lee Corporation.
Audit Committee
The Exelon audit committee consists of John M. Palms, Ph.D., its Chair, M. Walter D’Alessio, Sue L. Gin and Richard L. Thomas. The Exelon board of directors has determined that all members of the Exelon audit committee are independent directors, are financially literate, have accounting or related financial management expertise, and are “audit committee financial experts” under applicable SEC rules. Each member of the audit committee obtained these attributes through the business experience and directorships described above and through service on audit committees of various public companies, including the audit committees of Exelon’s predecessor companies, PECO and Unicom Corporation.
413
Code of Ethics
Exelon’s Code of Business Conduct is the code of ethics that applies to Exelon’s Chief Executive Officer, Chief Financial Officer, Corporate Controller, and other finance organization employees. The Code of Business Conduct is filed as Exhibit 14 to this report and is available on Exelon’s website at www.exeloncorp.com. The Code of Business Conduct will be made available, without charge, in print to any shareholder who requests such document from Katherine K. Combs, Vice President and Corporate Secretary, Exelon Corporation, P.O. Box 805398, Chicago, Illinois 60680-5398.
If any substantive amendments to the Code of Business Conduct are made or any waivers are granted, including any implicit waiver, from a provision of the Code of Business Conduct, to its Chief Executive Officer, Chief Financial Officer or Corporate Controller, Exelon will disclose the nature of such amendment or waiver on Exelon’s website, www.exeloncorp.com, or in a report on Form 8-K.
Section 16(a) Beneficial Ownership Reporting Compliance
Based upon signed affirmations received from directors and officers, as well as administrative review of company plans and accounts administered by private brokers on behalf of directors and officers which have been disclosed to Exelon by the individual directors and officers, Exelon believes that its directors and officers made all required filings on a timely basis during 2004. However, in conducting a thorough review of the holdings of directors through brokers, Exelon discovered one filing that was not made on a timely basis. On June 1, 2004, Mr. G. Fred DiBona’s broker liquidated Mr. DiBona’s Keogh account to transfer the account to another broker. Mr. DiBona was unaware that the account was being liquidated or that the account included a small amount of Exelon stock. The broker apparently overlooked his prior agreement to obtain approval before trading Exelon stock on behalf of Mr. DiBona. When the failure to report was discovered, Exelon immediately reviewed the details of the transaction with the reporting individual and made the necessary filing.
Executive Officers
The information required by Item 10 relating to executive officers is set forth above in ITEM 1. Business—Executive Officers of the Registrants at December 31, 2004.
Directors
John W. Rowe. Age 59. Chairman, Chief Executive Officer and President of Exelon Corporation since November 2004; Chairman and Chief Executive Officer since April 2002, serving as President through May 2003; President and co-Chief Executive Officer from October 20, 2000 through April 2002. Director of ComEd since 1998. Former Chairman, President and CEO of Unicom Corporation and Commonwealth Edison Company. Former President and CEO of the New England Electric System. Other directorships: UnumProvident Corporation, The Northern Trust Company, and Sunoco, Inc.
Frank M. Clark. Age 59. Executive Vice President and Chief of Staff of Exelon Corporation since August 1, 2004. President of ComEd since October 2001. Previously Senior Vice President, distribution, customer and market services and external affairs of ComEd. Other directorship: Waste Management, Inc. and ShoreBank Corporation.
Robert S. Shapard. Age 49. Executive Vice President and Chief Financial Officer of Exelon Corporation since October 21, 2002. Previously Executive Vice President and CFO of Covanta Energy Corporation during 2002. For 2000 through 2001, Executive Vice President and CFO of Ultramar
414
Diamond Shamrock. Prior to that, Chief Executive Officer of TXU Australia, LTD, a wholly owned subsidiary of TXU Corporation.
S. Gary Snodgrass. Age 53. Executive Vice President and Chief Human Resources Officer, Exelon since August 1, 2004. Prior to his election to his listed position, Mr. Snodgrass was Chief Administrative Officer of Exelon; Senior Vice President of ComEd and Unicom; Vice President of ComEd and Unicom; and Vice President of USG Corporation.
John L. Skolds Age 52. Executive Vice President of Exelon Corporation since February 1, 2004. Senior Vice President of Exelon and Exelon Generation Company, LLC and Chief Nuclear Officer from October 2000 through February 2004. Vice President of Unicom Corporation and ComEd, Chief Operating Officer, Nuclear Generation Group of ComEd from August 2000 through October 2000. President and Chief Operating Officer of South Carolina Electric and Gas from 1995 through August 2000.
Audit Committee
ComEd is a controlled subsidiary of Exelon and does not have a separate audit committee. Instead, that function is fulfilled by the audit committee of the Exelon board of directors. See discussion of Exelon’s audit committee above.
Code of Ethics
Exelon’s Code of Business Conduct is the code of ethics that applies to ComEd’s Chief Executive Officer, Chief Financial Officer, Corporate Controller, and other finance organization employees. The Code of Business Conduct is filed as Exhibit 14 to this report and is available on Exelon’s website at www.exeloncorp.com. The Code of Business Conduct will be made available, without charge, in print to any shareholder who requests such document from Katherine K. Combs, Vice President and Corporate Secretary, Exelon Corporation, P.O. Box 805398, Chicago, Illinois 60680-5398.
If any substantive amendments to the Code of Business Conduct are made or any waivers are granted, including any implicit waiver, from a provision of the Code of Business Conduct, to its Chief Executive Officer, Chief Financial Officer or Corporate Controller, ComEd will disclose the nature of such amendment or waiver on Exelon’s website, www.exeloncorp.com, or in a report on Form 8-K.
Executive Officers
The information required by Item 10 relating to executive officers is set forth above in ITEM 1. Business—Executive Officers of the Registrants at December 31, 2004.
Directors
John W. Rowe. Age 59. Chairman, Chief Executive Officer and President of Exelon Corporation since November 2004; Chairman and Chief Executive Officer since April 2002, serving as President through May 2003; President and co-Chief Executive Officer from October 20, 2000 through April 2002. Director of ComEd since 1998. Former Chairman, President and CEO of Unicom Corporation and Commonwealth Edison Company. Former President and CEO of the New England Electric System. Other directorships: UnumProvident Corporation, The Northern Trust Company, and Sunoco, Inc.
415
Robert S. Shapard. Age 49. Executive Vice President and Chief Financial Officer of Exelon Corporation since October 21, 2002. Previously Executive Vice President and CFO of Covanta Energy Corporation during 2002. For 2000 through 2001, Executive Vice President and CFO of Ultramar Diamond Shamrock. Prior to that, Chief Executive Officer of TXU Australia, LTD, a wholly owned subsidiary of TXU Corporation.
Denis P. O’Brien. Mr. O’Brien, age 43. Class III director since June 30, 2003. President of PECO since April 2003. Previously Executive Vice President, Vice President of Operations, Director of Operations for the BucksMont Region and Director of Transmission and Substations.
John L. Skolds. Mr. Skolds, age 52. Class II director with term expiring in 2005. Director since March 15, 2004. Executive Vice President of Exelon Corporation since February 1, 2004. Senior Vice President of Exelon and Exelon Generation Company, LLC and Chief Nuclear Officer from October 2000 through February 2004. Vice President of Unicom Corporation and ComEd, Chief Operating Officer, Nuclear Generation Group of ComEd from August 2000 through October 2000. President and Chief Operating Officer of South Carolina Electric and Gas from 1995 through August 2000.
Audit Committee
PECO is a controlled subsidiary of Exelon and does not have a separate audit committee. Instead, that function is fulfilled by the audit committee of the Exelon board of directors. See discussion of Exelon’s audit committee above.
Code of Ethics
Exelon’s Code of Business Conduct is the code of ethics that applies to PECO’s Chief Executive Officer, Chief Financial Officer, Corporate Controller, and other finance organization employees. The Code of Business Conduct is filed as Exhibit 14 to this report and is available on Exelon’s website at www.exeloncorp.com. The Code of Business Conduct will be made available, without charge, in print to any shareholder who requests such document from Katherine K. Combs, Vice President and Corporate Secretary, Exelon Corporation, P.O. Box 805398, Chicago, Illinois 60680-5398.
If any substantive amendments to the Code of Business Conduct are made or any waivers are granted, including any implicit waiver, from a provision of the Code of Business Conduct, to its Chief Executive Officer, Chief Financial Officer or Corporate Controller, PECO will disclose the nature of such amendment or waiver on Exelon’s website, www.exeloncorp.com, or in a report on Form 8-K.
Executive Officers
The information required by Item 10 relating to executive officers is set forth above in ITEM 1. Business—Executive Officers of the Registrants at December 31, 2004.
Directors
Generation operates as a limited liability company and has no board of directors.
Audit Committee
Generation is a controlled subsidiary of Exelon and does not have a separate audit committee. Instead, that function is fulfilled by the audit committee of the Exelon board of directors. See discussion of Exelon’s audit committee above.
416
Code of Ethics
Exelon’s Code of Business Conduct is the code of ethics that applies to Generation’s Chief Executive Officer, Chief Financial Officer, Corporate Controller, and other finance organization employees. The Code of Business Conduct is filed as Exhibit 14 to this report and is available on Exelon’s website at www.exeloncorp.com. The Code of Business Conduct will be made available, without charge, in print to any shareholder who requests such document from Katherine K. Combs, Vice President and Corporate Secretary, Exelon Corporation, P.O. Box 805398, Chicago, Illinois 60680-5398.
If any substantive amendments to the Code of Business Conduct are made or any waivers are granted, including any implicit waiver, from a provision of the Code of Business Conduct, to its Chief Executive Officer, Chief Financial Officer or Corporate Controller, Generation will disclose the nature of such amendment or waiver on Exelon’s website, www.exeloncorp.com, or in a report on Form 8-K.
| ITEM 11. | EXECUTIVE COMPENSATION |
Board Compensation
In December 2004, based upon a review conducted by a leading external compensation consultant, the Exelon board of directors approved an increase in directors’ compensation, effective January 1, 2005, to bring Exelon’s program in line with its peer group, which is composed of other utilities and general industrial companies. The increase also recognizes the increased time commitment required of the directors. With the approved increases, Exelon’s total compensation program for directors is between the 50th percentile and the mean of its peer group. Directors are paid in cash and deferred stock units as set forth below and are reimbursed for expenses, if any, for attending meetings.
| • | $35,000 Annual board retainer; |
| • | $1,500 Meeting fee or per diem fee; |
| • | $5,000 Annual retainer for committee chair; |
| • | $5,000 Annual retainer for members of the audit and Exelon generation oversight committees; and |
| • | $60,000 Annual grant of deferred stock units (dollar value). |
Directors are required to own at least 6,000 shares of Exelon common stock or deferred stock units within three years after their election to the Exelon board of directors.
Directors can elect to defer receiving their cash compensation until age 65 or until retirement from the Exelon board of directors. Deferred compensation is put into an unfunded account and credited with interest, equal to the amount that would have been earned had the compensation been invested in a variety of mutual funds, including one fund composed exclusively of shares of Exelon common stock. The deferred amounts and accrued interest are unfunded obligations of Exelon.
417
Executive Compensation
Summary Compensation Table
| Annual Compensation |
Long Term Compensation |
||||||||||||||||||||||
| Restricted Stock Award (See |
Number of Options (See |
Payouts (See |
All Other Compensation (See Notes |
||||||||||||||||||||
| Name and Principal |
Year |
Salary |
Bonus |
Other Annual Compensation (See Note 1) |
|||||||||||||||||||
| John W. Rowe Chairman, President & Chief Executive |
2004 2003 2002 |
$ |
1,241,346 1,185,289 1,104,000 |
$ |
1,675,000 1,400,000 1,550,000 |
$ |
357,431 342,341 185,121 |
$ |
1,480,279 2,733,360 1,909,985 |
400,000 350,000 400,000 |
$ |
1,666,322 — — |
$ |
2,153,432 191,851 184,189 |
| ||||||||
| Robert S. Shapard Executive Vice |
2004 2003 2002 |
|
531,538 512,404 96,154 |
|
501,830 411,362 83,609 |
|
2,268 2,727 72,344 |
|
404,218 634,530 837,742 |
80,000 72,000 40,000 |
|
426,400 — — |
|
513,859 64,319 5,148 |
| ||||||||
| John L. Skolds Executive Vice |
2004 2003 2002 |
|
571,154 530,673 492,423 |
|
462,239 393,837 499,800 |
|
3,472 2,762 121,510 |
|
739,118 634,530 416,724 |
80,000 80,000 90,000 |
|
426,400 — — |
|
514,883 64,276 62,363 |
| ||||||||
| Pamela B. Strobel Executive Vice |
2004 2003 2002 |
|
521,538 500,673 474,923 |
|
492,450 403,374 470,400 |
|
7,563 7,349 6,811 |
|
404,218 634,530 520,905 |
80,000 72,000 120,000 |
|
426,400 — — |
|
503,632 54,006 52,718 |
| ||||||||
| Randall E. Mehrberg Executive Vice |
2004 2003 2002 |
|
494,807 466,538 435,288 |
|
469,000 375,418 389,639 |
|
6,159 6,248 6,218 |
|
404,218 634,530 418,740 |
80,000 72,000 90,000 |
|
426,400 — — |
|
499,737 49,741 48,582 |
| ||||||||
| Oliver D. Kingsley, Jr. President & Chief |
2004 2003 2002 |
|
768,269 824,038 728,634 |
|
1,139,000 969,924 823,680 |
|
218,497 185,294 102,387 |
|
— 1,164,737 2,373,140 |
140,000 120,000 160,000 |
|
2,238,570 — — |
|
12,105,852 180,591 175,821 |
(6) | ||||||||
Notes to Summary Compensation Table
| 1. | The amounts shown under the column labeled “Other Annual Compensation” include perquisites and other personal benefits if the aggregate amount exceeds $50,000, and/or amounts reimbursed for the payment of taxes. For Mr. Rowe, the amount shown for 2004 includes $266,877 for personal use of corporate jet aircraft, and $26,040 for the reimbursement of taxes. For Mr. Kingsley, the amount shown for 2004 includes $149,631 for personal use of corporate jet aircraft and $15,408 for the reimbursement of taxes. For Messrs. Shapard, Skolds, Mehrberg and Ms. Strobel, the amount shown is for the reimbursement of taxes. |
| 2. | Exelon has a performance share award program under its Long Term Incentive Plan. Awards made prior to January 2005 were made in restricted stock that vested one-third upon the grant date and one-third upon each of the first and second anniversaries of the grant date. Beginning with awards made in January 2005 and for amounts vesting in 2005, if the participant has achieved 125% of the participant’s stock ownership requirement, the performance shares are settled approximately one-half in cash and one half in stock, with the same vesting schedule as before. For the 3 year performance period ended December 31, 2004, Mr. Rowe was granted 116,662 shares, Messrs. Shapard, Skolds, and Mehrberg and Ms. Strobel were each granted 29,853 shares, and Mr. Kingsley was granted 52,242 shares. These shares were valued at $42.85 per share. The amount of these grants that vested immediately is shown in the column headed “Long Term Compensation—Payouts”, while the amount that will be settled in stock and will vest on the first and second anniversaries of the award is shown in the column headed “Restricted Stock Award” and the amount that may be settled in stock or cash (depending on the participant’s stock ownership on the first and second anniversaries of the grant) is shown in the column headed “All Other Compensation.” |
| 3. | This column reports the value of the restricted stock portion of performance share awards as well as other restricted awards granted to individuals during the preceding year by the Compensation Committee and the Board of Directors in recognition |
418
| of specific accomplishments and/or significant increases in job responsibilities. Mr. Skolds received a grant of 20,000 shares on February 1, 2004, valued at $33.49 per share, which will all vest on February 1, 2009. During that time Mr. Skolds will receive the dividends payable on these shares. The number of shares and the share price has been adjusted to reflect the 2 for 1 stock split on May 5, 2004. |
| The named executive officers held the amounts of restricted shares, including unvested performance shares granted with respect to the 3-year performance periods ending December 31, 2003 and December 31, 2002, as shown in the following table. Unvested restricted and performance shares continue to receive dividends. The value of restricted shares and unvested performance shares shown below in columns [A] and [B] is based on the December 31, 2004 closing price of Exelon stock, $44.07 except for Mr. Kingsley’s shares which are valued at $39.62 as of October 31, 2004, the last day of his employment. |
| Columns [C], [D] and [E] in the following table include the amounts and value of restricted and unvested performance shares after the grant and vesting of performance shares on January 24, 2005. Column [C] shows the number of restricted shares and unvested performance shares that will be settled in stock, column [D] shows the number of performance shares that may be settled in cash or stock, depending on the participant’s stock ownership at the date of vesting, and column [E] shows the total value of the restricted shares and performance shares shown in columns [C] and [D] as of January 24, 2005, when the closing price of Exelon stock was $42.85. |
| [A] Number of |
[B] Value of |
Restricted & Unvested Performance Shares Remaining After Vesting on 01/24/2005 | ||||||||||
| [C] Number of |
[D] Number of |
[E] Total Value [C] + [D] as of | ||||||||||
| John W. Rowe |
85,380 | $ | 3,762,699 | 49,029 | 57,712 | $ | 4,573,852 | |||||
| Robert S. Shapard |
44,925 | 1,979,840 | 42,795 | 13,831 | 2,426,424 | |||||||
| John L. Skolds |
47,947 | 2,113,031 | 41,305 | 13,831 | 2,362,578 | |||||||
| Pamela B. Strobel |
20,934 | 922,577 | 12,795 | 13,831 | 1,140,924 | |||||||
| Randall E. Mehrberg |
19,437 | 856,595 | 12,795 | 13,831 | 1,140,924 | |||||||
| Oliver D. Kingsley, Jr. |
76,339 | 3,024,571 | — | — | — | |||||||
| 4. | Options granted prior to May 5, 2004 reflect the effect of a 2 for 1 stock split as of that date. |
| 5. | The amounts shown under the column labeled “Long Term Compensation—Payouts” represent the value of the one third of the total performance share award granted with respect to the three year performance period ending December 31, 2004, which vested immediately on the date of grant. Officers who had reached 125% of their stock ownership requirement received a portion of their vested shares in cash. Mr. Kingsley’s entire award vested upon grant because of his retirement. The amount of cash and the value of the vested shares of stock are as follows: |
| Cash Payout |
Value of Vested Shares | |||||
| John W. Rowe |
$ | 927,060 | $ | 739,262 | ||
| Robert S. Shapard |
— | 426,400 | ||||
| John L. Skolds |
224,277 | 202,123 | ||||
| Pamela B. Strobel |
224,277 | 202,123 | ||||
| Randall E. Mehrberg |
— | 426,400 | ||||
| Oliver D. Kingsley, Jr. |
1,177,518 | 1,061,052 | ||||
| 6. | The amounts shown under the column labeled “All Other Compensation” include company paid matching contributions to qualified and non-qualified savings plans, the amounts paid as premiums for term life insurance policies for certain executives (for Mr. Rowe, a term life policy and a whole life policy), and the value of the unvested two-thirds of the performance share award granted with respect to the three-year performance period ending December 31, 2004 which will be paid out in cash or stock at the time of vesting in 2006 and 2007, depending upon the participants’ stock ownership at that time. |
| Value of Company Contributions to Savings Plans |
Value of Unvested Performance Shares From Current Grant |
Company Paid Term Life Insurance Premiums |
Other Items | |||||||||
| John W. Rowe |
$ | 62,067 | $ | 1,852,366 | $ | 238,999 | $ | — | ||||
| Robert S. Shapard |
26,577 | 448,583 | 38,699 | — | ||||||||
| John L. Skolds |
28,558 | 448,583 | 37,742 | — | ||||||||
| Pamela B. Strobel |
26,077 | 448,583 | 28,972 | — | ||||||||
| Randall E. Mehrberg |
24,740 | 448,583 | 26,414 | — | ||||||||
| Oliver D. Kingsley, Jr. |
35,962 | — | 139,389 | 11,930,501 | ||||||||
| Pursuant to Mr. Kingsley’s employment agreement, he is entitled to an enhanced supplemental retirement benefit calculated as if he had 32 years of service. He elected to receive a lump sum of $10,430,500 which was paid to him as of his retirement date, in accordance with his previous payment election. |
419
| Also, Exelon will reimburse Mr. Kingsley up to $100,000 in any year for his daughter’s medical care expenses not otherwise covered by insurance for a 15 year period which commenced on the date of his retirement. The estimated value of this benefit is $1,500,000. |
| Pursuant to Mr. Kingsley’s employment agreement, his outstanding restricted shares and outstanding performance shares vested upon his retirement. Mr. Kingsley and Exelon entered into a share repurchase agreement through which Exelon purchased from Mr. Kingsley a total of 360,000 shares in two transactions at the weighted average market price over a ten-day period prior to the repurchase date. Exelon paid Mr. Kingsley $7,032,387 for 172,765 shares repurchased on November 17, 2004. Exelon also paid Mr. Kingsley $8,297,933 for 187,235 shares of Exelon common stock repurchased on February 9, 2005. The amounts paid to Mr. Kingsley for repurchase of his shares of Exelon common stock are not included in the above table. |
| Option Grants for 2004 | |||||||||||||
| Individual Grants | |||||||||||||
| Number of Securities Underlying Options Granted (See Note 1) |
Percentage of Total Options Granted to Employees in 2004 |
Exercise or Base Price ($/Share) |
Options Date |
Grant Date Value (See Note 2) | |||||||||
| John W. Rowe |
400,000 | 5.72 | % | $ | 32.54 | 01/15/2014 | $ | 2,228,000 | |||||
| Robert S. Shapard |
80,000 | 1.14 | % | 32.54 | 01/15/2014 | 445,600 | |||||||
| John L. Skolds |
80,000 | 1.14 | % | 32.54 | 01/15/2014 | 445,600 | |||||||
| Pamela B. Strobel |
80,000 | 1.14 | % | 32.54 | 01/15/2014 | 445,600 | |||||||
| Randall E. Mehrberg |
80,000 | 1.14 | % | 32.54 | 01/15/2014 | 445,600 | |||||||
| Oliver D. Kingsley, Jr. |
140,000 | 2.00 | % | 32.54 | 01/15/2014 | 779,800 | |||||||
| 1. | The number of options granted and the exercise or base price have been adjusted to reflect the 2 for 1 stock split which was effective on May 5, 2004. |
| 2. | The “grant date present values” indicated in the Option Grants Table are estimates based on the Black-Scholes option pricing model. Although executives risk forfeiting these options in some circumstances, these risks are not factored into the calculated values. The actual value of these options will be determined by the excess of the stock price over the exercise price of the option on the date that the options are exercised. There is no certainty that the value realized will be at or near the value estimated by the Black-Scholes option pricing model. |
| The assumptions used for the Black-Scholes model are as of the date of grants, January 26, 2004, and are as follows: Risk free interest rate: 3.26%; Volatility: 22.84%; Dividend Yield: 3.30%; and time of exercise: 5 years. |
| Option Exercises & Year End Value | |||||||||||||||
| As of December 31, 2004 (See Note 1) | |||||||||||||||
| Number of Shares Exercise |
Dollar Value Realized From Exercise |
Number of Securities Underlying Remaining Options |
Dollar Value of In-the-Money Options | ||||||||||||
| Exercisable |
Unexercisable |
Exercisable |
Unexercisable | ||||||||||||
| John W. Rowe (See Note 2) |
206,256 | $ | 3,853,893 | 1,894,111 | 795,833 | $ | 33,102,690 | $ | 12,417,056 | ||||||
| Robert S. Shapard |
— | — | 44,668 | 147,332 | 868,663 | 2,223,617 | |||||||||
| John L. Skolds |
— | — | 240,000 | 170,000 | 3,913,100 | 2,696,600 | |||||||||
| Pamela B. Strobel |
40,000 | 501,460 | 302,500 | 174,000 | 5,195,370 | 2,787,110 | |||||||||
| Randall E. Mehrberg |
78,000 | 755,010 | 126,000 | 164,000 | 1,489,320 | 2,581,010 | |||||||||
| Oliver D. Kingsley, Jr. (See Note 3) |
218,500 | 3,066,112 | 724,000 | — | 11,576,280 | — | |||||||||
| 1. | This table shows the number and value of exercisable and unexercisable stock options for the named executive officers during 2004. The value is determined using the closing market price of Exelon common stock on December 31, 2004, which was $44.07, less the exercise price of the options. All options whose exercise price exceeded the market price at the day of determination are valued at zero. For all data above, the number of shares and exercise prices have been adjusted to reflect the 2 for 1 stock split of May 5, 2004. |
| 2. | All options exercised by Mr. Rowe during 2004 were done in accordance with a Rule 10b5-1 Trading Plan, which was entered into on February 3, 2004 when Mr. Rowe was unaware of any material adverse information in regard to current and |
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| prospective operations of Exelon which had not been publicly disclosed. The dates of the sales were set at the time the Trading Plan was established. |
| 3. | All of Mr. Kingsley’s options vested upon his retirement. |
Long-Term Incentive Plans—Awards in Last Fiscal Year
| Number of Shares, Rights |
Performance Period until Maturation or Payout |
Estimated future payouts under non-stock price-based plans (See Note 2) | ||||||||
| Threshold (#) |
Target (#) |
Maximum (#) | ||||||||
| John W. Rowe |
N/A | 3 years | 33,000 | 66,000 | 132,000 | |||||
| Robert S. Shapard |
N/A | 3 years | 8,000 | 16,000 | 32,000 | |||||
| John L. Skolds |
N/A | 3 years | 8,000 | 16,000 | 32,000 | |||||
| Pamela B. Strobel |
N/A | 3 years | 8,000 | 16,000 | 32,000 | |||||
| Randall E. Mehrberg |
N/A | 3 years | 8,000 | 16,000 | 32,000 | |||||
| Oliver D. Kingsley, Jr. |
N/A | 3 years | 14,000 | 28,000 | 56,000 | |||||
| 1. | Exelon’s Long Term Performance Share Award program under the Long-Term Incentive Plan provides incentives to key executives in the form of restricted stock and cash. Awards are determined upon the successful completion of strategic goals designed to achieve long term business success and increased shareholder value. These goals include Exelon’s Total Shareholder Return (TSR) over the previous three years relative to established benchmarks including a peer group of companies listed on the Dow Jones Utility Index and the Standard & Poor’s 500 Index (weighted 70%) and a quantifiable cash savings goal aligned with The Exelon Way initiative (weighted 30%). Grants under the Long Term Performance Share Award Program for 2004 are reflected in the Summary Compensation Table. See note 2 to that table. |
| 2. | A target number of performance shares is established for each participant which is commensurate with the participant’s base salary. Based on measured performance as described above, participants may earn up to 200% of their target and may earn nothing if thresholds are not met. Shares listed under the Threshold, Target and Maximum columns have been adjusted to reflect the 2 for 1 stock split effective on May 5, 2004. |
ComEd, PECO and Generation
Board Compensation
Since the Merger Date, the boards of directors of ComEd and PECO have been comprised solely of employees of ComEd, PECO, Exelon or its subsidiaries. These individuals receive no additional compensation for serving as directors of ComEd or PECO.
Generation operates a limited liability company and has no board of directors.
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Executive Compensation
Summary Compensation Table
| Annual Compensation |
Long Term Compensation |
|||||||||||||||||||||||
| Name and Principal |
Year |
Salary |
Bonus |
Other Annual Compensation (See Note 1) |
Restricted Stock Award (See Notes 2 and 3) |
Number of Options (See Note 4) |
Payouts (See Notes 2 and 5) |
All Other Compensation (See Notes 2 and 6) |
||||||||||||||||
| Michael B. Bemis Former President, |
2004 2003 2002 |
$ |
93,480 414,687 121,195 |
$ |
— 292,346 121,347 |
$ |
5,771 177,294 — |
$ |
— 423,020 — |
$ |
— — — |
$ |
— — — |
$ |
333,526 1,616,569 31,813 |
| ||||||||
| John L. Skolds Executive Vice President, |
2004 2003 2002 |
|
571,154 530,673 492,423 |
|
462,239 393,837 499,800 |
|
3,472 2,762 121,510 |
|
739,118 634,530 416,724 |
|
80,000 80,000 90,000 |
|
426,400 — — |
|
514,883 64,276 62,363 |
| ||||||||
| John W. Rowe Chairman, President & |
2004 2003 2002 |
|
1,241,346 1,185,289 1,104,000 |
|
1,675,000 1,400,000 1,550,000 |
|
357,431 342,341 185,121 |
|
1,480,279 2,733,360 1,909,985 |
|
400,000 350,000 400,000 |
|
1,666,322 — — |
|
2,153,432 191,851 184,189 |
| ||||||||
| Robert S. Shapard Executive Vice President & |
2004 2003 2002 |
|
531,538 512,404 96,154 |
|
501,830 411,362 83,609 |
|
2,268 2,727 72,344 |
|
404,218 634,530 837,742 |
|
80,000 72,000 40,000 |
|
426,400 — — |
|
513,859 64,319 5,148 |
| ||||||||
| Ruth Ann M. Gillis Senior Vice President, |
2004 2003 2002 |
|
388,029 364,471 346,615 |
|
321,158 263,123 265,360 |
|
6,612 7,230 4,298 |
|
277,927 444,171 347,270 |
|
54,000 54,000 70,000 |
|
293,151 — — |
|
344,872 35,319 34,426 |
| ||||||||
| Frank M. Clark Executive Vice President, |
2004 2003 2002 |
|
402,596 377,404 352,500 |
|
275,367 227,880 274,827 |
|
8,355 9,427 5,981 |
|
626,927 444,171 604,470 |
|
54,000 54,000 70,000 |
|
293,151 — — |
|
377,067 67,432 66,187 |
| ||||||||
| Oliver D. Kingsley, Jr. President & Chief Operating |
2004 2003 2002 |
|
768,269 824,038 728,634 |
|
1,139,000 969,924 823,680 |
|
218,497 185,294 102,387 |
|
— 1,164,737 2,373,140 |
|
140,000 120,000 160,000 |
|
2,238,570 — — |
|
12,105,852 180,591 175,821 |
(6) | ||||||||
Notes to Summary Compensation Table
| 1. | The amounts shown under the column labeled “Other Annual Compensation” include perquisites and other personal benefits if the aggregate amount exceeds $50,000, and/or amounts reimbursed for the payment of taxes. For Mr. Rowe, the amount shown for 2004 includes $266,877 for personal use of corporate jet aircraft, and $26,040 for the reimbursement of taxes. For Mr. Kingsley, the amount shown for 2004 includes $149,631 for personal use of corporate jet aircraft and $15,408 for the reimbursement of taxes. For Messrs. Bemis, Skolds, Shapard, Clark and Ms. Gillis, the amount shown is for the reimbursement of taxes. |
| 2. | Exelon has a performance share award program under its Long Term Incentive Plan. Awards made prior to January 2005 were made in restricted stock that vested one-third upon the grant date and one-third upon each of the first and second anniversaries of the grant date. Beginning with awards made in January 2005 and for amounts vesting in 2005, if the participant has achieved 125% of the participant’s stock ownership requirement, the performance shares are settled approximately one-half in cash and one half in stock, with the same vesting schedule as before. For the 3 year performance |
422
| period ended December 31, 2004, Mr. Rowe was granted 116,662 shares, Messrs. Shapard and Skolds were each granted 29,853 shares, Ms. Gillis and Mr. Clark were each granted 20,524 shares Mr. Kingsley was granted 52,242 shares. These shares were valued at $42.85 per share. The amount of these grants that vested immediately is shown in the column headed “Long Term Compensation—Payouts”, while the amount that will be settled in stock and will vest on the first and second anniversaries of the award is shown in the column headed “Restricted Stock Awards” and the amount that may be settled in stock or cash (depending on the participant’s stock ownership on the first and second anniversaries of the grant) is shown in the column headed “All Other Compensation.” |
| 3. | This column reports the value of the restricted stock portion of performance share awards as well as other restricted awards granted to individuals during the preceding year by the Compensation Committee and the Board of Directors in recognition of specific accomplishments and/or significant increases in job responsibilities. Mr. Skolds received a grant of 20,000 shares on February 1, 2004, valued at $33.49 per share, which will all vest on February 1, 2009. Mr. Clark received a grant of 10,00 shares on July 26, 2004. 5,000 shares will vest on July 26, 2007 and 5,000 will vest on July 26, 2009. Dividends will be paid on these shares. The number of shares and the share price has been adjusted to reflect the 2 for 1 stock split on May 5, 2004. |
| The named executive officers held the amounts of restricted shares, including unvested performance shares granted with respect to the 3-year performance periods ending December 31, 2003 and December 31, 2002, as shown in the following table. Unvested restricted and performance shares continue to receive dividends. The value of restricted shares and unvested performance shares shown below in columns [A] and [B] is based on the December 31, 2004 closing price of Exelon stock, $44.07 except for Mr. Kingsley’s shares which are valued at $39.62 as of October 31, 2004 and Mr. Bemis’s shares which are valued at $33.49 as of January 31, 2004 respectively, the last day of employment for each officer. Mr. Bemis’s share total and value have been adjusted to reflect the 2 for 1 stock split of May 5, 2004. |
| Columns [C], [D] and [E] in the following table include the amounts and value of restricted and unvested performance shares after the grant and vesting of performance shares on January 24, 2005. Column [C] shows the number of restricted shares and unvested performance shares that will be settled in stock, column [D] shows the number of performance shares that may be settled in cash or stock, depending on the participant’s stock ownership at the date of vesting, and column [E] shows the total value of the restricted shares and performance shares shown in columns [C] and [D] as of January 24, 2005, when the closing price of Exelon stock was $42.85. |
| Restricted & Unvested Performance Shares Remaining After Vesting on 01/24/2005 | ||||||||||||
| [A] Number
of Performance 12/31/2004 |
[B] Value of Restricted and Performance 12/31/2004 |
[C] Number of Shares That Will Be Settled in Stock |
[D] Number of Shares That May Be Settled in Cash or Stock |
[E] Total Shares in [C] + [D] as of 01/24/2005 | ||||||||
| Michael B. Bemis |
8,666 | $ | 290,224 | — | — | $ | — | |||||
| John L. Skolds |
47,947 | 2,113,031 | 41,305 | 13,831 | 2,362,578 | |||||||
| John W. Rowe |
85,380 | 3,762,699 | 49,029 | 57,712 | 4,573,852 | |||||||
| Robert S. Shapard |
44,925 | 1,979,840 | 42,795 | 13,831 | 2,426,424 | |||||||
| Ruth Ann M. Gillis |
14,405 | 634,807 | 8,840 | 9,550 | 788,012 | |||||||
| Frank M. Clark |
34,405 | 1,516,207 | 28,840 | 9,550 | 1,645,012 | |||||||
| Oliver D. Kingsley, Jr. |
76,339 | 3,024,571 | — | — | — | |||||||
| 4. | Options granted prior to May 5, 2004 reflect the effect of a 2 for 1 stock split as of that date. |
423
| 5. | The amounts shown under the column labeled “Long Term Compensation—Payouts” represent the value of the one third of the total performance share award granted with respect to the three year performance period ending December 31, 2004, which vested immediately on the date of grant. Officers who had reached 125% of their stock ownership requirement received a portion of their vested shares in cash. Mr. Kingsley’s entire award vested upon grant because of his retirement. The amount of cash and the value of the vested shares of stock are as follows: |
| Cash Payout |
Value of Vested Shares | |||||
| Michael B. Bemis |
$ | — | $ | — | ||
| John L. Skolds |
224,277 | 202,123 | ||||
| John W. Rowe |
927,060 | 739,262 | ||||
| Robert S. Shapard |
— | 426,400 | ||||
| Ruth Ann M. Gillis |
154,217 | 138,934 | ||||
| Frank M. Clark |
154,217 | 138,934 | ||||
| Oliver D. Kingsley, Jr. |
1,177,518 | 1,061,052 | ||||
| 6. | The amounts shown under the column labeled “All Other Compensation” include company paid matching contributions to qualified and non-qualified savings plans, the amounts paid as premiums for term life insurance policies for certain executives (for Mr. Rowe, a term life policy and a whole life policy), and the value of the unvested two-thirds of the performance share award granted with respect to the three-year performance period ending December 31, 2004 which will be paid out in cash or stock at the time of vesting in 2006 and 2007, depending upon the participants’ stock ownership at that time. |
| Value of Company Contributions |
Value of Unvested Performance Shares From Current |
Company Paid Term Life Insurance Premiums |
Other Items | |||||||||
| Michael B. Bemis |
$ | 3,029 | $ | — | $ | 44,152 | $ | 286,345 | ||||
| John L. Skolds |
28,558 | 448,583 | 37,742 | — | ||||||||
| John W. Rowe |
62,067 | 1,852,366 | 238,999 | — | ||||||||
| Robert S. Shapard |
26,577 | 448,583 | 38,699 | — | ||||||||
| Ruth Ann M. Gillis |
19,402 | 308,375 | 17,095 | — | ||||||||
| Frank M. Clark |
20,130 | 308,375 | 48,562 | — | ||||||||
| Oliver D. Kingsley, Jr. |
35,962 | — | 139,389 | 11,930,501 | ||||||||
| Pursuant to Mr. Kingsley’s employment agreement, he is entitled to an enhanced supplemental retirement benefit calculated as if he had 32 years of service. He elected to receive a lump sum of $10,430,500 which was paid to him as of his retirement date, in accordance with his previous payment election. |
| Also, Exelon will reimburse Mr. Kingsley up to $100,000 in any year for his daughter’s medical care expenses not otherwise covered by insurance for a 15 year period which commenced on the date of his retirement. The estimated value of this benefit is $1,500,000. |
| Pursuant to Mr. Kingsley’s employment agreement, his outstanding restricted shares and outstanding performance shares vested upon his retirement. Mr. Kingsley and Exelon entered into a share repurchase agreement through which Exelon purchased from Mr. Kingsley a total of 360,000 shares in two transactions at the weighted average market price over a ten-day period prior to the repurchase date. Exelon paid Mr. Kingsley $7,032,387 for 172,765 shares repurchased on November 17, 2004. Exelon also paid Mr. Kingsley $8,297,933 for 187,235 shares of Exelon common repurchased on February 9, 2005. The amounts paid to Mr. Kingsley for repurchase of his shares of Exelon common stock are not included in the above table. |
| 7. | Mr. Bemis received a sign-on bonus when hired in August 2002, payable in January 2003. As reported in the 2004 Form 10-K, in connection with his resignation as of February 1, 2004, Mr. Bemis received a lump sum severance payment of $450,000 and a fully vested award of 15,000 shares, worth $1,004,700, representing final payment of his special incentive award program with respect to the Sithe Transaction, and $9,936 to terminate an apartment lease. In 2004, Mr. Bemis was entitled to coverage under the term life insurance policy for certain executives for the full year and also received a distribution from his deferred compensation account in accordance with his previous payment election. |
424
| Option Grants for 2004 | |||||||||||||
| Individual Grants | |||||||||||||
| Number of Securities Underlying Options Granted (See Note 1) |
Percentage of Total Options Granted to Employees in 2004 |
Exercise or Base Price (See Note 1) |
Options Date |
Grant Date Present Value (See Note 2) | |||||||||
| Michael B. Bemis |
— | — | $ | — | — | $ | — | ||||||
| John L. Skolds |
80,000 | 1.14 | % | 32.54 | 01/15/2014 | 445,600 | |||||||
| John W. Rowe |
400,000 | 5.72 | % | 32.54 | 01/15/2014 | 2,228,000 | |||||||
| Robert S. Shapard |
80,000 | 1.14 | % | 32.54 | 01/15/2014 | 445,600 | |||||||
| Ruth Ann M. Gillis |
54,000 | 0.77 | % | 32.54 | 01/15/2014 | 300,780 | |||||||
| Frank M. Clark |
54,000 | 0.77 | % | 32.54 | 01/15/2014 | 300,780 | |||||||
| Oliver D. Kingsley, Jr. |
140,000 | 2.00 | % | 32.54 | 01/15/2014 | 779,800 | |||||||
| 1. | The number of options granted and the exercise or base price have been adjusted to reflect the 2 for 1 stock split which was effective on May 5, 2004. |
| 2. | The “grant date present values” indicated in the Option Grants Table are estimates based on the Black-Scholes option pricing model. Although executives risk forfeiting these options in some circumstances, these risks are not factored into the calculated values. The actual value of these options will be determined by the excess of the stock price over the exercise price of the option on the date that the options are exercised. There is no certainty that the value realized will be at or near the value estimated by the Black-Scholes option pricing model. |
| The assumptions used for the Black-Scholes model are as of the date of grants, January 26, 2004, and are as follows: Risk free interest rate: 3.26%; Volatility: 22.84%; Dividend Yield: 3.30%; and time of exercise: 5 years. |
| Option Exercises & Year End Value | |||||||||||||||
| As of December 31, 2004 (See Note 1) | |||||||||||||||
| Number of Shares Acquired by Exercise |
Dollar Value Realized From Exercise |
Number of Securities Underlying Remaining Options |
Dollar Value of In-the-Money Options | ||||||||||||
| Exercisable |
Unexercisable |
Exercisable |
Unexercisable | ||||||||||||
| Michael B. Bemis |
— | $ | — | — | — | $ | — | $ | — | ||||||
| John L. Skolds |
— | — | 240,000 | 170,000 | 3,913,100 | 2,696,600 | |||||||||
| John W. Rowe (See Note 2) |
206,256 | 3,853,893 | 1,894,111 | 795,833 | 33,102,690 | 12,417,056 | |||||||||
| Robert S. Shapard |
— | — | 44,668 | 147,332 | 868,663 | 2,223,617 | |||||||||
| Ruth Ann M. Gillis |
28,500 | 405,319 | 281,167 | 117,833 | 5,392,180 | 1,883,746 | |||||||||
| Frank M. Clark |
— | — | 162,833 | 117,833 | 2,545,291 | 1,883,746 | |||||||||
| Oliver D. Kingsley, Jr. (See Note 3) |
218,500 | 3,066,112 | 724,000 | — | 11,576,280 | — | |||||||||
| 1. | This table shows the number and value of exercisable and unexercisable stock options for the named executive officers during 2004. The value is determined using the closing market price of Exelon common stock on December 31, 2004, which was $44.07, less the exercise price of the options. All options whose exercise price exceeded the market price at the day of determination are valued at zero. For all data above, the number of shares and exercise prices have been adjusted to reflect the 2 for 1 stock split of May 5, 2004. |
| 2. | All options exercised by Mr. Rowe during 2004 were done in accordance with a Rule 10b5-1 Trading Plan, which was entered into on February 3, 2004 when Mr. Rowe was unaware of any material adverse information in regard to current and prospective operations of Exelon which had not been publicly disclosed. The dates of the sales were set at the time the Trading Plan was established. |
| 3. | All of Mr. Kingsley’s options vested upon his retirement. |
425
Long-Term Incentive Plans—Awards in Last Fiscal Year
| Number (See Note 1) |
Performance Period until Maturation or Payout |
Estimated future payouts under non-stock price-based plans | ||||||||
| Threshold |
Target |
Maximum | ||||||||
| Michael B. Bemis |
N/A | 3 years | — | — | — | |||||
| John L. Skolds |
N/A | 3 years | 8,000 | 16,000 | 32,000 | |||||
| John W. Rowe |
N/A | 3 years | 33,000 | 66,000 | 132,000 | |||||
| Robert S. Shapard |
N/A | 3 years | 8,000 | 16,000 | 32,000 | |||||
| Ruth Ann M. Gillis |
N/A | 3 years | 5,500 | 11,000 | 22,000 | |||||
| Frank M. Clark |
N/A | 3 years | 5,500 | 11,000 | 22,000 | |||||
| Oliver D. Kingsley, Jr. |
N/A | 3 years | 14,000 | 28,000 | 56,000 | |||||
| 1. | Exelon’s Long Term Performance Share Award program under the Long-Term Incentive Plan provides incentives to key executives in the form of restricted stock and cash. Awards are determined upon the successful completion of strategic goals designed to achieve long term business success and increased shareholder value. These goals include Exelon’s Total Shareholder Return (TSR) over the previous three years relative to established benchmarks including a peer group of companies listed on the Dow Jones Utility Index and the Standard & Poor’s 500 Index (weighted 70%) and a quantifiable cash savings goal aligned with The Exelon Way initiative (weighted 30%). Grants under the Long Term Performance Share Award Program for 2004 are reflected in the Summary Compensation Table. See note 2 to that table. |
| 2. | A target number of performance shares is established for each participant which is commensurate with the participant’s base salary. Based on measured performance as described above, participants may earn up to 200% of their target and may earn nothing if thresholds are not met. Shares listed under the Threshold, Target and Maximum columns have been adjusted to reflect the 2 for 1 stock split effective on May 5, 2004. |
426
Summary Compensation Table
| Annual Compensation |
Long Term Compensation |
||||||||||||||||||||||
| Name and Principal Position |
Year |
Salary |
Bonus |
Other Annual |
Restricted Stock Award (See |
Number of Options (See Note 4) |
Payouts (See |
All Other (See Notes 2 and 6) |
|||||||||||||||
| Michael B. Bemis |
2004 | $ | 93,480 | $ | — | $ | 5,771 | $ | — | — | $ | — | $ | 333,526 | |||||||||
| Former President, Exelon Energy Delivery, and CEO, PECO Energy (See Note 7) |
2003 2002 |
|
414,687 121,195 |
|
292,346 121,347 |
|
177,294 — |
|
423,020 — |
— — |
|
— — |
|
1,616,569 31,813 |
| ||||||||
| John L. Skolds |
2004 | 571,154 | 462,239 | 3,472 | 739,118 | 80,000 | 426,400 | 514,883 | |||||||||||||||
| Executive Vice President, Exelon Corp. |
2003 2002 |
|
530,673 492,423 |
|
393,837 499,800 |
|
2,762 121,510 |
|
634,530 416,724 |
80,000 90,000 |
|
— — |
|
64,276 62,363 |
| ||||||||
| John W. Rowe |
2004 | 1,241,346 | 1,675,000 | 357,431 | 1,480,279 | 400,000 | 1,666,322 | 2,153,432 | |||||||||||||||
| Chairman, President & Chief Executive Officer, Exelon Corp. |
2003 2002 |
|
1,185,289 1,104,000 |
|
1,400,000 1,550,000 |
|
342,341 185,121 |
|
2,733,360 1,909,985 |
350,000 400,000 |
|
— — |
|
191,851 184,189 |
| ||||||||
| Robert S. Shapard |
2004 | 531,538 | 501,830 | 2,268 | 404,218 | 80,000 | 426,400 | 513,859 | |||||||||||||||
| Executive Vice President & Chief Financial Officer, Exelon Corp. |
2003 2002 |
|
512,404 96,154 |
|
411,362 83,609 |
|
2,727 72,344 |
|
634,530 837,742 |
72,000 40,000 |
|
— — |
|
64,319 5,148 |
| ||||||||
| Denis P. O’Brien |
2004 | 344,498 | 238,873 | 5,570 | 202,106 | 40,000 | 213,193 | 260,141 | |||||||||||||||
| President, PECO Energy Co. |
2003 2002 |
|
296,154 208,896 |
|
194,897 186,491 |
|
450 3 |
|
285,896 129,681 |
30,000 27,000 |
|
— — |
|
33,462 29,099 |
| ||||||||
| J. Barry Mitchell |
2004 | 343,058 | 223,110 | 3,269 | 176,853 | 30,000 | 186,555 | 250,532 | |||||||||||||||
| Senior Vice President, Exelon Corp.; CFO & Treasurer, PECO |
2003 2002 |
|
305,288 263,635 |
|
164,317 164,847 |
|
2,884 1,028 |
|
222,053 520,417 |
30,000 30,000 |
|
— — |
|
52,386 43,429 |
| ||||||||
| Oliver D. Kingsley, Jr. |
2004 | 768,269 | 1,139,000 | 218,497 | — | 140,000 | 2,238,570 | 12,105,852 | (6) | ||||||||||||||
| President & Chief Operating Officer, Exelon Corp. through 10/31/2004 |
2003 2002 |
|
824,038 728,634 |
|
969,924 823,680 |
|
185,294 102,387 |
|
1,164,737 2,373,140 |
120,000 160,000 |
|
— — |
|
180,591 175,821 |
| ||||||||
427
Notes to Summary Compensation Table
| 1. | The amounts shown under the column labeled “Other Annual Compensation” include perquisites and other personal benefits if the aggregate amount exceeds $50,000, and/or amounts reimbursed for the payment of taxes. For Mr. Rowe, the amount shown for 2004 includes $266,877 for personal use of corporate jet aircraft, and $26,040 for the reimbursement of taxes. For Mr. Kingsley, the amount shown for 2004 includes $149,631 for personal use of corporate jet aircraft and $15,408 for the reimbursement of taxes. For Messrs. Bemis, Skolds, Shapard, O’Brien and Mitchell the amount shown is for the reimbursement of taxes. |
| 2. | Exelon has a performance share award program under its Long Term Incentive Plan. Awards made prior to January 2005 were made in restricted stock that vested one-third upon the grant date and one-third upon each of the first and second anniversaries of the grant date. Beginning with awards made in January 2005 and for amounts vesting in 2005, if the participant has achieved 125% of the participant’s stock ownership requirement, the performance shares are settled approximately one-half in cash and one half in stock, with the same vesting schedule as before. For the 3 year performance period ended December 31, 2004, Mr. Rowe was granted 116,662 shares, Messrs. Shapard and Skolds were each granted 29,853 shares, Mr. O’Brien was granted 14,926 shares, Mr. Mitchell was granted 13,061 shares and Mr. Kingsley was granted 52,242 shares. These shares were valued at $42.85 per share. The amount of these grants that vested immediately is shown in the column headed “Long Term Compensation—Payouts”, while the amount that will be settled in stock and will vest on the first and second anniversaries of the award is shown in the column headed “Restricted Stock Awards” and the amount that may be settled in stock or cash (depending on the participant’s stock ownership on the first and second anniversaries of the grant) is shown in the column headed “All Other Compensation.” |
| 3. | This column reports the value of the restricted stock portion of performance share awards as well as other restricted awards granted to individuals during the preceding year by the Compensation Committee and the Board of Directors in recognition of specific accomplishments and/or significant increases in job responsibilities. Mr. Skolds received a grant of 20,000 shares on February 1, 2004, valued at $33.49 per share, which will all vest on February 1, 2009. Dividends will be paid on these shares. The number of shares and the share price has been adjusted to reflect the 2 for 1 stock split on May 5, 2004. |
| The named executive officers held the amounts of restricted shares, including unvested performance shares granted with respect to the 3-year performance periods ending December 31, 2003 and December 31, 2002, as shown in the following table. Unvested restricted and performance shares continue to receive dividends. The value of restricted shares and unvested performance shares shown below in columns [A] and [B] is based on the December 31, 2004 closing price of Exelon stock, $44.07 except for Mr. Kingsley’s shares which are valued at $39.62 as of October 31, 2004 and Mr. Bemis’s shares which are valued at $33.49 as of January 31, 2004 respectively, the last day of employment for each officer. Mr. Bemis’s share total and value have been adjusted to reflect the 2 for 1 stock split of May 5, 2004. |
| Columns [C], [D] and [E] in the following table include the amounts and value of restricted and unvested performance shares after the grant and vesting of performance shares on January 24, 2005. Column [C] shows the number of restricted shares and unvested performance shares that will be settled in stock, column [D] shows the number of performance shares that may be settled in cash or stock, depending on the participant’s stock ownership at the date of vesting, and column [E] shows the total value of the restricted shares and performance shares shown in columns [C] and [D] as of January 24, 2005, when the closing price of Exelon stock was $42.85. |
| Restricted & Unvested Performance Shares Remaining After Vesting on 01/24/2005 | ||||||||||||
| [A] Number
of |
[B] Value of and Unvested |
[C] Number of |
[D] Number of |
[E] Total Value of [C] + [D] as of 01/24/2005 | ||||||||
| Michael B. Bemis |
8,666 | $ | 290,224 | — | — | $ | — | |||||
| John L. Skolds |
47,947 | 2,113,031 | 41,305 | 13,831 | 2,362,578 | |||||||
| John W. Rowe |
85,380 | 3,762,699 | 49,029 | 57,712 | 4,573,852 | |||||||
| Robert S. Shapard |
44,925 | 1,979,840 | 42,795 | 13,831 | 2,426,424 | |||||||
| Denis P. O’Brien |
7,923 | 349,167 | 6,231 | 6,749 | 556,193 | |||||||
| J. Barry Mitchell |
21,503 | 947,632 | 20,304 | 5,757 | 1,116,714 | |||||||
| Oliver D. Kingsley, Jr. |
76,339 | 3,024,571 | — | — | — | |||||||
| 4. | Options granted prior to May 5, 2004 reflect the effect of a 2 for 1 stock split as of that date. |
| 5. | The amounts shown under the column labeled “Long Term Compensation—Payouts” represent the value of the one third of the total performance share award granted with respect to the three year performance period ending December 31, 2004, which vested immediately on the date of grant. Officers who had reached 125% of their stock ownership requirement received a portion of their vested shares in cash. Mr. Kingsley’s entire award vested upon grant because of his retirement. The amount of cash and the value of the vested shares of stock are as follows: |
428
| Cash Payout |
Value of Vested Shares | |||||
| Michael B. Bemis |
$ | — | $ | — | ||
| John L. Skolds |
224,277 | 202,123 | ||||
| John W. Rowe |
927,060 | 739,262 | ||||
| Robert S. Shapard |
— | 426,400 | ||||
| Denis P. O’Brien |
— | 213,193 | ||||
| J. Barry Mitchell |
98,127 | 88,428 | ||||
| Oliver D. Kingsley, Jr. |
1,177,518 | 1,061,052 | ||||
| 6. | The amounts shown under the column labeled “All Other Compensation” include company paid matching contributions to qualified and non-qualified savings plans along with the value of the unvested two-thirds of the performance share award granted with respect to the three-year performance period ending December 31, 2004 which will be paid out in cash or stock at the time of vesting in 2006 and 2007, depending upon the participants’ stock ownership at that time. |
| Value of Company Contributions to Savings Plans |
Value of Unvested Performance Shares From Current Grant |
Company Paid Term Life Insurance Premiums |
Other Items | |||||||||
| Michael B. Bemis |
$ | 3,029 | $ | — | $ | 44,152 | $ | 286,345 | ||||
| John L. Skolds |
28,558 | 448,583 | 37,742 | — | ||||||||
| John W. Rowe |
62,067 | 1,852,366 | 238,999 | — | ||||||||
| Robert S. Shapard |
26,577 | 448,583 | 38,699 | — | ||||||||
| Denis P. O’Brien |
17,207 | 224,280 | 18,654 | — | ||||||||
| J. Barry Mitchell |
17,153 | 196,257 | 37,122 | — | ||||||||
| Oliver D. Kingsley, Jr. |
35,962 | — | 139,389 | 11,930,501 | ||||||||
| Pursuant to Mr. Kingsley’s employment agreement, he is entitled to an enhanced supplemental retirement benefit calculated as if he had 32 years of service. He elected to receive a lump sum of $10,430,501 which was paid to him as of his retirement date, in accordance with his previous payment election. |
| Also, Exelon will reimburse Mr. Kingsley up to $100,000 in any year for his daughter’s medical care expenses not otherwise covered by insurance for a 15 year period which commenced on the date of his retirement. The estimated value of this benefit is $1,500,000. |
| Pursuant to Mr. Kingsley’s employment agreement, his outstanding restricted shares and outstanding performance shares vested upon his retirement. Mr. Kingsley and Exelon entered into a share repurchase agreement through which Exelon purchased from Mr. Kingsley a total of 360,000 shares in two transactions at the weighted average market price over a ten-day period prior to the repurchase date. Exelon paid Mr. Kingsley $7,032,387 for 172,765 shares repurchased on November 17, 2004. Exelon also paid Mr. Kingsley $8,297,933 for 187,235 shares of Exelon common stock repurchased on February 9, 2005. The amounts paid to Mr. Kingsley for repurchase of his shares of Exelon common stock are not included in the above table. |
| 7. | Mr. Bemis received a sign-on bonus when hired in August 2002, payable in January 2003. As reported in the 2004 Information Statement, in connection with his resignation as of February 1, 2004, Mr. Bemis received a lump sum severance payment of $450,000 and a fully vested award of 15,000 shares, worth $1,004,700, representing final payment of his special incentive award program with respect to the Sithe Transaction, and $9,936 to terminate an apartment lease. In 2004, Mr. Bemis was entitled to coverage under the term life insurance policy for certain executives for the full year and also received a distribution from his deferred compensation account in accordance with his previous payment election. |
429
| Option Grants for 2004
| |||||||||||||
| Individual Grants | |||||||||||||
| Number of Securities Underlying Options Granted (See Note 1) |
Percentage of Total Options |
Exercise or Base Price |
Options Date |
Grant Date Value (See Note 2) | |||||||||
| Michael B. Bemis |
— | — | $ | — | — | $ | — | ||||||
| John L. Skolds |
80,000 | 1.14 | % | 32.54 | 01/15/2014 | 445,600 | |||||||
| John W. Rowe |
400,000 | 5.72 | % | 32.54 | 01/15/2014 | 2,228,000 | |||||||
| Robert S. Shapard |
80,000 | 1.14 | % | 32.54 | 01/15/2014 | 445,600 | |||||||
| Denis P. O’Brien |
40,000 | 0.57 | % | 32.54 | 01/15/2014 | 222,800 | |||||||
| J. Barry Mitchell |
30,000 | 0.43 | % | 32.54 | 01/15/2014 | 167,100 | |||||||
| Oliver D. Kingsley, Jr. |
140,000 | 2.00 | % | 32.54 | 01/15/2014 | 779,800 | |||||||
| 1. | The number of options granted and the exercise or base price have been adjusted to reflect the 2 for 1 stock split which was effective on May 5, 2004. |
| 2. | The “grant date present values” indicated in the Option Grants Table are estimates based on the Black-Scholes option pricing model. Although executives risk forfeiting these options in some circumstances, these risks are not factored into the calculated values. The actual value of these options will be determined by the excess of the stock price over the exercise price of the option on the date that the options are exercised. There is no certainty that the value realized will be at or near the value estimated by the Black-Scholes option pricing model. |
| The assumptions used for the Black-Scholes model are as of the date of grants, January 26, 2004, and are as follows: Risk free interest rate: 3.26%; Volatility: 22.84%; Dividend Yield: 3.30%; and time of exercise: 5 years. |
| Option Exercises & Year End Value
| |||||||||||||||
| As of December 31, 2004 (See Note 1) | |||||||||||||||
| Number of Shares Acquired by Exercise |
Dollar Value From Exercise |
Number of Securities Underlying Remaining Options |
Dollar Value of In-the-Money Options | ||||||||||||
| Exercisable |
Unexercisable |
Exercisable |
Unexercisable | ||||||||||||
| Michael B. Bemis |
— | $ | — | — | — | $ | — | $ | — | ||||||
| John L. Skolds |
— | — | 240,000 | 170,000 | 3,913,100 | 2,696,600 | |||||||||
| John W. Rowe (See Note 2) |
206,256 | $ | 3,853,893 | 1,894,111 | 795,833 | 33,102,690 | 12,417,056 | ||||||||
| Robert S. Shapard |
— | — | 44,668 | 147,332 | 868,663 | 2,223,617 | |||||||||
| Denis P. O’Brien |
— | — | 98,500 | 71,500 | 2,219,422 | 1,080,153 | |||||||||
| J. Barry Mitchell |
64,000 | $ | 1,249,600 | 100,100 | 62,500 | 2,130,414 | 985,463 | ||||||||
| Oliver D. Kingsley, Jr. (See Note 3) |
218,500 | $ | 3,066,112 | 724,000 | — | 11,576,280 | — | ||||||||
| 1. | This table shows the number and value of exercisable and unexercisable stock options for the named executive officers during 2004. The value is determined using the closing market price of Exelon common stock on December 31, 2004, which was $44.07, less the exercise price of the options. All options whose exercise price exceeded the market price at the day of determination are valued at zero. For all data above, the number of shares and exercise prices have been adjusted to reflect the 2 for 1 stock split of May 5, 2004. |
| 2. | All options exercised by Mr. Rowe during 2004 were done in accordance with a Rule 10b5-1 Trading Plan, which was entered into on February 3, 2004 when Mr. Rowe was unaware of any material adverse information in regard to current and prospective operations of Exelon which had not been publicly disclosed. The dates of the sales were set at the time the Trading Plan was established. |
| 3. | All of Mr. Kingsley’s options vested upon his retirement. |
430
| Long-Term Incentive Plans—Awards in Last Fiscal Year
| ||||||||||
| Number of Shares, Units or Other Rights (See Note 1) |
Performance |
Estimated future payouts under non-stock price-based plans (See Note 2) | ||||||||
| Threshold |
Target |
Maximum | ||||||||
| Michael B. Bemis |
N/A | 3 years | N/A | N/A | N/A | |||||
| John L. Skolds |
N/A | 3 years | 8,000 | 16,000 | 32,000 | |||||
| John W. Rowe |
N/A | 3 years | 33,000 | 66,000 | 132,000 | |||||
| Robert S. Shapard |
N/A | 3 years | 8,000 | 16,000 | 32,000 | |||||
| Denis P. O’Brien |
N/A | 3 years | 4,000 | 8,000 | 16,000 | |||||
| J. Barry Mitchell |
N/A | 3 years | 3,500 | 7,000 | 14,000 | |||||
| Oliver D. Kingsley, Jr. |
N/A | 3 years | 14,000 | 28,000 | 56,000 | |||||
| 1. | Exelon’s Long Term Performance Share Award program under the Long-Term Incentive Plan provides incentives to key executives in the form of restricted stock and cash. Awards are determined upon the successful completion of strategic goals designed to achieve long term business success and increased shareholder value. These goals include Exelon’s Total Shareholder Return (TSR) over the previous three years relative to established benchmarks including a peer group of companies listed on the Dow Jones Utility Index and the Standard & Poor’s 500 Index (weighted 70%) and a quantifiable cash savings goal aligned with The Exelon Way initiative (weighted 30%). Grants under the Long Term Performance Share Award Program for 2004 are reflected in the Summary Compensation Table. See note 2 to that table. |
| 2. | A target number of performance shares is established for each participant which is commensurate with the participant’s base salary. Based on measured performance as described above, participants may earn up to 200% of their target and may earn nothing if thresholds are not met. Shares listed under the Threshold, Target and Maximum columns have been adjusted to reflect the 2 for 1 stock split effective on May 5, 2004. |
431
Summary Compensation Table
| Year |
Annual Compensation |
Long Term Compensation |
All Other Compensation (See Notes 2 and 6) |
|||||||||||||||||||||
| Name and Principal Position |
Salary |
Bonus |
Other Annual |
Restricted Award (See Notes 2 |
Number of Options |
Payouts (See Notes 2 |
||||||||||||||||||
| Oliver D. Kingsley, Jr. |
2004 | $ | 768,269 | $ | 1,139,000 | $ | 218,497 | $ | — | $ | 140,000 | $ | 2,238,570 | $ | 12,105,852 | (6) | ||||||||
| President & Chief Operating Officer, Exelon Corp. through 10/31/2004 |
2003 2002 |
|
824,038 728,634 |
|
969,924 823,680 |
|
185,294 102,387 |
|
1,164,737 2,373,140 |
|
120,000 160,000 |
|
— — |
|
180,591 175,821 |
| ||||||||
| John F. Young |
2004 | 435,807 | 505,680 | 5,066 | 330,695 | 54,000 | 348,842 | 415,106 | ||||||||||||||||
| Executive Vice President, Exelon Corp.; President, Genco |
2003 2002 |
|
311,923 — |
|
214,159 — |
|
144,943 — |
|
494,236 — |
|
30,000 — |
|
— — |
|
185,973 — |
| ||||||||
| John W. Rowe |
2004 | 1,241,346 | 1,675,000 | 357,431 | 1,480,279 | 400,000 | 1,666,322 | 2,153,432 | ||||||||||||||||
| Chairman, President & Chief Executive Officer, Exelon Corp. |
2003 2002 |
|
1,185,289 1,104,000 |
|
1,400,000 1,550,000 |
|
342,341 185,121 |
|
2,733,360 1,909,985 |
|
350,000 400,000 |
|
— — |
|
191,851 184,189 |
| ||||||||
| Robert S. Shapard |
2004 | 531,538 | 501,830 | 2,268 | 404,218 | 80,000 | 426,400 | 513,859 | ||||||||||||||||
| Executive Vice President & Chief Financial Officer, Exelon Corp. |
2003 2002 |
|
512,404 96,154 |
|
411,362 83,609 |
|
2,727 72,344 |
|
634,530 837,742 |
|
72,000 40,000 |
|
— — |
|
64,319 5,148 |
| ||||||||
| Christopher M. Crane |
2004 | 458,269 | 420,654 | 1,738 | 961,827 | 54,000 | 293,151 | 348,425 | ||||||||||||||||
| Senior Vice President, Exelon Corp. |
2003 2002 |
|
387,788 360,769 |
|
219,489 325,078 |
|
277 0 |
|
317,265 277,816 |
|
40,000 70,000 |
|
— — |
|
36,525 62,174 |
| ||||||||
| Ian P. McLean |
2004 | 427,438 | 407,705 | 3,076 | 404,218 | 80,000 | 426,400 | 506,844 | ||||||||||||||||
| Executive Vice President, Exelon Corp. |
2003 2002 |
|
411,827 385,462 |
|
273,607 187,176 |
|
9,657 15,842 |
|
634,530 — |
|
72,000 99,288 |
|
— 1,000,000 |
|
57,511 40,766 |
| ||||||||
| John L. Skolds |
2004 | 571,154 | 462,239 | 3,472 | 739,118 | 80,000 | 426,400 | 514,883 | ||||||||||||||||
| Executive Vice President, Exelon Corp. |
2003 2002 |
|
530,673 492,423 |
|
393,837 499,800 |
|
2,762 121,510 |
|
634,530 416,724 |
|
80,000 90,000 |
|
— — |
|
64,276 62,363 |
| ||||||||
Notes to Summary Compensation Table
| 1. | The amounts shown under the column labeled “Other Annual Compensation” include perquisites and other personal benefits if the aggregate amount exceeds $50,000, and/or amounts reimbursed for the payment of taxes. For Mr. Rowe, the amount shown for 2004 includes $266,877 for personal use of corporate jet aircraft, and $26,040 for the reimbursement of taxes. For Mr. Kingsley, the amount shown for 2004 includes $149,631 for personal use of corporate jet aircraft and $15,408 for the reimbursement of taxes. For Messrs. Young, Shapard, Crane, McLean and Skolds the amount shown is for the reimbursement of taxes. |
| 2. | Exelon has a performance share award program under its Long Term Incentive Plan. Awards made prior to January 2005 were made in restricted stock that vested one-third upon the grant date and one-third upon each of the first and second anniversaries of the grant date. Beginning with awards made in January 2005 and for amounts vesting in 2005, if the participant has achieved 125% of the participant’s stock ownership requirement, the performance shares are settled approximately one-half in cash and one half in stock, with the same vesting schedule as before. For the 3 year performance period ended December 31, 2004, Mr. Rowe was granted 116,662 shares, Messrs. Shapard, Skolds, and McLean were |
432
| each granted 29,853 shares, Mr. Young was granted 24,423 shares, Mr. Crane was granted 20,524 shares, and Mr. Kingsley was granted 52,242 shares. These shares were valued at $42.85 per share. The amount of these grants that vested immediately is shown in the column headed “Long Term Compensation—Payouts”, while the amount that will be settled in stock and will vest on the first and second anniversaries of the award is shown in the column headed “Restricted Stock Awards” and the amount that may be settled in stock or cash (depending on the participant’s stock ownership on the first and second anniversaries of the grant) is shown in the column headed “All Other Compensation.” |
| 3. | This column reports the value of the restricted stock portion of performance share awards as well as other restricted awards granted to individuals during the preceding year by the Compensation Committee and the Board of Directors in recognition of specific accomplishments and/or significant increases in job responsibilities. Mr. Skolds received a grant of 20,000 shares on February 1, 2004, valued at $33.49 per share, which will all vest on February 1, 2009. Mr. Crane received 10,000 shares on February 1, 2004 and 10,000 shares on July 26, 2004. Both grants will fully vest on their respective anniversary dates in 2009. Dividends are payable on these shares. The number of shares and the share price has been adjusted to reflect the 2 for 1 stock split on May 5, 2004. |
| The named executive officers held the amounts of restricted shares, including unvested performance shares granted with respect to the 3-year performance periods ending December 31, 2003 and December 31, 2002, as shown in the following table. Unvested restricted and performance shares continue to receive dividends. The value of restricted shares and unvested performance shares shown below in columns [A] and [B] is based on the December 31, 2004 closing price of Exelon stock, $44.07 except for Mr. Kingsley’s shares which are valued at $39.62 as of October 31, 2004, the last day of his employment. |
| Columns [C], [D] and [E] in the following table include the amounts and value of restricted and unvested performance shares after the grant and vesting of performance shares on January 24, 2005. Column [C] shows the number of restricted shares and unvested performance shares that will be settled in stock, column [D] shows the number of performance shares that may be settled in cash or stock, depending on the participant’s stock ownership at the date of vesting, and column [E] shows the total value of the restricted shares and performance shares shown in columns [C] and [D] as of January 24, 2005, when the closing price of Exelon stock was $42.85. |
| Restricted & Unvested Performance Shares Remaining After Vesting on 01/24/2005 | ||||||||||||
| [A] Number of Restricted and Unvested Performance Shares as of 12/31/2004 |
[B] Value of Restricted and Unvested Performance Shares as of 12/31/2004 |
[C] Number of Shares That Will Be Settled in Stock |
[D] Number of Shares That May Be Settled in Cash or Stock |
[E} Total Value of Shares in Columns [C] + [D] as of 01/24/2005 | ||||||||
| Oliver D. Kingsley, Jr. |
76,339 | $ | 3,024,571 | — | — | $ | — | |||||
| John F. Young |
12,865 | 566,955 | 14,684 | 10,531 | 1,080,463 | |||||||
| John W. Rowe |
85,380 | 3,762,699 | 49,029 | 57,712 | 4,573,852 | |||||||
| Robert S. Shapard |
44,925 | 1,979,840 | 42,795 | 13,831 | 2,426,424 | |||||||
| Christopher M. Crane |
30,717 | 1,353,685 | 28,167 | 8,878 | 1,587,378 | |||||||
| Ian P. McLean |
17,458 | 769,378 | 12,795 | 13,831 | 1,140,924 | |||||||
| John L. Skolds |
47,947 | 2,113,031 | 41,305 | 13,831 | 2,362,578 | |||||||
| 4. | Options granted prior to May 5, 2004 reflect the effect of a 2 for 1 stock split as of that date. |
| 5. | The amounts shown under the column labeled “Long Term Compensation—Payouts” represent the value of the one third of the total performance share award granted with respect to the three year performance period ending December 31, 2004, which vested immediately on the date of grant. Officers who had reached 125% of their stock ownership requirement received a portion of their vested shares in cash. Mr. Kingsley’s entire award vested upon grant because of his retirement. The amount of cash and the value of the vested shares of stock are as follows: |
| Cash Payout |
Value of Vested Shares | |||||
| Oliver D. Kingsley, Jr. |
$ | 1,177,518 | $ | 1,061,052 | ||
| John F. Young |
— | 348,842 | ||||
| John W. Rowe |
927,060 | 739,262 | ||||
| Robert S. Shapard |
— | 426,400 | ||||
| Christopher M. Crane |
154,217 | 138,934 | ||||
| Ian P. McLean |
224,277 | 202,123 | ||||
| John L. Skolds |
224,277 | 202,123 | ||||
433
| 6. | The amounts shown under the column labeled “All Other Compensation” include company paid matching contributions to qualified and non-qualified savings plans along with the value of the unvested two-thirds of the performance share award granted with respect to the three-year performance period ending December 31, 2004 which will be paid out in cash or stock at the time of vesting in 2006 and 2007, depending upon the participants’ stock ownership at that time. |
| Value of Company Contributions to Savings Plans |
Value of Unvested Performance Shares From Current Grant |
Company Paid Term Life Insurance Premiums |
Other Items | |||||||||
| Oliver D. Kingsley, Jr. |
$ | 35,962 | $ | — | $ | 139,389 | $ | 11,930,501 | ||||
| John F. Young |
21,779 | 366,989 | 26,338 | — | ||||||||
| John W. Rowe |
62,067 | 1,852,366 | 238,999 | — | ||||||||
| Robert S. Shapard |
26,577 | 448,583 | 38,699 | — | ||||||||
| Christopher M. Crane |
22,914 | 308,375 | 17,136 | — | ||||||||
| Ian P. McLean |
21,341 | 448,583 | 36,920 | — | ||||||||
| John L. Skolds |
28,558 | 448,583 | 37,742 | — | ||||||||
| Pursuant to Mr. Kingsley’s employment agreement, he is entitled to an enhanced supplemental retirement benefit calculated as if he had 32 years of service. He elected to receive a lump sum of $10,430,501 which was paid to him as of his retirement date, in accordance with his previous payment election. |
| Also, Exelon will reimburse Mr. Kingsley up to $100,000 in any year for his daughter’s medical care expenses not otherwise covered by insurance for a 15 year period which commenced on the date of his retirement. The estimated value of this benefit is $1,500,000. |
| Pursuant to Mr. Kingsley’s employment agreement, his outstanding restricted shares and outstanding performance shares vested upon his retirement. Mr. Kingsley and Exelon entered into a share repurchase agreement through which Exelon purchased from Mr. Kingsley a total of 360,000 shares in two transactions at the weighted average market price over a ten-day period prior to the repurchase date. Exelon paid Mr. Kingsley $7,032,387 for 172,765 shares repurchased on November 17, 2004. Exelon also paid Mr. Kingsley $8,297,933 for 187,235 shares of Exelon common stock repurchased on February 9, 2005. The amounts paid to Mr. Kingsley for repurchase of his shares of Exelon common stock are not included in the above table. |
| Option Grants for 2004 | |||||||||||||
| Individual Grants | |||||||||||||
| Number of Securities Underlying Options Granted (See Note 1) |
Percentage of Total Options Granted to Employees in 2004 |
Exercise or Base Price (See Note 1) |
Options Expiration Date |
Grant Date Value (See Note 2) | |||||||||
| Oliver D. Kingsley, Jr. |
140,000 | 2.00 | % | $ | 32.54 | 01/15/2014 | $ | 779,800 | |||||
| John F. Young |
54,000 | 0.77 | % | 32.54 | 01/15/2014 | 300,780 | |||||||
| John W. Rowe |
400,000 | 5.72 | % | 32.54 | 01/15/2014 | 2,228,000 | |||||||
| Robert S. Shapard |
80,000 | 1.14 | % | 32.54 | 01/15/2014 | 445,600 | |||||||
| Christopher M. Crane |
54,000 | 0.77 | % | 32.54 | 01/15/2014 | 300,780 | |||||||
| Ian P. McLean |
80,000 | 1.14 | % | 32.54 | 01/15/2014 | 445,600 | |||||||
| John L. Skolds |
80,000 | 1.14 | % | 32.54 | 01/15/2014 | 445,600 | |||||||
| 1. | The number of options granted and the exercise or base price have been adjusted to reflect the 2 for 1 stock split which was effective on May 5, 2004. |
| 2. | The “grant date present values” indicated in the Option Grants Table are estimates based on the Black-Scholes option pricing model. Although executives risk forfeiting these options in some circumstances, these risks are not factored into the calculated values. The actual value of these options will be determined by the excess of the stock price over the exercise price of the option on the date that the options are exercised. There is no certainty that the value realized will be at or near the value estimated by the Black-Scholes option pricing model. |
| The assumptions used for the Black-Scholes model are as of the date of grants, January 26, 2004, and are as follows: Risk free interest rate: 3.26%; Volatility: 22.84%; Dividend Yield: 3.30%; and time of exercise: 5 years. |
434
| Option Exercises & Year End Value | |||||||||||||||
| As of December 31, 2004 (See Note 1) | |||||||||||||||
| Number Shares Acquired Exercise |
Dollar Value Realized From Exercise |
Number of Securities Underlying Remaining Options |
Dollar Value of In-the-Money Options | ||||||||||||
| Exercisable |
Unexercisable |
Exercisable |
Unexercisable | ||||||||||||
| Oliver D. Kingsley, Jr. (See Note 2) |
218,500 | $ | 3,066,112 | 724,000 | — | $ | 11,576,280 | $ | — | ||||||
| John F. Young |
— | — | 7,500 | 76,500 | 145,000 | 1,060,020 | |||||||||
| John W. Rowe (See Note 3) |
206,256 | 3,853,893 | 1,894,111 | 795,833 | 33,102,690 | 12,417,056 | |||||||||
| Robert S. Shapard |
— | — | 44,668 | 147,332 | 868,663 | 2,223,617 | |||||||||
| Christopher M. Crane |
— | — | 164,667 | 107,333 | 2,701,017 | 1,681,463 | |||||||||
| Ian P. McLean |
20,000 | 282,150 | 210,192 | 167,096 | 5,135,419 | 3,458,488 | |||||||||
| John L. Skolds |
— | — | 240,000 | 170,000 | 3,913,100 | 2,696,600 | |||||||||
| 1. | This table shows the number and value of exercisable and unexercisable stock options for the named executive officers during 2004. The value is determined using the closing market price of Exelon common stock on December 31, 2004, which was $44.07, less the exercise price of the options. All options whose exercise price exceeded the market price at the day of determination are valued at zero. For all data above, the number of shares and exercise prices have been adjusted to reflect the 2 for 1 stock split of May 5, 2004. |
| 2. | All of Mr. Kingsley’s options vested upon his retirement. |
| 3. | All options exercised by Mr. Rowe during 2004 were done in accordance with a Rule 10b5-1 Trading Plan, which was entered into on February 3, 2004 when Mr. Rowe was unaware of any material adverse information in regard to current and prospective operations of Exelon which had not been publicly disclosed. The dates of the sales were set at the time the Trading Plan was established. |
435
|
Long-Term Incentive Plans—Awards in Last Fiscal Year
| ||||||||||
| Number (See Note 1) |
Performance |
Estimated future payouts under (See Note 2) | ||||||||
| Threshold |
Target |
Maximum | ||||||||
| Oliver D. Kingsley, Jr. |
N/A | 3 years | 14,000 | 28,000 | 56,000 | |||||
| John F. Young |
N/A | 3 years | 6,545 | 13,090 | 26,180 | |||||
| John W. Rowe |
N/A | 3 years | 33,000 | 66,000 | 132,000 | |||||
| Robert S. Shapard |
N/A | 3 years | 8,000 | 16,000 | 32,000 | |||||
| Christopher M. Crane |
N/A | 3 years | 5,500 | 11,000 | 22,000 | |||||
| Ian P. McLean |
N/A | 3 years | 8,000 | 16,000 | 32,000 | |||||
| John L. Skolds |
N/A | 3 years | 8,000 | 16,000 | 32,000 | |||||
| 1. | Exelon’s Long Term Performance Share Award program under the Long-Term Incentive Plan provides incentives to key executives in the form of restricted stock and cash. Awards are determined upon the successful completion of strategic goals designed to achieve long term business success and increased shareholder value. These goals include Exelon’s Total Shareholder Return (TSR) over the previous three years relative to established benchmarks including a peer group of companies listed on the Dow Jones Utility Index and the Standard & Poor’s 500 Index (weighted 70%) and a quantifiable cash savings goal aligned with The Exelon Way initiative (weighted 30%). Grants under the Long Term Performance Share Award Program for 2004 are reflected in the Summary Compensation Table. See note 2 to that table. |
| 2. | A target number of performance shares is established for each participant which is commensurate with the participant’s base salary. Based on measured performance as described above, participants may earn up to 200% of their target and may earn nothing if thresholds are not met. Shares listed under the Threshold, Target and Maximum columns have been adjusted to reflect the 2 for 1 stock split effective on May 5, 2004. |
Retirement Benefit Plans
The following tables show the estimated annual retirement benefits payable on a straight-life annuity basis to participating employees, including officers, in the earnings and year of service classes indicated, under Exelon’s non-contributory retirement plans. The amounts shown in the table are not subject to any reductions for social security or other offset amounts.
Exelon sponsors the Exelon Corporation Retirement Program, a traditional defined benefit pension plan that covers certain management employees who commenced employment prior to January 1, 2001 and certain collective bargaining unit employees. Effective January 1, 2001, Exelon also established two cash balance defined benefit pension plans which cover management employees and certain collective bargaining unit employees hired on or after such date, as well as certain management employees hired prior to such date who elected to transfer to a cash balance plan. Each of these plans is intended to be tax-qualified under Section 401(a) of the Internal Revenue Code.
Covered compensation under the plans generally includes salary and bonus which is disclosed in the Summary Compensation Table under “—Executive Compensation” for the named executive officers. The calculation of retirement benefits under the Exelon Corporation Retirement Program is based upon average earnings for the highest consecutive five-year period under the PECO Energy Company Service Annuity Benefit Formula and for the highest four-year period (three-year for certain represented employees) under the ComEd Service Annuity Benefit Formula.
The Internal Revenue Code limits the individual annual compensation that may be taken into account under tax-qualified retirement plan to $205,000 as of January 1, 2004 and the amount that an individual may accrue in one year under such a defined benefit plan to $165,000 as of January 1, 2004. As permitted by the Employee Retirement Income Security Act of 1974, as amended, Exelon sponsors supplemental pension plans which allow the payment to certain individuals out of its general assets of any benefits calculated under provisions of the applicable qualified pension plan which may be above these limits.
436
Service Annuity System Benefit Table—PECO
(applicable to employees of Exelon, PECO and Generation)
| Annual normal retirement benefits based on specified years of service and earnings | |||||||||||||||||||||
| Highest 5-year annual earnings |
10 years |
15 years |
20 years |
25 years |
30 years |
35 years |
40 years | ||||||||||||||
| $ 100,000 | $ | 18,960 | $ | 25,940 | $ | 32,921 | $ | 39,901 | $ | 46,881 | $ | 53,861 | $ | 60,841 | |||||||
| 200,000 | 39,460 | 54,190 | 68,921 | 83,651 | 98,381 | 113,111 | 127,841 | ||||||||||||||
| 300,000 | 59,960 | 82,440 | 104,921 | 127,401 | 149,881 | 172,361 | 194,841 | ||||||||||||||
| 400,000 | 80,460 | 110,690 | 140,921 | 171,151 | 201,381 | 231,611 | 261,841 | ||||||||||||||
| 500,000 | 100,960 | 138,940 | 176,921 | 214,901 | 252,881 | 290,861 | 328,841 | ||||||||||||||
| 600,000 | 121,460 | 167,190 | 212,921 | 258,651 | 304,381 | 350,111 | 395,841 | ||||||||||||||
| 700,000 | 141,960 | 195,440 | 248,921 | 302,401 | 355,881 | 409,361 | 462,841 | ||||||||||||||
| 800,000 | 162,460 | 223,690 | 284,921 | 346,151 | 407,381 | 468,611 | 529,841 | ||||||||||||||
| 900,000 | 182,960 | 251,940 | 320,921 | 389,901 | 458,881 | 527,861 | 596,841 | ||||||||||||||
| 1,000,000 | 203,460 | 280,190 | 356,921 | 433,651 | 510,381 | 587,111 | 663,841 | ||||||||||||||
Service Annuity System Benefit Table—ComEd
(applicable to employees of Exelon, ComEd and Generation)
| Annual normal retirement benefits based on specified years of service and earnings | |||||||||||||||||||||
| Highest 5-year annual earnings |
10 years |
15 years |
20 years |
25 years |
30 years |
35 years |
40 years | ||||||||||||||
| $ 100,000 | $ | 16,914 | $ | 28,699 | $ | 39,599 | $ | 49,808 | $ | 59,490 | $ | 68,776 | $ | 77,761 | |||||||
| 200,000 | 33,978 | 58,237 | 80,680 | 101,694 | 121,601 | 140,652 | 159,043 | ||||||||||||||
| 300,000 | 51,041 | 87,775 | 121,760 | 153,580 | 183,711 | 212,528 | 240,324 | ||||||||||||||
| 400,000 | 68,103 | 117,312 | 162,841 | 205,466 | 245,822 | 284,404 | 321,604 | ||||||||||||||
| 500,000 | 85,169 | 146,849 | 203,921 | 257,352 | 307,933 | 356,281 | 402,886 | ||||||||||||||
| 600,000 | 102,233 | 176,387 | 245,002 | 309,238 | 370,043 | 428,157 | 484,167 | ||||||||||||||
| 700,000 | 119,296 | 205,924 | 286,082 | 361,124 | 432,153 | 500,034 | 565,447 | ||||||||||||||
| 800,000 | 136,360 | 235,462 | 327,163 | 413,011 | 494,263 | 571,910 | 646,728 | ||||||||||||||
| 900,000 | 153,424 | 264,999 | 368,243 | 464,897 | 556,374 | 643,786 | 728,009 | ||||||||||||||
| 1,000,000 | 170,488 | 294,537 | 409,324 | 516,783 | 618,484 | 715,662 | 809,290 | ||||||||||||||
Credited Years of Service
The executive officers who are named in the Summary Compensation Tables have the following credited years of service as of December 31, 2004 (partial years are not included):
| Exelon |
ComEd | |||||||
| John W. Rowe |
26 years | John L. Skolds |
4 years | |||||
| John L. Skolds |
4 years | John W. Rowe |
26 years | |||||
| Pamela B. Strobel |
20 years | Ruth Ann Gillis |
7 years | |||||
| Randall E. Mehrberg |
4 years | Frank M. Clark |
39 years | |||||
| Oliver D. Kingsley, Jr. |
32 years | Oliver D. Kingsley, Jr. |
32 years | |||||
| GENERATION |
PECO | |||||||
| Oliver D. Kingsley, Jr. |
32 years | John L. Skolds |
4 years | |||||
| John W. Rowe |
26 years | John W. Rowe |
26 years | |||||
| Christopher M. Crane |
12 years | J. Barry Mitchell |
33 years | |||||
| Ian P. McLean |
5 years | Oliver D. Kingsley, Jr. |
32 years | |||||
| John L. Skolds |
4 years | |||||||
437
With respect to executive officers’ credited years of service: Mr. Skolds will receive an additional 7 1/2 years of service upon his 5th anniversary of employment and 7 1/2 years upon his 10th anniversary; Mr. Mehrberg will receive an additional 10 years upon his 5th anniversary; and Mr. Crane will receive an additional year for each year until his 10th anniversary.
Cash Balance Pension Plan
Mr. Shapard, Mr. Young and Mr. O’Brien participate in the Exelon Corporation Cash Balance Pension Plan. Mr. Bemis also participated in this plan. Under this plan, a notional account is established for each participant. For each active participant, the account balance grows as a result of annual benefit credits and annual investment credits.
Currently, the benefit credit under the plan is 5.75% of base pay and annual incentive award (subject to applicable Internal Revenue Code limit). The annual investment credit is the greater of 4% or the average for the year of the S&P 500 Index and the applicable interest rate used under Section 417(e) of the Internal Revenue Code to determine lump sums, determined as of November of such year.
Benefits are vested and nonforfeitable after completion of at least five years of service, and are payable following termination of employment. Apart from the benefit credits and vesting requirement, and as described above, years of service are not relevant to a determination of accrued benefits under the Cash Balance Pension Plan.
Employment Agreements
Employment Agreement with Mr. Rowe
Under the amended and restated employment agreement between Exelon and Mr. Rowe, Mr. Rowe has been serving as Chief Executive Officer of Exelon, Chairman of the Board and a member of the Exelon board of directors since the 2002 annual meeting of shareholders.
Under the employment agreement, which continues in effect until Mr. Rowe’s termination, Mr. Rowe’s annual base salary is determined by Exelon’s compensation committee. He is eligible to participate in the annual incentive award program, long-term incentive plan and all savings, deferred compensation, retirement and other employee benefit plans generally available to other senior executives of Exelon on the same basis as other senior executives of Exelon. His life insurance coverage will be at least three times his base salary.
In addition, Mr. Rowe is entitled to receive a special supplemental executive retirement plan, the “SERP,” benefit upon termination of employment for any reason other than for cause. The special SERP benefit, when added to all other retirement benefits provided to Mr. Rowe by Exelon, will equal Mr. Rowe’s SERP benefit, calculated under the terms of the SERP in effect on March 10, 1998 as if:
| • | he had attained age 60 (or his actual age, if greater); |
| • | he had earned 20 years of service on March 16, 1998 and one additional year of service on each anniversary after that date and prior to termination; and |
| • | his annual incentive awards for each of 1998 and 1999 had been $300,000 greater than the annual incentive awards he actually received for those years. |
On February 19, 1999, Mr. Rowe was granted a right to receive, on termination of employment, 24,688 shares of Exelon common stock, increased by the number of shares that could have been acquired with dividends on such number of shares after that date and subject to adjustment for events such as recapitalization, merger, or stock splits.
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Except as provided below, if Exelon terminates Mr. Rowe’s employment for reasons other than cause, death or disability or if he terminates employment for good reason, he would be entitled to the following benefits:
| • | a lump sum payment of Mr. Rowe’s accrued but unpaid base salary and annual incentive, and a prorated annual bonus for the year in which his employment terminates; |
| • | for a two-year severance period following the termination of employment, continued payment of base salary and continued payment of an annual incentive equal to either the annual incentive for the last year ending prior to termination or the average of the annual incentives payable with respect to Mr. Rowe’s last three full years of employment, whichever is greater; |
| • | for the two-year severance period, continuation of life, disability, accident, health and other welfare benefits for him and his family, plus post-retirement health care coverage for him and his wife for the remainder of their respective lives; |
| • | all exercisable options remain exercisable until the applicable option expiration date; and |
| • | unvested options continue to become exercisable during the two-year severance period and thereafter remain exercisable until the applicable option expiration date. |
The term “good reason” means any material breach of the employment agreement by Exelon, including:
| • | a failure to provide compensation and benefits required under the employment agreement; |
| • | causing Mr. Rowe to report to someone other than the Exelon board of directors; |
| • | any material adverse change in Mr. Rowe’s status, responsibilities or perquisites; or |
| • | any announcement by the Exelon board of directors without Mr. Rowe’s consent that Exelon is seeking a replacement for Mr. Rowe. |
The term “cause” means any of the following, unless cured within the time period specified in the agreement:
| • | conviction of a felony or a misdemeanor involving moral turpitude, fraud or dishonesty; |
| • | willful misconduct in the performance of duties intended to personally benefit the executive; or |
| • | material breach of the agreement (other than as a result of incapacity due to physical or mental illness). |
In connection with Exelon’s entry into the merger agreement, Mr. Rowe’s employment agreement was amended to provide that Mr. Ferland’s service as non-executive Chairman of the Exelon board of directors for the periods described in the Amended and Restated By-laws of Exelon to be adopted upon completion of the merger will not constitute “good reason.” Therefore, Mr. Rowe is not entitled to any severance payments as a result of the merger with PSEG.
Mr. Rowe would receive the termination benefits described under “—Other Change in Control Employment Agreements and Severance Plan” below rather than the benefits described in the previous paragraph, if Exelon terminates Mr. Rowe without cause or he terminates with good reason, and
| • | the termination occurs within 24 months after a change in control of Exelon or within 18 months after a Significant Acquisition (as each is described under “—Other Change in Control Employment Agreements and Severance Plan”); or |
| • | Mr. Rowe resigns before normal retirement because of the failure to be appointed or elected as the sole Chief Executive Officer and Chairman of the Board and as a member of the Exelon board of directors, |
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except that:
| • | instead of receiving the target annual incentive for the year in which termination occurs, Mr. Rowe will receive an annual incentive award for the year in which termination occurs, based on the higher of the prior year’s annual incentive payment or the average annual incentives paid over the prior three years; |
| • | in determining the severance payment for Mr. Rowe, the average incentive awards for three years preceding the termination will be used rather than a two year average; |
| • | following the three-year period during which welfare benefits are continued, Mr. Rowe and his wife will be eligible to receive post-retirement health care coverage; and |
| • | change in control benefits are not provided to Mr. Rowe for a termination of employment in the event of a Disaggregation (see “—Other Change in Control Employment Agreements and Severance Plan” for a discussion of this term). |
With respect to a termination of employment during the change in control or Significant Acquisition periods described above, the following events will constitute additional grounds for termination for good reason:
| • | a good faith determination by Mr. Rowe that he is substantially unable to perform, or that there has been a material reduction in, any of his duties, functions, responsibilities or authority; |
| • | the failure of any successor to assume his employment agreement; |
| • | a relocation of Exelon’s office by more than 50 miles; or |
| • | a 20% increase in the amount of time that Mr. Rowe must spend traveling for business outside of the Chicago area. |
Mr. Rowe is subject to confidentiality restrictions and to non-competition, non-solicitation and non-disparagement restrictions continuing in effect for two years following his termination of employment.
Employment Agreement and Share Purchase Agreement with Mr. Oliver D. Kingsley
Mr. Kingsley retired on November 1, 2004 as President and Chief Operating Officer of Exelon.
The terms of Mr. Kingsley’s employment agreement with Exelon prior to his retirement are described below.
Exelon and Exelon Generation entered into an amended employment agreement with Mr. Kingsley as of September 5, 2002, which restated his employment agreement with Commonwealth Edison Company in effect at the time of the merger forming Exelon and under which Mr. Kingsley agreed to serve as senior executive vice president of Exelon. Mr. Kingsley’s employment agreement was further amended as of April 28, 2003, at which time he agreed to serve as President and Chief Operating Officer of Exelon.
Under the amended employment agreement, Mr. Kingsley’s annual base salary was $850,000, and his target performance award under the annual incentive plan was 85% of his base salary, with a maximum payout of 170% of his base salary. Mr. Kingsley was eligible to participate in long-term incentive, stock option, and other equity incentive plans, savings and retirement plans and welfare plans, and to receive fringe benefits on the same basis as peer executives of Exelon. Mr. Kingsley was also entitled to 30 days of paid vacation per year.
In addition, Exelon will reimburse Mr. Kingsley for his daughter’s medical care expenses for a 15-year period (up to $100,000 in any year) that commenced upon his retirement.
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Mr. Kingsley received a grant of 35,000 shares of restricted stock on September 5, 2002, which accelerated upon his retirement on October 31, 2004.
Mr. Kingsley became eligible to elect retiree health coverage on the same terms as peer employees eligible for early retirement benefits at the time of his retirement. All restricted stock and all his stock options fully vested at the time of his retirement. Options remain exercisable until (1) the option expiration date for options granted before January 1, 2002 or (2) the earlier of the fifth anniversary of his retirement or the option’s expiration date, for options granted after that date.
Mr. Kingsley’s amended employment agreement provides for an enhanced supplemental retirement benefit determined by treating him under the SERP as if he had 30 years of service as of October 31, 2002, plus (1) one additional year each October 31 during his employment and (2) an additional year for each year during the severance period described below. Severance payments will be included in compensation under the SERP. The enhanced SERP benefits were paid to Mr. Kingsley upon his retirement.
Mr. Kingsley’s amended employment agreement contains confidentiality requirements and also non-competition, non-solicitation and non-disparagement provisions, which are effective for two years following his retirement.
On November 8, 2004, Exelon entered into a share repurchase agreement with Mr. Kingsley with respect to certain shares of Exelon common stock that Mr. Kingsley held or had the right to acquire. Under the agreement, Exelon repurchased 172,765 shares of Exelon common stock held by Mr. Kingsley on November 17, 2004 for $7,032,387 and 187,235 shares of Exelon common stock held by Mr. Kingsley on February 9, 2005 for $8,297,933.
Mr. Kingsley has agreed that he will not transfer any of his remaining shares of Exelon common stock prior to May 1, 2005, that he may transfer up to 360,000 shares of Exelon common stock between May 1, 2005 and December 31, 2005, and may freely transfer any other shares after January 1, 2006. During the transfer restriction periods, the agreement does permit transfers of shares to two specified Kingsley family trusts, which would be bound by the provisions of the agreement following any such transfer.
Other Change in Control Employment Agreements and Severance Plan
Exelon has entered into change in control employment agreements with the named executive officers other than Mr. Rowe, which generally protect such executives’ position and compensation levels for two years after a change in control of Exelon. Those agreements were restated and generally became effective May 1, 2004 for a period of two years, subject to an annual extension each subsequent May 1 if there has not been a change in control. Under the restated change in control employment agreements, the circumstances under which an executive can terminate employment for “good reason” are narrower and the circumstances under which Exelon can terminate the executive’s employment for “cause” are broader than under the prior agreements. However, the definition of a change in control was not changed and the level of severance benefits was not reduced under the restated agreements.
During the 24-month period following a change in control (or during the 18-month period following another significant corporate transaction affecting the executive’s business unit in which Exelon shareholders retain between 60% and 662/3% control (a “Significant Acquisition”)) if a named executive officer resigns for good reason or if the executive’s employment is terminated by Exelon other than for cause or disability, the executive is entitled to the following:
| • | the executive’s target annual incentive for the year in which termination occurs; |
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| • | severance payments equal to three times the sum of (1) the executive’s base salary plus (2) the higher of the executive’s target annual incentive for the year of termination or the executive’s average annual incentive award payments for the two years preceding the termination; |
| • | a benefit equal to the amount payable under the SERP determined as if (1) the SERP benefit were fully vested, (2) the executive had three additional years of age and years of service (two years for executives who entered into such agreements after 2003) and (3) the severance pay constituted covered compensation for purposes of the SERP; |
| • | a cash payment equal to the actuarial equivalent present value of the unvested portion of the executive’s accrued benefits under Exelon’s defined benefit retirement plan; |
| • | all options, performance shares or units, deferred stock units, restricted stock, or restricted share units become fully vested, and options remain exercisable until (1) the option expiration date, for options granted before January 1, 2002 or (2) the earlier of the fifth anniversary of his termination date or the option’s expiration date, for options granted after that date; |
| • | life, disability, accident, health and other welfare benefit coverage continues for three years, followed by retiree health coverage if the executive has attained at least age 50 and completed at least ten years of service (or any lesser eligibility requirement then in effect for regular employees); and |
| • | outplacement services for at least twelve months. |
The change in control benefits are also provided if the executive is terminated other than for cause or disability, or terminates for good reason (1) after a tender offer or proxy contest commences, or after Exelon enters into an agreement which, if consummated, would cause a change in control, and within one year after such termination a change in control does occur, or (2) within two years after a sale or spin-off of the executive’s business unit in contemplation of a change in control that actually occurs within 60 days after such sale or spin-off (a “Disaggregation”).
A change in control generally occurs:
| • | when any person acquires 20% of Exelon’s voting securities; |
| • | when the incumbent members of the Exelon board of directors (or new members nominated by a majority of incumbent directors) cease to constitute at least a majority of the members of the Exelon board of directors; |
| • | upon consummation of a reorganization, merger or consolidation, or sale or other disposition of at least 50% of Exelon’s operating assets (excluding a transaction where Exelon shareholders retain at least 60% of the voting power); or |
| • | upon shareholder approval of a plan of complete liquidation or dissolution. |
“Good reason,” under the change in control employment agreements generally includes any of the following occurring within 2 years after a change in control or Disaggregation or within 18 months after a Significant Acquisition:
| • | a material adverse reduction in salary, incentive compensation opportunity or aggregate benefits, unless such reduction is part of a policy, program or arrangement applicable to peer executives; |
| • | failure of a successor to assume the agreement; |
| • | a material breach of the agreement by Exelon; or |
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| • | any of the following, but only after a change in control or Disaggregation: (1) a material adverse reduction in the executive’s position, duties or responsibilities (other than a change in the position or level of officer to whom the executive reports or a change that is part of a policy, program or arrangement applicable to peer executives) or (2) a required relocation by more than 50 miles. |
“Cause” under the change in control employment agreements generally includes any of the following:
| • | refusal to perform or habitual neglect in the performance of duties or responsibilities or of specific directives of the officer to whom the executive reports which are not materially inconsistent with the scope and nature of the executive’s duties and responsibilities; |
| • | willful or reckless commission of acts or omissions which have resulted in or are likely to result in a material loss or material damage to the reputation of Exelon or any of its affiliates, or that compromise the safety of any employee; |
| • | commission of a felony or any crime involving dishonesty or moral turpitude; |
| • | material violation of the code of business conduct which would constitute grounds for immediate termination of employment, or of any statutory or common-law duty of loyalty; or |
| • | any breach of the executive’s restrictive covenants. |
The mere occurrence of a Disaggregation is not “good reason.”
Executives who have entered into change in control employment agreements will be eligible to receive an additional payment to cover excise taxes imposed under Section 4999 of the Internal Revenue Code on “excess parachute payments” or under similar state or local law if the after-tax amount of payments and benefits subject to these taxes exceeds 110% of the “safe harbor” amount that would not subject the employee to these excise taxes. If the after-tax amount, however, is less than 110% of the safe harbor amount, payments and benefits subject to these taxes would be reduced or eliminated to equal the safe harbor amount.
If a named executive officer other than Mr. Rowe resigns for good reason or is terminated by Exelon other than for cause or disability, in each case under circumstances not covered by an individual change in control employment agreement, the named executive officer may be eligible for the following non-change in control benefits under the Exelon Corporation Senior Management Severance Plan:
| • | pro-rated payment of the executive’s target annual incentive for the year in which termination occurs; |
| • | for a two-year severance period, continued payment of base salary and continued payment of annual incentive equal to the executive’s target incentive for the year in which the termination occurs; |
| • | a benefit equal to the amount payable under the SERP determined as if the severance payments were paid as ordinary base salary and annual incentive; |
| • | for the two-year severance period, continuation of health, basic life and other welfare benefits the executive was receiving immediately prior to the severance period, followed by retiree health coverage if the executive has attained at least age fifty and completed at least ten years of service (or any lesser eligibility requirement then in effect for regular employees); and |
| • | outplacement services for at least six months. |
Payments are subject to reduction by Exelon to the extent necessary to avoid imposition of excise taxes imposed by Section 4999 of the Internal Revenue Code on “excess parachute payments” or under similar state or local law.
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Consummation of the Merger is not a change in control and is not expected to be a Significant Acquisition under the change in control employment agreements or the Exelon Corporation Senior Management Severance Plan. However, the Exelon compensation committee recently considered changes to the Senior Management Severance Plan that would provide the following benefits to participating executives whose employment terminates in connection with the merger: (1) the executive’s target annual incentive, rather than a pro-rated target annual incentive, for the year in which termination occurs, (2) use of the higher of the executive’s target annual incentive in the year of termination or the executive’s average annual incentives for the two years preceding termination, for purposes of determining the amount of continued annual incentive during the severance period, and (3) accelerated vesting of outstanding stock options and restricted stock awards. No such changes have been formally adopted to date, but it is currently anticipated that such changes may be adopted on or before the closing of the Merger.
“Good reason” is defined under the Senior Management Severance Plan as either of the following:
| • | a material reduction of the executive’s salary, incentive compensation opportunity or aggregate benefits unless such reduction is part of a policy, program or arrangement applicable to peer executives of Exelon or of the business unit that employs the executive; or |
| • | a material adverse reduction in the executive’s position or duties (other than a change in the position or level of officer to whom the executive reports) that is not applicable to peer executives of Exelon or of the business unit that employs the executive, but excluding any change (1) resulting from a reorganization or realignment of all or a significant portion of the business, operations or senior management of Exelon or of the business unit that employs the executive or (2) that generally places the executive in substantially the same level of responsibility. |
The definition of “cause” under the Senior Management Severance Plan is the same as the definition of such term under the restated individual change in control employment agreements.
Report of the Exelon Compensation Committee
ComEd, PECO and Generation are controlled subsidiaries of Exelon and as such do not have compensation committees. Instead, that function is fulfilled for ComEd, PECO and Generation by the compensation committee of the Exelon board of directors. The following is the report of the Exelon compensation committee.
Compensation Philosophy
Exelon’s executive compensation program is designed to motivate and reward senior management for achieving high levels of business performance and outstanding financial results. In 2004, Exelon continued to reward executives on the basis of compensation that is benchmarked with the best practices of high performing energy services companies and general industry firms. This philosophy reflects a commitment to attracting and retaining key executives to ensure continued focus on achieving long-term growth in shareholder value.
The Exelon compensation committee (the “Committee”), composed entirely of independent directors, is responsible for administering executive compensation programs, policies and practices. Exelon’s executive compensation program comprises three elements:
| • | base salary; |
| • | annual incentives; and |
| • | long-term incentives. |
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These components balance short-term and longer range business objectives and align executive financial rewards with those of Exelon’s shareholders.
Factors Considered in Determining Overall Compensation
The Committee commissioned a study of compensation programs in the fall of 2004. This analysis was conducted by a leading independent management compensation consulting firm and included an assessment of business plans, strategic goals, peer companies and competitive compensation levels benchmarked with the external market.
The study results indicated that the mix of compensation components (i.e., salary, annual and long-term incentives) is effectively aligned with the best practices of the external market. Exelon’s pay-for-performance philosophy places an emphasis on pay-at-risk. Pay will exceed market levels when excellent performance is achieved. Failure to achieve target goals will result in below market pay.
How Base Salary is Determined
Base salaries for Exelon’s executives are determined based on individual performance with reference to the salaries of executives in similar positions in general industry, and where appropriate, the energy services sector. Executive salaries are targeted to approximate the median (50th percentile) salary levels of the companies identified and surveyed.
Mr. Rowe’s 2004 Base Salary
The independent directors of the Exelon board of directors, on the recommendations of the Committee and the Exelon corporate governance committee, determined Mr. Rowe’s base salary for serving as the Chief Executive Officer by considering:
| • | a review of benchmark levels of base pay, which were provided by independent consulting firms; |
| • | performance achieved against financial and operational goals; and |
| • | the implementation of Exelon’s strategic plans. |
Mr. Rowe’s annualized base salary was increased to $1,250,000 effective March 1, 2004.
Other Named Executives’ 2004 Base Salaries
The base salaries of the other named executive officers listed in the Summary Compensation Table under “—Executive Compensation” were determined based upon individual performance and by considering comparable compensation data from the industry surveys referred to above.
How 2004 Annual Incentives are Determined
Exelon establishes corporate and business unit measures each year which are based on factors necessary to achieve strategic business objectives. These measures are incorporated into financial, customer and internal indicators designed to measure corporate and business unit performance.
The annual incentive awards paid to Exelon executives for 2004 were determined in accordance with the Exelon incentive programs. Generally, annual incentives were paid to executives based on a combination of the achievement of pre-determined corporate and business unit-specific measures and individual performance. The incentive plan was designed to tie executive annual incentives to the achievement of key goals of Exelon and, as applicable, the executive’s particular business unit.
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For 2004, the annual incentive payments to Mr. Rowe and each of nine other senior executives was funded from a hypothetical incentive pool established by the Exelon board of directors under a shareholder-approved plan which is intended to comply with Section 162(m) of the Internal Revenue Code. The incentive pool was funded with 1.5% of Exelon’s operating income. The Exelon board of directors determined a lesser award based on the achievement of earnings per share for Mr. Rowe in the amount of $1,675,000.
Mr. Rowe’s 2004 Annual Incentive
The Committee and the Exelon board of directors exercised negative discretion to approve an annual incentive of $1,675,000 for Mr. Rowe consistent with the methodology used to determine the awards payable to other employees based on Exelon’s earnings per share.
In evaluating Mr. Rowe’s performance, the directors also considered the leadership demonstrated in positioning Exelon for the future.
Other Named Executive Officers’ 2004 Annual Incentives
The final 2004 incentive plan payouts as approved by the Committee for the other named executive officers listed in the Summary Compensation Table under “—Executive Compensation” also reflect the Committee’s exercise of negative discretion and were determined consistent with the methodology used to determine the awards payable to other employees based on Exelon’s earnings per share and also reflect each individual’s performance.
How Compensation is Used to Focus Management in Long-Term Value Creation
Exelon established a long-term incentive program that includes a combination of non-qualified stock options (60%) and performance shares (40%). Exelon granted long-term incentives in the form of stock options to key management employees, including the named executive officers, effective January 26, 2004. The purpose of stock options is to align compensation directly to increases in shareholder value. Individuals receiving stock options are provided the right to buy a fixed number of shares of Exelon common stock at the closing price of such stock on the grant date. Options typically vest over a four-year period and have a term of ten years.
Stock Option Awards
Mr. Rowe received a grant of 400,000 non-qualified stock options on January 26, 2004. Other senior executives received grants on January 26, 2004 to motivate them to achieve stock appreciation in support of shareholder value.
Exelon Performance Share Awards
Long-term incentives were awarded in the form of restricted stock to retain key executives engaged in positioning Exelon. Awards were determined based upon the successful completion of strategic goals designed to achieve long-term business success and increased shareholder value. Depending on Exelon’s performance each year, the Committee could award performance shares with prohibitions on sale or transfer until the restrictions lapse.
Performance shares are paid in shares of Exelon common stock: 33% vest upon the award date, 33% vest the following year and 33% vest the year after that.
The 2004 Long-Term Performance Share Program was based on Total Shareholder Return (“TSR”), comparing Exelon to companies listed on the Dow Jones Utility Index and the Standard and
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Poor’s 500 Index using a three-year TSR compounded monthly. The other component in determining the award was 2004 cash savings from The Exelon Way initiative.
The Exelon board of directors approved Mr. Rowe’s Performance Share Award of 116,662 shares. Beginning in 2004, executives were permitted to receive earned awards in stock and cash if they achieved 125% of their stock ownership requirement. Mr. Rowe exceeded the 125% of stock ownership (five times base salary) and opted for the payment in stock and cash. All other executives named also received Performance Share Awards in a similar manner.
Senior management recommended and the Exelon board of directors approved a modest reduction to the 2004 Long-Term Performance Share Award Program of 10% for the Chairman and Chief Executive Officer and 5% for all other participants. This award reduction partially offset the expense associated with a one-time payment made to non-executive employees to assist them with the cost of medical plan charges in 2005.
Ability to Deduct Executive Compensation
Under Section 162(m) of the Internal Revenue Code, executive compensation in excess of $1 million paid to a chief executive officer or other person among the four other highest compensated officers is generally not deductible for purposes of corporate Federal income taxes. However, “qualified performance-based compensation” within the meaning of Section 162(m) of the Internal Revenue Code and applicable regulations remains deductible. The Committee intends to continue reliance on performance-based compensation programs, consistent with sound executive compensation policy. Such programs will be designed to fulfill, in the best possible manner, future corporate business objectives. The Committee’s policy has been to seek to cause executive incentive compensation to qualify as “performance-based” in order to preserve its deductibility for Federal income tax purposes to the extent possible without sacrificing flexibility in designing appropriate compensation programs.
For 2004, the Committee approved an annual incentive award plan design that provided for the final awards paid to named executive officers to qualify as performance-based compensation under Section 162(m) of the Internal Revenue Code.
Exelon Compensation Committee
Edward A. Brennan, Chair
M. Walter D’Alessio
Rosemarie B. Greco
Ronald Rubin
Richard L. Thomas
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Stock Performance Graph
The performance graph below illustrates a five year comparison of cumulative total returns based on an initial investment of $100 in PECO Energy Company common stock that was exchanged for Exelon Corporation common stock in the share exchange on October 20, 2000, as compared with the S&P 500 Stock Index and the S&P Utility Average for the period 1999 through 2004.
This performance chart assumes:
| • | $100 invested on December 31, 1999 in PECO Energy Company common stock, in the S&P 500 Stock Index and in the S&P Utility Index; |
| • | All dividends are reinvested; and |
| • | PECO Energy common stock exchanged for Exelon Corporation common stock on a 1:1 basis on October 20, 2000. |
| 1999 |
2000 |
2001 |
2002 |
2003 |
2004 | |||||||||||||
| Exelon Corporation |
$ | 100.00 | $ | 205.98 | $ | 145.21 | $ | 165.60 | $ | 215.04 | $ | 295.35 | ||||||
| S&P 500 |
100.00 | 90.89 | 80.14 | 62.47 | 80.35 | 89.07 | ||||||||||||
| S&P Utilities |
100.00 | 156.99 | 109.39 | 76.63 | 96.56 | 119.87 | ||||||||||||
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ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
The following table shows the ownership of Exelon common stock as of December 31, 2004 by (1) any person or entity that has publicly disclosed ownership of more than five percent, of Exelon’s outstanding stock, (2) any director, (3) each executive officer named in the Summary Compensation Table, and (4) all directors and executive officers as a group.
Beneficial Ownership Table
| [A] Beneficially (See Note 1) |
[B] Shares Held in (See Note 2) |
[C] = [A] + [B] Total Shares |
[D] Share (See Note 3) |
[E] = [C] + [D] Total Share | ||||||
| 5% Owners |
||||||||||
| Wellington Management Company, LLP (See Note 4) |
42,937,621 | 42,937,621 | 42,937,621 | |||||||
| Barclays Global Investors, NA (See Note 5) |
47,021,765 | 47,021,765 | 47,021,765 | |||||||
| Capital Research and Management Company (See Note 6) |
37,541,800 | 37,541,800 | 37,541,800 | |||||||
| Directors |
||||||||||
| Edward A. Brennan |
7,999 | 11,308 | 19,307 | 9,909 | 29,216 | |||||
| M. Walter D’Alessio |
12,565 | 29,742 | 42,307 | — | 42,307 | |||||
| Nicholas DeBenedictis |
— | 4,740 | 4,740 | — | 4,740 | |||||
| Bruce DeMars |
9,146 | 8,799 | 17,945 | — | 17,945 | |||||
| Nelson A. Diaz |
500 | 1,291 | 1,791 | 422 | 2,213 | |||||
| G. Fred DiBona, Jr. |
1,600 | 15,260 | 16,860 | — | 16,860 | |||||
| Sue L. Gin |
25,895 | 10,296 | 36,191 | 5,488 | 41,679 | |||||
| Rosemarie B. Greco |
2,000 | 13,006 | 15,006 | 4,631 | 19,637 | |||||
| Edgar D. Jannotta |
13,240 | 19,830 | 33,070 | 7,632 | 40,702 | |||||
| John M. Palms |
2,603 | 24,454 | 27,057 | — | 27,057 | |||||
| John W. Rogers, Jr. |
11,374 | 10,732 | 22,106 | 5,276 | 27,382 | |||||
| Ronald Rubin |
14,726 | 29,630 | 44,356 | 737 | 45,093 | |||||
| Richard L. Thomas |
21,256 | 15,858 | 37,114 | 9,095 | 46,209 | |||||
| Named Officers |
||||||||||
| John W. Rowe |
2,260,708 | 313,646 | 2,574,354 | 86,942 | 2,661,296 | |||||
| Robert S. Shapard |
96,000 | 69,702 | 165,702 | 14,813 | 180,515 | |||||
| John L. Skolds |
327,160 | 94,252 | 421,412 | 20,329 | 441,741 | |||||
| Pamela B. Strobel |
391,112 | 92,713 | 483,825 | 17,911 | 501,736 | |||||
| Randall E. Mehrberg |
194,000 | 63,437 | 257,437 | 15,397 | 272,834 | |||||
| Oliver D. Kingsley, Jr. |
740,041 | — | 740,041 | 6,499 | 746,540 | |||||
| Directors, Named & Executive Officers as a group, 25 people (See Note 7) |
5,227,878 | 1,050,793 | 6,278,671 | 278,015 | 6,556,686 | |||||
| 1. | The shares listed above under Beneficially Owned Shares, Column [A], include shares that may be acquired from non-qualified stock options that are fully vested or that vest within 60 days of January 31, 2005. |
| 2. | The shares listed above under Shares Held in Company Plans, Column [B], include restricted shares, deferred shares, shares held in the 401(k) plan, and shares that may be acquired from all unvested, non-qualified stock options that are not included in Column [A]. |
| 3. | The shares listed above under Equivalent Shares to be Settled in Cash or Stock, Column [D], include the unvested portion of performance shares which may be settled in either cash or stock depending on whether the officer has achieved 125% of their stock ownership requirement, and phantom shares held in a non-qualified deferred compensation plan which will be settled in cash on a 1 for 1 basis upon retirement or termination. |
| 4. | In a Schedule 13G filed with the SEC on February 14, 2005, an investment adviser, Wellington Management Company, LLP, 75 State Street, Boston, MA 02109, disclosed that as of December 31, 2004, it was the beneficial owner of 42,937,621 shares, or approximately 6.481% of Exelon’s issued and outstanding shares. Wellington disclosed that it shared power to vote 24,094,410 shares and shared power to dispose of 42,937,621 shares. |
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| 5. | In a Schedule 13G filed with the SEC on February 14, 2005, a bank, Barclays Global Investors, NA, 45 Fremont Street, San Francisco, CA 94105, and its affiliates, including banks, investment advisers and broker/dealers, disclosed that as of December 31, 2004, they were the beneficial owners of an aggregate of 47,021,765 shares, or approximately 7.09% of Exelon’s issued and outstanding shares. Barclays disclosed that it had the sole power to vote 41,789,460 shares and sole power to dispose of 47,021,765 shares. |
| 6. | In a Schedule 13G filed with the SEC on February 11, 2005, an investment adviser, Capital Research and Management Company, 333 South Hope Street, Los Angeles, CA 90071, disclosed that as of December 31, 2004, it is deemed to be the beneficial owner of 37,541,800 shares, or approximately 5.7% of Exelon’s issued and outstanding shares, although it disclaimed beneficial ownership pursuant to Rule 13d-4. Capital Research disclosed that it had sole dispositive power of 37,541,800 shares. |
| 7. | Beneficial ownership, shown in Column [A], of directors and executive officers as a group represents less than 1% of the outstanding shares of Exelon common stock. |
Securities Authorized for Issuance under Equity Compensation Plans
| Plan Category |
Number of securities to be issued upon exercise of outstanding options |
Weighted-average price of outstanding options |
Number of securities remaining available for future issuance under equity compensation plans(a) | ||||
| Equity compensation plans approved by security holders |
24,759,308 | $ | 26.94 | 14,777,078 | |||
| Equity compensation plans not approved by security holders(b) |
660,808 | 20.56 | — | ||||
| Total |
25,420,116 | $ | 26.78 | 14,770,078 | |||
| (a) | Excludes securities to be issued upon exercise of outstanding options. |
| (b) | Amount shown represents options issued under a broad based incentive plan available to all employees of PECO Energy Company. Options were issued beginning in November 1998 and no further grants were made after October 20, 2000. |
Exelon indirectly owns 127,002,904 shares of ComEd common stock, more than 99% of all outstanding shares. Accordingly, the only beneficial holder of more than five percent of ComEd’s voting securities is Exelon, and none of the directors or executive officers of ComEd hold any ComEd voting securities.
450
The following table shows the ownership of Exelon common stock as of December 31, 2004 by (1) any director of ComEd, (2) each executive officer of ComEd named in the Summary Compensation Table, and (3) all directors and executive officers of ComEd as a group.
Beneficial Ownership Table
| [A] (See Note 1) [A] |
[B] Shares Held in Company Plans (See Note 2) [B] |
[C] = [A] + [B] Total Shares Held |
[D] Equivalents to be Settled in Cash or Stock (See Note 3) |
[E] = [C] + [D] Total Share Interest | ||||||
| Directors and Named Officers |
||||||||||
| S. Gary Snodgrass (Director) |
265,114 | 25,034 | 290,148 | 12,441 | 302,589 | |||||
| Michael B. Bemis (see Note 4) |
33,499 | 11,396 | 44,895 | 130 | 45,025 | |||||
| John L. Skolds (Director) |
327,160 | 94,252 | 421,412 | 20,329 | 441,741 | |||||
| John W. Rowe (Director) |
2,260,708 | 313,646 | 2,574,354 | 86,942 | 2,661,296 | |||||
| Robert S. Shapard (Director) |
96,000 | 69,702 | 165,702 | 14,813 | 180,515 | |||||
| Ruth Ann M. Gillis |
353,301 | 46,811 | 400,112 | 21,739 | 421,851 | |||||
| Frank M. Clark (Director) |
228,799 | 53,420 | 282,219 | 19,324 | 301,543 | |||||
| Oliver D. Kingsley, Jr. |
740,041 | — | 740,041 | 6,499 | 746,540 | |||||
| Directors, Named & Executive Officers as a group, 10 people. (See Note 5) |
4,472,266 | 674,214 | 5,146,480 | 196,933 | 5,343,413 | |||||
| 1. | The shares listed above under Beneficially Owned Shares, Column [A], include shares that may be acquired from non-qualified stock options that are fully vested or that vest within 60 days of January 31, 2005. |
| 2. | The shares listed above under Shares Held in Company Plans, Column [B], include restricted shares, deferred shares, shares held in the 401(k) plan, and shares that may be acquired from all unvested, non-qualified stock options that are not included in Column [A]. |
| 3. | The shares listed above under Equivalent Shares to be Settled in Cash or Stock, Column [D], include the unvested portion of performance shares which may be settled in either stock or cash depending on whether the officer has achieved 125% of their stock ownership requirement, and phantom shares held in a non-qualified deferred compensation plan which will be settled in cash on a 1 for 1 basis upon retirement or termination. |
| 4. | Mr. Bemis’s share totals are as of January 31, 2004, the last day of his employment. |
| 5. | Beneficial ownership, shown in Column [C], of directors and executive officers as a group represents less than 1% of the outstanding shares of Exelon common stock. |
No ComEd securities are authorized for issuance under equity compensation plans. For information about Exelon Securities authorized for issuance to ComEd employees under Exelon equity compensation plans, see above under “Exelon—Securities Authorized Under Equity Compensation Plans.”
451
Exelon indirectly owns all 170,478,507 shares of PECO common stock. As of December 31, 2004, there were 874,720 shares of PECO preferred stock outstanding. Accordingly, the only beneficial owner of more than five percent of PECO’s voting securities is Exelon, and none of the directors or executive officers of PECO hold any preferred stock.
The following table shows the ownership of Exelon common stock as of December 31, 2004 by (1) any director of PECO, (2) each executive officer of PECO named in the Summary Compensation Table, and (3) all directors and executive officers of PECO as a group.
Beneficial Ownership Table
| [A] (See Note 1) |
[B] (See Note 2) |
[C] = [A] + [B] Total Shares |
[D] in Cash or Stock (See Note 3) |
[E] = [C] + [D] Total Share Interest | ||||||
| Directors and Named Officers |
||||||||||
| Michael B. Bemis (see Note 4) |
33,499 | 11,396 | 44,895 | 130 | 45,025 | |||||
| John L. Skolds (Director) |
327,160 | 94,252 | 421,412 | 20,329 | 441,741 | |||||
| John W. Rowe (Director) |
2,260,708 | 313,646 | 2,574,354 | 86,942 | 2,661,296 | |||||
| Robert S. Shapard (Director) |
96,000 | 69,702 | 165,702 | 14,813 | 180,515 | |||||
| Denis P. O’Brien (Director) |
140,737 | 11,853 | 152,590 | 8,013 | 160,603 | |||||
| J. Barry Mitchell |
138,156 | 39,531 | 177,687 | 10,593 | 188,280 | |||||
| Oliver D. Kingsley, Jr. |
740,085 | — | 740,085 | 6,499 | 746,584 | |||||
| Directors, Named & Executive Officers as a group, 8 people. (See Note 5) |
3,765,788 | 560,803 | 4,326,591 | 151,442 | 4,478,033 | |||||
| 1. | The shares listed above under Beneficially Owned Shares, Column [A], include shares that may be acquired from non-qualified stock options that are fully vested or that vest within 60 days of January 31, 2005. |
| 2. | The shares listed above under Shares Held in Company Plans, Column [B], include restricted shares, deferred shares, shares held in the 401(k) plan, and shares that may be acquired from all unvested, non-qualified stock options that are not included in Column [A]. |
| 3. | The shares listed above under Equivalent Shares to be Settled in Cash or Stock, Column [D], include the unvested portion of performance shares which may be settled in either stock or cash depending on whether the officer has achieved 125% of their stock ownership requirement, and phantom shares held in a non-qualified deferred compensation plan which will be settled in cash on a 1 for 1 basis upon retirement or termination. |
| 4. | Mr. Bemis’s share totals are as of January 31, 2004, the last day of his employment. |
| 5. | Beneficial ownership, shown in Column [C], of directors and executive officers as a group represents less than 1% of the outstanding shares of Exelon common stock. |
No PECO securities are authorized for issuance under equity compensation plans. For information about Exelon securities authorized for issuance to PECO employees under Exelon equity compensation plans, see above under “Exelon – Securities Authorized Under Equity Compensation Plans.”
452
Generation is a wholly owned indirect subsidiary of Exelon and has no voting securities. The following table presents the beneficial ownership as of December 31, 2004 of Exelon’s common stock by (1) Generation’s executive officers named in the Summary Compensation Table, and (2) all named officers and executive officers of Generation as a group.
Beneficial Ownership Table
| [A] Beneficially (See Note 1) |
[B] Shares Held in Company Plans (See Note 2) |
[C] = [A] + [B] Total Shares Held |
[D] Share Equivalents to be Settled in Cash or Stock (See Note 3) |
[E] = [C] +[D] Total Share Interest | ||||||
| Named Officers |
||||||||||
| Oliver D. Kingsley, Jr. |
740,085 | — | 740,085 | 6,499 | 746,584 | |||||
| John F. Young |
39,390 | 14,684 | 54,074 | 10,943 | 65,017 | |||||
| John W. Rowe |
2,260,708 | 313,646 | 2,574,354 | 86,942 | 2,661,296 | |||||
| Robert S. Shapard |
96,000 | 69,702 | 165,702 | 14,813 | 180,515 | |||||
| Christopher M. Crane |
237,047 | 57,219 | 294,266 | 11,352 | 305,618 | |||||
| Ian P. McLean |
290,135 | 16,464 | 306,599 | 14,488 | 321,087 | |||||
| John L. Skolds |
327,160 | 94,252 | 421,412 | 20,329 | 441,741 | |||||
| Named & Executive Officers as a group, 9 people. (See Note 4) |
3,824,277 | 530,030 | 4,354,307 | 164,021 | 4,518,328 |
| 1. | The shares listed above under Beneficially Owned Shares, Column [A], include shares that may be acquired from non-qualified stock options that are fully vested or that vest within 60 days of January 31, 2005. |
| 2. | The shares listed above under Shares Held in Company Plans, Column [B], include restricted shares, deferred shares, shares held in the 401(k) plan, and shares that may be acquired from all unvested, non-qualified stock options that are not included in Column [A]. |
| 3. | The shares listed above under Equivalent Shares to be Settled in Cash or Stock, Column [D], include the unvested portion of performance shares which may be settled in either stock or cash depending on whether the officer has achieved 125% of their stock ownership requirement, and phantom shares held in a non-qualified deferred compensation plan which will be settled in cash on a 1 for 1 basis upon retirement or termination. |
| 4. | Beneficial ownership, shown in Column [C], of named and executive officers as a group represents less than 1% of the outstanding shares of Exelon common stock. |
No Generation Securities are authorized for issuance under equity compensation plans. For information about Exelon Securities Authorized for issuance to Generation employees under Exelon equity compensation plans, see above under “Exelon Securities Authorized Under Equity Compensations Plans.”
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
Pamela B. Strobel is an Executive Vice President of Exelon, and until April 2003 was the Vice Chair and Chief Executive Officer of Exelon Energy Delivery Company, the Chairman of Commonwealth Edison Company and PECO Energy Company, all of which are subsidiaries of Exelon. Ms. Strobel’s husband, Russ M. Strobel, was elected President of Nicor Inc. in October 2002 and Chief Executive Officer of Nicor Gas, a subsidiary of Nicor, in November 2003, and was appointed to the board of directors of Nicor and Nicor Gas in January 2004. Since January 1, 2004, Nicor Gas and ComEd have been parties to the following transactions, proposed transactions or business dealings:
| – | Nicor Gas and ComEd are parties to an interim agreement approved by the Illinois Commerce Commission under which they cooperate in cleaning up residue at former manufactured gas plant sites. Under the interim agreement, costs are split evenly between Nicor Gas and ComEd, except that if they cannot agree upon a final allocation of costs, the interim agreement provides for arbitration. For the year 2004, Nicor Gas billed ComEd $1,511,794 and ComEd billed Nicor Gas $13,730,041. For year 2005, ComEd estimates that Nicor |
453
| Gas will bill ComEd approximately $3,750,000 and that ComEd will bill Nicor Gas approximately $8,520,000. |
| – | Nicor Gas and Exelon Power Team are parties to an agreement entered into in May 2000 and expiring in May 2005, pursuant to which Nicor Gas transports gas to an electric generating station in Rockford, Illinois. In 2004, Exelon Power Team made $2,057,966 in payments under this agreement, and estimates that it will make payments of approximately $2,000,000 to Nicor Gas in 2005. |
Blank Rome LLP provided legal services to Exelon during 2004 and 2003. Mr. Diaz, a member of the Exelon board of directors, became a partner of Blank Rome LLP in March 2004.
None.
ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES
In July 2002, the Exelon Audit Committee adopted a policy for pre-approval of services to be performed by the independent accountants. The committee pre-approves annual budgets for audit, audit-related and tax compliance and planning services. The services that the committee will consider include services that do not impair the accountant’s independence and add value to the audit, including audit services such as attest services and scope changes in the audit of the financial statements, audit-related services such as accounting advisory services related to proposed transactions and new accounting pronouncements, the issuance of comfort letters and consents in relation to financings, the provision of attest services in relation to regulatory filings and contractual obligations, and tax compliance and planning services. With respect to non-budgeted services in amounts less than $500,000, the committee delegated authority to the committee’s chairman to pre-approve such services. All other services must be pre-approved by the committee. The committee receives quarterly reports on all fees paid to the independent accountants. None of the services provided by the independent accountants was provided pursuant to the de minimis exception to the pre-approval requirements contained in the SEC’s rules.
The following table presents fees for professional audit services rendered by PricewaterhouseCoopers LLP for the audit of Exelon’s annual financial statements for the years ended December 31, 2004 and 2003, and fees billed for other services rendered by PricewaterhouseCoopers LLP during those periods. Fees include amounts related to the year indicated, which may differ from amounts billed. Information for 2003 has been adjusted for comparative purposes.
| Year Ended December 31, | ||||||
| (in thousands) |
2004 |
2003 | ||||
| Audit fees |
$ | 6,578 | $ | 3,969 | ||
| Audit related fees(a) |
2,128 | 2,394 | ||||
| Tax fees(b) |
594 | 421 | ||||
| All other fees(c) |
45 | 60 | ||||
| (a) | Audit related fees consist of assurance and related services that are reasonably related to the performance of the audit or review of Exelon’s financial statements. This category includes fees for accounting assistance and due diligence in connection with proposed acquisitions or sales, employee benefit plan audits, internal control reviews, and consultations concerning financial accounting and reporting standards. |
| (b) | Tax fees consist of the aggregate fees billed for professional services rendered by PricewaterhouseCoopers LLP for tax compliance, tax advice, and tax planning. These services included tax compliance and preparation services, including the preparation of original and amended tax returns, claims for refunds, and tax payment planning, and tax advice and consulting services, including assistance and representation in connection with tax audits and appeals, tax advice related to proposed acquisitions or sales, employee benefit plans and requests for rulings or technical advice from taxing authorities. |
| (c) | All other fees reflect work performed primarily in connection with corporate executive programs. |
454
ComEd, PECO and Generation
ComEd, PECO and Generation are indirect controlled subsidiaries of Exelon and do not have separate audit committees. Instead, that function is fulfilled for these companies by the Exelon Audit Committee. In July 2002, the Exelon Audit Committee adopted a policy for pre-approval of services to be performed by the independent accountants. The committee pre-approves annual budgets for audit, audit-related and tax compliance and planning services. The services that the committee will consider include services that do not impair the accountant’s independence and add value to the audit, including audit services such as attest services and scope changes in the audit of the financial statements, audit-related services such as accounting advisory services related to proposed transactions and new accounting pronouncements, the issuance of comfort letters and consents in relation to financings, the provision of attest services in relation to regulatory filings and contractual obligations, and tax compliance and planning services. With respect to non-budgeted services in amounts less than $500,000, the committee delegated authority to the committee’s chairman to pre-approve such services. All other services must be pre-approved by the committee. The committee receives quarterly reports on all fees paid to the independent accountants. None of the services provided by the independent accountants was provided pursuant to the de minimis exception to the pre-approval requirements contained in the SEC’s rules.
The following tables present fees for professional audit services rendered by PricewaterhouseCoopers LLP for the audit of ComEd’s, PECO’s and Generation’s annual financial statements for the years ended December 31, 2004 and 2003, and fees billed for other services rendered by PricewaterhouseCoopers LLP during those periods. These fees include an allocation of amounts billed directly to Exelon Corporation. Fees include amounts related to the year indicated, which may differ from amounts billed. Information for 2003 has been adjusted for comparative purposes.
| Year Ended December 31, | ||||||
| (in thousands) |
2004 |
2003 | ||||
| Audit fees |
$ | 2,157 | $ | 1,008 | ||
| Audit related fees(a) |
13 | 217 | ||||
| Tax fees(b) |
24 | 343 | ||||
| All other fees |
6 | 1 | ||||
| (a) | Audit related fees consist of assurance and related services that are reasonably related to the performance of the audit or review of ComEd’s financial statements. This category includes fees for regulatory work, depreciation studies and internal control projects. |
| (b) | Tax fees consist of the aggregate fees billed for professional services rendered by PricewaterhouseCoopers LLP for tax compliance, tax advice, and tax planning. |
455
| Year Ended December 31, | ||||||
| (in thousands) |
2004 |
2003 | ||||
| Audit fees |
$ | 1,275 | $ | 491 | ||
| Audit related fees (a) |
28 | 266 | ||||
| Tax fees (b) |
526 | 10 | ||||
| All other fees |
4 | 1 | ||||
| (a) | Audit related fees consist of assurance and related services that are reasonably related to the performance of the audit or review of PECO’s financial statements. This category includes fees for regulatory work, depreciation studies and internal control projects. |
| (b) | Tax fees consist of the aggregate fees billed for professional services rendered by PricewaterhouseCoopers LLP for tax compliance, tax advice, tax planning and tax advice and consulting services in connection with appeals claims. |
| Year Ended December 31, | ||||||
| (in thousands) |
2004 |
2003 | ||||
| Audit fees |
$ | 2,566 | $ | 1,641 | ||
| Audit related fees (a) |
84 | 467 | ||||
| Tax fees (b) |
38 | 51 | ||||
| All other fees |
7 | 2 | ||||
| (a) | Audit related fees consist of assurance and related services that are reasonably related to the performance of the audit or review of Generation’s financial statements. This category includes fees for purchase accounting reviews, audits of employee benefit plans and internal control projects. |
| (b) | Tax fees consist of the aggregate fees billed for professional services rendered by PricewaterhouseCoopers LLP for tax compliance, tax advice, and tax planning. |
456
PART IV
ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES
| (a) |
FinancialStatements and Financial Statement Schedules | |||
| (1) |
Exelon | |||
| (i) |
Financial Statements | |||
| Consolidated Statements of Income for the years 2004, 2003 and 2002 | ||||
| Consolidated Statements of Cash Flows for the years 2004, 2003 and 2002 | ||||
| Consolidated Balance Sheets as of December 31, 2004 and 2003 | ||||
| Consolidated Statements of Changes in Shareholders’ Equity for the years 2004, 2003 and 2002 | ||||
| Consolidated Statements of Comprehensive Income for the years 2004, 2003 and 2002 | ||||
| Notes to Consolidated Financial Statements | ||||
| (ii) |
Financial Statement Schedule | |||
457
EXELON CORPORATION AND SUBSIDIARY COMPANIES
Schedule II – Valuation and Qualifying Accounts
(in millions)
| Column A |
Column B |
Column C |
Column D |
Column E | |||||||||||||
| Additions and adjustments |
|||||||||||||||||
| Description |
Balance at Beginning of Year |
Charged and |
Charged to Other Accounts |
Deductions |
Balance at End of Year | ||||||||||||
| For The Year Ended December 31, 2004 |
|||||||||||||||||
| Allowance for uncollectible accounts |
$ | 110 | $ | 86 | $ | 3 | $ | 106 | (a) | $ | 93 | ||||||
| Reserve for obsolete materials |
$ | 18 | $ | 17 | $ | 1 | $ | 8 | $ | 28 | |||||||
| For The Year Ended December 31, 2003 |
|||||||||||||||||
| Allowance for uncollectible accounts |
$ | 132 | $ | 103 | $ | (9 | ) | $ | 116 | (a) | $ | 110 | |||||
| Reserve for obsolete materials |
$ | 18 | $ | 4 | $ | 1 | $ | 5 | $ | 18 | |||||||
| For The Year Ended December 31, 2002 |
|||||||||||||||||
| Allowance for uncollectible accounts |
$ | 213 | $ | 129 | $ | — | $ | 210 | (a) | $ | 132 | ||||||
| Reserve for obsolete materials |
$ | 18 | $ | 9 | $ | 4 | $ | 13 | $ | 18 | |||||||
| (a) | Write-off of individual accounts receivable. |
458
| (2) | ComEd | |||
| (i) | Financial Statements | |||
| Consolidated Statements of Income for the years 2004, 2003 and 2002 | ||||
| Consolidated Statements of Cash Flows for the years 2004, 2003 and 2002 | ||||
| Consolidated Balance Sheets as of December 31, 2004 and 2003 | ||||
| Consolidated Statements of Changes in Shareholders’ Equity for the years 2004, 2003 and 2002 | ||||
| Consolidated Statements of Comprehensive Income for the years 2004, 2003 and 2002 | ||||
| Notes to Consolidated Financial Statements | ||||
| (ii) | Financial Statement Schedule | |||
459
COMMONWEALTH EDISON COMPANY AND SUBSIDIARY COMPANIES
Schedule II – Valuation and Qualifying Accounts
(in millions)
| Column A |
Column B |
Column C |
Column D |
Column E | |||||||||||||
| Additions and adjustments |
|||||||||||||||||
| Description |
Balance at Beginning of Year |
Charged and |
Charged to Other Accounts |
Deductions |
Balance at End of Year | ||||||||||||
| For The Year Ended December 31, 2004 |
|||||||||||||||||
| Allowance for uncollectible accounts |
$ | 16 | $ | 37 | $ | — | $ | 37 | (a) | $ | 16 | ||||||
| Reserve for obsolete materials |
$ | 8 | $ | (1 | ) | $ | 1 | $ | 5 | $ | 3 | ||||||
| For The Year Ended December 31, 2003 |
|||||||||||||||||
| Allowance for uncollectible accounts |
$ | 24 | $ | 46 | $ | — | $ | 54 | (a) | $ | 16 | ||||||
| Reserve for obsolete materials |
$ | 5 | $ | 4 | $ | — | $ | 1 | $ | 8 | |||||||
| For The Year Ended December 31, 2002 |
|||||||||||||||||
| Allowance for uncollectible accounts |
$ | 49 | $ | 50 | $ | — | $ | 75 | (a) | $ | 24 | ||||||
| Reserve for obsolete materials |
$ | 6 | $ | — | $ | — | $ | 1 | $ | 5 | |||||||
| (a) | Write-off of individual accounts receivable. |
460
| (3) |
PECO | |||
| (i) |
Financial Statements | |||
| Consolidated Statements of Income for the years 2004, 2003 and 2002 | ||||
| Consolidated Statements of Cash Flows for the years 2004, 2003 and 2002 | ||||
| Consolidated Balance Sheets as of December 31, 2004 and 2003 | ||||
| Consolidated Statements of Changes in Shareholders’ Equity for the years 2004, 2003 and 2002 | ||||
| Consolidated Statements of Comprehensive Income for the years 2004, 2003 and 2002 | ||||
| Notes to Consolidated Financial Statements | ||||
| (ii) |
Financial Statement Schedule | |||
461
PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES
Schedule II – Valuation and Qualifying Accounts
(in millions)
| Column A |
Column B |
Column C |
Column D |
Column E | ||||||||||||
| Additions and adjustments |
||||||||||||||||
| Description |
Balance at Beginning of Year |
Charged and Expenses |
Charged to Other Accounts |
Deductions |
Balance at End of Year | |||||||||||
| For The Year Ended December 31, 2004 |
||||||||||||||||
| Allowance for uncollectible accounts |
$ | 72 | $ | 46 | $ | 2 | $ | 68 | (a) | $ | 52 | |||||
| Reserve for obsolete materials |
$ | — | $ | 1 | $ | — | $ | — | $ | 1 | ||||||
| For The Year Ended December 31, 2003 |
||||||||||||||||
| Allowance for uncollectible accounts |
$ | 72 | $ | 52 | $ | 8 | $ | 60 | (a) | $ | 72 | |||||
| For The Year Ended December 31, 2002 |
||||||||||||||||
| Allowance for uncollectible accounts |
$ | 110 | $ | 45 | $ | — | $ | 83 | (a) | $ | 72 | |||||
| Reserve for obsolete materials |
$ | 1 | $ | — | $ | — | $ | 1 | $ | — | ||||||
| (a) | Write-off of individual accounts receivable. |
462
| (4) |
Generation | |||
| (i) |
Financial Statements | |||
| Consolidated Statements of Income for the years 2004, 2003 and 2002 | ||||
| Consolidated Statements of Cash Flow for the years 2004, 2003 and 2002 | ||||
| Consolidated Balance Sheets as of December 31, 2004 and 2003 | ||||
| Consolidated Statements of Changes in Membership Interest for the years 2004, 2003 and 2002 | ||||
| Consolidated Statements of Comprehensive Income for the years 2004, 2003 and 2002 | ||||
| Notes to Consolidated Financial Statements | ||||
| (ii) |
Financial Statement Schedule | |||
463
EXELON GENERATION COMPANY, LLC AND SUBSIDIARY COMPANIES
Schedule II – Valuation and Qualifying Accounts
(in millions)
| Column A |
Column B |
Column C |
Column D |
Column E | |||||||||||||
| Additions and adjustments |
|||||||||||||||||
| Description |
Balance at Beginning of Year |
Charged and |
Charged to Other Accounts |
Deductions |
Balance at End of Year | ||||||||||||
| For The Year Ended December 31, 2004 |
|||||||||||||||||
| Allowance for uncollectible accounts |
$ | 14 | $ | 2 | $ | 4 | $ | 1 | $ | 19 | |||||||
| Reserve for obsolete materials |
$ | 9 | $ | 18 | $ | — | $ | 3 | $ | 24 | |||||||
| For The Year Ended December 31, 2003 |
|||||||||||||||||
| Allowance for uncollectible accounts |
$ | 22 | $ | 1 | $ | (9 | ) | $ | — | $ | 14 | ||||||
| Reserve for obsolete materials |
$ | 13 | $ | 1 | $ | — | $ | 5 | $ | 9 | |||||||
| For The Year Ended December 31, 2002 |
|||||||||||||||||
| Allowance for uncollectible accounts |
$ | 17 | $ | 26 | $ | — | $ | 21 | (a) | $ | 22 | ||||||
| Reserve for obsolete materials |
$ | 12 | $ | 10 | $ | 3 | $ | 12 | $ | 13 | |||||||
| (a) | Write-off of individual accounts receivable. |
464
| (b) | Exhibits |
Certain of the following exhibits are incorporated herein by reference under Rule 12b-32 of the Securities and Exchange Act of 1934, as amended. Certain other instruments which would otherwise be required to be listed below have not been so listed because such instruments do not authorize securities in an amount which exceeds 10% of the total assets of the applicable registrant and its subsidiaries on a consolidated basis and the relevant registrant agrees to furnish a copy of any such instrument to the Commission upon request.
| Exhibit No. |
Description | |
| 2-1 | Amended and Restated Agreement and Plan of Merger dated as of October 20, 2000, among PECO Energy Company, Exelon Corporation and Unicom Corporation (File No. 1-01401, PECO Energy Company Form 10-Q for the quarter ended September 30, 2000, Exhibit 2-1). | |
| 2-2 | Agreement and Plan of Merger between Exelon Corporation and Public Service Enterprise Group Incorporated dated as of December 20, 2004 (File No. 1-16169, Form 8-K dated December 21, 2004, Exhibit 2.1). | |
| 3-1 | Articles of Incorporation of Exelon Corporation (Registration Statement No. 333-37082, Form S-4, Exhibit 3-1). | |
| 3-2 | Amendment to Articles of Incorporation of Exelon Corporation (File No. 1-16169, Form 10-Q for the quarter ended June 30, 2004, Exhibit 3-1). | |
| 3-3 | Amended and Restated Bylaws of Exelon Corporation, adopted January 27, 2004 (File No. 1-16169, 2003 Form 10-K Exhibit 3-2). | |
| 3-4 | Amended and Restated Articles of Incorporation of PECO Energy Company (File No. 1-01401, 2000 Form 10-K, Exhibit 3-3). | |
| 3-5 | Bylaws of PECO Energy Company, adopted February 26, 1990 and amended January 26, 1998 (File No. 1-01401, 1997 Form 10-K, Exhibit 3-2). | |
| 3-6 | Restated Articles of Incorporation of Commonwealth Edison Company effective February 20, 1985, including Statements of Resolution Establishing Series, relating to the establishment of three new series of Commonwealth Edison Company preference stock known as the “$9.00 Cumulative Preference Stock,” the “$6.875 Cumulative Preference Stock” and the “$2.425 Cumulative Preference Stock” (File No. 1-1839, 1994 Form 10-K, Exhibit 3-2). | |
| 3-7 | Bylaws of Commonwealth Edison Company, effective September 2, 1998, as amended through October 20, 2000 (File No. 1-1839, 2000 Form 10-K, Exhibit 3-6). | |
| 3-8 | Certificate of Formation of Exelon Generation Company, LLC (Registration Statement No. 333-85496, Form S-4, Exhibit 3-1). | |
| 3-9 | First Amended and Restated Operating Agreement of Exelon Generation Company, LLC executed as of January 1, 2001 (File No. 333-85496, 2003 Form 10-K, Exhibit 3-8). | |
| 4-1 | First and Refunding Mortgage dated May 1, 1923 between The Counties Gas and Electric Company (predecessor to PECO Energy Company) and Fidelity Trust Company, Trustee (First Union National Bank, successor), (Registration No. 2-2281, Exhibit B-1). | |
465
| Exhibit No. |
Description | |||||
| 4-1-1 | Supplemental Indentures to PECO Energy Company’s First and Refunding Mortgage: | |||||
| Dated as of |
File Reference |
Exhibit No. | ||||
| May 1, 1927 | 2-2881 | B-1(c) | ||||
| March 1, 1937 | 2-2881 | B-1(g) | ||||
| December 1, 1941 | 2-4863 | B-1(h) | ||||
| November 1, 1944 | 2-5472 | B-1(i) | ||||
| December 1, 1946 | 2-6821 | 7-1(j) | ||||
| September 1, 1957 | 2-13562 | 2(b)-17 | ||||
| May 1, 1958 | 2-14020 | 2(b)-18 | ||||
| March 1, 1968 | 2-34051 | 2(b)-24 | ||||
| March 1, 1981 | 2-72802 | 4-46 | ||||
| March 1, 1981 | 2-72802 | 4-47 | ||||
| December 1, 1984 | 1-01401, 1984 Form 10-K | 4-2(b) | ||||
| April 1, 1991 | 1-01401, 1991 Form 10-K | 4(e)-76 | ||||
| December 1, 1991 | 1-01401, 1991 Form 10-K | 4(e)-77 | ||||
| June 1, 1992 | 1-01401, June 30, 1992 Form 10-Q | 4(e)-81 | ||||
| March 1, 1993 | 1-01401, 1992 Form 10-K | 4(e)-86 | ||||
| May 1, 1993 | 1-01401, March 31, 1993 Form 10-Q | 4(e)-88 | ||||
| May 1, 1993 | 1-01401, March 31, 1993 Form 10-Q | 4(e)-89 | ||||
| August 15, 1993 | 1-01401, Form 8-A dated August 19, 1993 | 4(e)-92 | ||||
| May 1, 1995 | 1-01401, Form 8-K dated May 24, 1995 | 4(e)-96 | ||||
| September 15, 2002 | 1-01401, September 30, 2002 Form 10-Q | 4-1 | ||||
| October 1, 2002 | 1-01401, September 30, 2002 Form 10-Q | 4-2 | ||||
| April 15, 2003 | 0-16844, March 31, 2003 Form 10-Q | 4.1 | ||||
| April 15, 2004 | 0-16844, September 30, 2004 Form 10-Q | 4-1-1 | ||||
| 4-2 | Exelon Corporation Dividend Reinvestment and Stock Purchase Plan (Registration Statement No. 333-84446, Form S-3, Prospectus). | |||||
| 4-3 | Mortgage of Commonwealth Edison Company to Illinois Merchants Trust Company, Trustee (BNY Midwest Trust Company, as current successor Trustee), dated July 1, 1923, as supplemented and amended by Supplemental Indenture thereto dated August 1, 1944. (File No. 2-60201, Form S-7, Exhibit 2-1). | |||||
| 4-3-1 | Supplemental Indentures to aforementioned Commonwealth Edison Mortgage. | |||||
| Dated as of |
File Reference |
Exhibit No. | ||||
| August 1, 1946 | 2-60201, Form S-7 | 2-1 | ||||
| April 1, 1953 | 2-60201, Form S-7 | 2-1 | ||||
| March 31, 1967 | 2-60201, Form S-7 | 2-1 | ||||
| April 1,1967 | 2-60201, Form S-7 | 2-1 | ||||
| February 28, 1969 | 2-60201, Form S-7 | 2-1 | ||||
| May 29, 1970 | 2-60201, Form S-7 | 2-1 | ||||
| June 1, 1971 | 2-60201, Form S-7 | 2-1 | ||||
| April 1, 1972 | 2-60201, Form S-7 | 2-1 | ||||
| May 31, 1972 | 2-60201, Form S-7 | 2-1 | ||||
| June 15, 1973 | 2-60201, Form S-7 | 2-1 | ||||
| May 31, 1974 | 2-60201, Form S-7 | 2-1 | ||||
| June 13, 1975 | 2-60201, Form S-7 | 2-1 | ||||
| May 28, 1976 | 2-60201, Form S-7 | 2-1 | ||||
| June 3, 1977 | 2-60201, Form S-7 | 2-1 | ||||
| May 17, 1978 | 2-99665, Form S-3 | 4-3 | ||||
466
| Exhibit No. |
Description | |||||
| Dated as of |
File Reference |
Exhibit No. | ||||
| August 31, 1978 | 2-99665, Form S-3 | 4-3 | ||||
| June 18, 1979 | 2-99665, Form S-3 | 4-3 | ||||
| June 20, 1980 | 2-99665, Form S-3 | 4-3 | ||||
| April 16, 1981 | 2-99665, Form S-3 | 4-3 | ||||
| April 30, 1982 | 2-99665, Form S-3 | 4-3 | ||||
| April 15, 1983 | 2-99665, Form S-3 | 4-3 | ||||
| April 13, 1984 | 2-99665, Form S-3 | 4-3 | ||||
| April 15, 1985 | 2-99665, Form S-3 | 4-3 | ||||
| April 15, 1986 | 33-6879, Form S-3 | 4-9 | ||||
| June 15, 1990 | 33-38232, Form S-3 | 4-12 | ||||
| October 1, 1991 | 33-40018, Form S-3 | 4-13 | ||||
| October 15, 1991 | 33-40018, Form S-3 | 4-14 | ||||
| May 15, 1992 | 33-48542, Form S-3 | 4-14 | ||||
| September 15, 1992 | 33-53766, Form S-3 | 4-14 | ||||
| February 1, 1993 | 1-1839, 1992 Form 10-K | 4-14 | ||||
| April 1, 1993 | 33-64028, Form S-3 | 4-12 | ||||
| April 15, 1993 | 33-64028, Form S-3 | 4-13 | ||||
| June 15, 1993 | 1-1839, Form 8-K dated May 21, 1993 | 4-1 | ||||
| July 15, 1993 | 1-1839, Form 10-Q for quarter ended June 30, 1993. | 4-1 | ||||
| January 15, 1994 | 1-1839, 1993 Form 10-K | 4-15 | ||||
| December 1, 1994 | 1-1839, 1994 Form 10-K | 4-16 | ||||
| June 1, 1996 | 1-1839, 1996 Form 10-K | 4-16 | ||||
| March 1, 2002 May 20, 2002 June 1, 2002 October 7, 2002 |
1-1839, 2001 Form 10-K | 4-4-1 | ||||
| January 13, 2003 | 1-1839, Form 8-K dated January 22, 2003 | 4-4 | ||||
| March 14, 2003 | 1-1839, Form 8-K dated April 7, 2003 | 4-4 | ||||
| August 13, 2003 | 1-1839, Form 8-K dated August 25, 2003 | 4-4 | ||||
| 4-3-2 | Instrument of Resignation, Appointment and Acceptance dated as of February 20, 2002, under the provisions of the Mortgage dated July 1, 1923, and Indentures Supplemental thereto, regarding corporate trustee (File No. 1-1839, 2001 Form 10-K, Exhibit 4-4-2). | |||||
| 4-3-3 | Instrument dated as of January 31, 1996, under the provisions of the Mortgage dated July 1, 1923 and Indentures Supplemental thereto, regarding individual trustee (File No. 1-1839, 1995 Form 10-K, Exhibit 4-29). | |||||
| 4-4 | Indenture dated as of September 1, 1987 between Commonwealth Edison Company and Citibank, N.A., Trustee relating to Notes (File No. 1-1839, Form S-3, Exhibit 4-13). | |||||
| 4-4-1 | Supplemental Indentures to aforementioned Indenture. | |||||
| Dated as of |
File Reference |
Exhibit No. | ||||
| September 1, 1987 | 33-32929, Form S-3 | 4-16 | ||||
| January 1, 1997 | 1-1839, 1999 Form 10-K | 4-21 | ||||
| September 1, 2000 | 1-1839, 2000 Form 10-K | 4-7-3 | ||||
| 4-5 | Indenture dated June 1, 2001 between Generation and First Union National Bank (now Wachovia Bank, National Association) (Registration Statement No. 333-85496, Form S-4, Exhibit 4.1). | |||||
| 4-6 | Indenture dated December 19, 2003 between Generation and Wachovia Bank, National Association (File No. 333-85496, 2003 Form 10-K, Exhibit 4-6). | |||||
467
| Exhibit No. |
Description | |
| 4-7 | Indenture to Subordinated Debt Securities dated as of June 24, 2003 between PECO Energy Company, as Issuer, and Wachovia Bank National Association, as Trustee (File No. 0-16844, PECO Energy Company Form 10-Q for the quarter ended June 30, 2003, Exhibit 4.1). | |
| 4-8 | Preferred Securities Guarantee Agreement between PECO Energy Company, as Guarantor, and Wachovia Trust Company, National Association, as Trustee, dated as of June 24, 2003 (File No. 0-16844, PECO Energy Company Form 10-Q for the quarter ended June 30, 2003, Exhibit 4.2). | |
| 4-9 | PECO Energy Capital Trust IV Amended and Restated Declaration of Trust among PECO Energy Company, as Sponsor, Wachovia Trust Company, National Association, as Delaware Trustee and Property Trustee, and J. Barry Mitchell, George R. Shicora and Charles S. Walls as Administrative Trustees dated as of June 24, 2003 (File No. 0-16844, PECO Energy Company Form 10-Q for the quarter ended June 30, 2003, Exhibit 4.3). | |
| 10-1 | Stock Purchase Agreement among Exelon (Fossil) Holdings, Inc., as Buyer and The Stockholders of Sithe Energies, Inc., as Sellers, and Sithe Energies, Inc. (File No. 0-16844, PECO Energy Company Form 10-Q for the quarter ended September 30, 2000, Exhibit 10-1). | |
| 10-2 | Power Purchase Agreement among Generation and PECO (Registration Statement No. 333-85496, Form S-4, Exhibit 10.1). | |
| 10-3 | Amended and Restated Power Purchase Agreement between Exelon Generation Company, LLC and Commonwealth Edison Company as of April 30, 2004 (File Nos. 1-01839 and 333-85496, Form 10-Q for quarter ended June 30, 2004, Exhibit 10-1). | |
| 10-4 | Amended and restated employment agreement between Exelon Corporation and John W. Rowe dated as of November 26, 2001* (File No. 1-16169, 2001 Form 10-K, Exhibit 10-2). | |
| 10-5 | Amended and restated employment agreement between Exelon Corporation, Exelon Generation Company, LLC and Oliver D. Kingsley, Jr. dated as of April 29, 2003. (File Nos. 1-16169 and 333-85496, 2003 Form 10-K, Exhibit 10-7).* | |
| 10-6 | Exelon Corporation Deferred Compensation Plan (File No. 1-16169, 2001 Form 10-K, Exhibit 10-3). | |
| 10-7 | Exelon Corporation Retirement Program (File No. 1-16169, 2001 Form 10-K, Exhibit 10-4). | |
| 10-8 | PECO Energy Company Unfunded Deferred Compensation Plan for Directors* (Registration Statement No. 333-49780, Form S-8, Exhibit 4-4). | |
| 10-9 | Exelon Corporation Long-Term Incentive Plan As Amended and Restated effective January 28, 2002* (File No. 1-16169, Exelon Proxy Statement dated March 13, 2002, Appendix B). | |
| 10-10-1 | Form of Restricted Stock Award Agreement under the Exelon Corporation Long-Term Incentive Plan* (File No. 1-16169, 2001 Form 10-K, Exhibit 10-6-1). | |
| 10-10-2 | Forms of Transferable Stock Option Award Agreement under the Exelon Corporation Long-Term Incentive Plan* (File No. 1-16169, 2001 Form 10-K, Exhibit 10-6-2). | |
| 10-10-3 | Forms of Stock Option Award Agreement under the Exelon Corporation Long-Term Incentive Plan* (File No. 1-16169, 2001 Form 10-K, Exhibit 10-6-3). | |
| 10-11 | PECO Energy Company Management Incentive Compensation Plan *(File No. 1-01401, 1997 Proxy Statement, Appendix A). | |
| 10-12 | PECO Energy Company 1998 Stock Option Plan* (Registration Statement No. 333-37082, Post-Effective Amendment No. 1 to Form S-4, Exhibit 4-3). | |
468
| Exhibit No. |
Description | |
| 10-13 | Exelon Corporation Employee Savings Plan. | |
| 10-14 | Second Amended and Restated Trust Agreement for PECO Energy Transition Trust (File No. 333-58055, PECO Energy Transition Trust Report on Form 8-K dated May 2, 2000, Exhibit 4.1). | |
| 10-15 | Indenture dated as of March 1, 1999 between PECO Energy Transition Trust and The Bank of New York. (File No. 333-58055, PECO Energy Transition Trust Report on Form 8-K dated March 25, 1999, Exhibit 4.3.1). | |
| 10-15-1 | Series Supplement dated as of March 25, 1999 between PECO Energy Transition Trust and The Bank of New York. (File No. 333-58055, PECO Energy Transition Trust Report on Form 8-K dated March 25, 1999, Exhibit 4.3.2). | |
| 10-15-2 | Series Supplement dated as of March 1, 2001 between PECO Energy Transition Trust and The Bank of New York. (File No. 333-58055, PECO Energy Transition Trust Report on Form 8-K dated March 1, 2001, Exhibit 4.3.2). | |
| 10-15-3 | Series Supplement dated as of May 2, 2000 between PECO Energy Transition Trust and The Bank of New York (File No. 333-58055, PECO Energy Transition Trust Report on Form 8-K dated May 2, 2000, Exhibit 4.3.2). | |
| 10-16 | Intangible Transition Property Sale Agreement dated as of March 25,1999, as amended and restated as of May 2, 2000, between PECO Energy Transition Trust and PECO Energy Company. (File No. 333-58055, PECO Energy Transition Trust Report on Form 8-K dated May 2, 2000, Exhibit 10.1). | |
| 10-16-1 | Amendment No. 1 to Intangible Transition Property Sale Agreement dated as of March 25, 1999, as amended and restated as of May 2, 2000 (File No. 1-01401, PECO Energy Company and PECO Energy Transition Trust Report on Form 8-K dated March 1, 2001). | |
| 10-17 | Master Servicing Agreement dated as of March 25, 1999, as amended and restated as of May 2, 2000, between PECO Energy Transition Trust and PECO Energy Company. (File No. 333-58055, PECO Energy Transition Trust Current Report on Form 8-K dated May 2, 2000, Exhibit 10.2). | |
| 10-17-1 | Amendment No. 1 to Master Servicing Agreement dated as of March 25, 1999, as amended and restated as of May 2, 2000 (File No. 1-01401, PECO Energy Company and PECO Energy Transition Trust Report on Form 8-K dated March 1, 2001). | |
| 10-18 | Exelon Corporation Cash Balance Pension Plan (File No. 1-16169, 2001 Form 10-K, Exhibit 10-14). | |
| 10-19 | Joint Petition for Full Settlement of PECO Energy Company’s Restructuring Plan and Related Appeals and Application for a Qualified Rate Order and Application for Transfer of Generation Assets dated April 29, 1998. (Registration Statement No. 333-58055, Exhibit 10.3). | |
| 10-20 | Joint Petition for Full Settlement of PECO Energy Company’s Application for Issuance of Qualified Rate Order Under Section 2812 of the Public Utility Code dated March 8, 2000 (Amendment No. 1 to Registration Statement No. 333-31646, Exhibit 10.4). | |
| 10-21 | Unicom Corporation Amended and Restated Long-Term Incentive Plan *(File No. 1-11375, Unicom Proxy Statement dated April 7, 1999, Exhibit A). | |
| 10-21-1 | First Amendment to Unicom Corporation Amended and Restated Long Term Incentive Plan *(Registration Statement No. 333-49780, Form S-8, Exhibit 4-8). | |
469
| Exhibit No. |
Description | |
| 10-21-2 | Second Amendment to Unicom Corporation Amended and Restated Long Term Incentive Plan *(Registration Statement No. 333-49780, Form S-8, Exhibit 4-9). | |
| 10-22 | Unicom Corporation General Provisions Regarding 1996 Stock Option Awards Granted under the Unicom Corporation and Long-Term Incentive Plan. *(File Nos. 1-11375 and 1-1839, 1996 Form 10-K, Exhibit 10-9). | |
| 10-23 | Unicom Corporation General Provisions Regarding 1996B Stock Option Awards Granted under the Unicom Corporation Long-Term Incentive Plan. *(File Nos. 1-11375 and 1-1839, 1996 Form 10-K, Exhibit 10-8). | |
| 10-24 | Unicom Corporation General Provisions Regarding Stock Option Awards Granted under the Unicom Corporation Long-Term Incentive Plan (Effective July 10, 1997) (File Nos. 1-11375 and 1-1839, 1999 Form 10-K, Exhibit 10-8). | |
| 10-25 | Unicom Corporation Deferred Compensation Unit Plan, as amended *(File Nos. 1-11375 and 1-1839, 1995 Form 10-K, Exhibit 10-12). | |
| 10-26 | Exelon Corporation Corporate Stock Deferral Plan* (File No. 1-16169, 2001 Form 10-K, Exhibit 10-22). | |
| 10-27 | Unicom Corporation Retirement Plan for Directors, as amended *(Registration Statement No. 333-49780, Form S-8, Exhibit 4-12). | |
| 10-28 | Commonwealth Edison Company Retirement Plan for Directors, as amended *(Registration Statement No. 333-49780, Form S-8, Exhibit 4-13). | |
| 10-29 | Unicom Corporation 1996 Directors’ Fee Plan *(File No. 1-11375, Unicom Proxy Statement dated April 8, 1996, Appendix A). | |
| 10-29-1 | Second Amendment to Unicom Corporation 1996 Directors Fee Plan *(Registration Statement No. 333-49780, Form S-8, Exhibit 4-11). | |
| 10-30 | Change in Control Agreement between Unicom Corporation, Commonwealth Edison Company and certain senior executives * (File Nos. 1-11375 and 1-1839, 1998 Form 10-K, Exhibit 10-24). | |
| 10-30-1 | Forms of Change in Control Agreement Between PECO Energy Company and Certain Employees * (File No. 1-1401, 2000 Form 10-K, Exhibit 10-25-1). | |
| 10-31 | Commonwealth Edison Company Executive Group Life Insurance Plan* (File No. 1-1839, 1980 Form 10-K, Exhibit 10-3). | |
| 10-31-1 | Amendment to the Commonwealth Edison Company Executive Group Life Insurance Plan *(File No. 1-1839, 1981 Form 10-K, Exhibit 10-4). | |
| 10-31-2 | Amendment to the Commonwealth Edison Company Executive Group Life Insurance Plan dated December 12, 1986 *(File No. 1-1839, 1986 Form 10-K, Exhibit 10-6). | |
| 10-31-3 | Amendment to the Commonwealth Edison Company Executive Group Life Insurance Plan to implement program of “split dollar life insurance” dated December 13, 1990 *(File No. 1-1839, 1990 Form 10-K, Exhibit 10-10). | |
| 10-31-4 | Amendment to Commonwealth Edison Company Executive Group Life Insurance Plan to stabilize the death benefit applicable to participants dated July 22, 1992 *(File No. 1-1839, 1992 Form 10-K, Exhibit 10-13). | |
| 10-32 | Not used. | |
470
| Exhibit No. |
Description | |
| 10-32-1 | First Amendment to the Commonwealth Edison Company Supplemental Management Retirement Plan. * (File No. 1-1839, 2000 Form 10-K, Exhibit 10-27-1) | |
| 10-33 | Second Amendment and Restated Exelon Corporation Key Management Severance Plan* (File No. 1-16169, 2001 Form 10-K, Exhibit 10-30). | |
| 10-34 | Forms of Change in Control Agreement between Exelon Corporation and certain senior executives (File No. 1-16169, 2001 Form 10-K, Exhibit 10-31). | |
| 10-35 | Amendment No. 1 to Exelon Corporation Supplemental Management Retirement Plan* (File No. 1-16169, 2001 Form 10-K, Exhibit 10-32). | |
| 10-36 | Form of Stock Award Agreement under the Unicom Corporation Long-Term Incentive Plan *(File Nos. 1-11375 and 1-1839, 1997 Form 10-K, Exhibit 10-37). | |
| 10-37 | Amended and Restated Key Management Severance Plan for Unicom Corporation and Commonwealth Edison Company dated March 8, 1999 * (File No. 1-1839, 1999 Form 10-K, Exhibit 10-38). | |
| 10-37-1 | Exelon Corporation Employee Stock Purchase Plan (Registration Statement No. 333-61390, Form S-8, Exhibit 4.2). | |
| 10-37-2 | First Amendment to the Exelon Corporation Employee Stock Purchase Plan (File No. 1-16169, 2001 Form 10-K, Exhibit 10-34-2). | |
| 10-38 | PECO Energy Company Supplemental Pension Benefit Plan (As Amended and Restated January 1, 2001)* (File No. 1-1401, 2001 Form 10-K, Exhibit 10-35). | |
| 10-39 | Exelon Corporation 2001 Performance Share Awards for Power Team Employees under the Exelon Corporation Long Term Incentive Plan* (File No. 1-16169, 2001 Form 10-K, Exhibit 10-36). | |
| 10-40 | Agreement Regarding Various Matters Involving or Affecting Rates for Electric Service Offered by Commonwealth Edison Company dated as of March 3, 2003 among Commonwealth Edison Company and the other parties named therein (File No. 1-16169, Commonwealth Edison Company 2002 Form 10-K, Exhibit 10-41). | |
| 10-40-1 | Amendment dated as of March 10, 2003 to the Agreement Regarding Various Matters Involving or Affecting Rates for Electric Service Offered by Commonwealth Edison Company (File No. 1-16169, Commonwealth Edison Company 2002 Form 10-K, Exhibit 10-41-1). | |
| 10-41 | Retirement and Separation between Exelon Corporation, PECO Energy Company and Kenneth G. Lawrence, dated as of May 11, 2003 (File No. 0-16844, PECO Energy Company September 30, 2003 Form 10-Q, Exhibit 10.1). | |
| 10-42 | Purchase and Sale Agreement dated as of October 10, 2003 between British Energy Investment Ltd. and Exelon Generation Company, LLC relating to the sale and purchase of 100% of the shares of British Energy US Holdings Inc. (File Nos. 1-16169 and 333-85496, Exelon Corporation and Exelon Generation Company, LLC September 30, 2003 Form 10-Q, Exhibit 10.2). | |
| 10-43 | $1,000,000,000 Five Year Credit Agreement dated as of July 16, 2004 among Exelon Corporation, Commonwealth Edison Company, PECO Energy Company and Exelon Generation Company, LLC as Borrowers and Various Financial Institutions as Lenders (Form 10-Q for quarter ended June 30, 2004, Exhibit 10-2). | |
| 10-43-1 | $750,000,000 Three Year Credit Agreement dated as of October 31, 2003 among Exelon Corporation, Commonwealth Edison Company, PECO Energy Company and Exelon Generation Company, LLC as Borrowers and Various Financial Institutions as Lenders (2003 Form 10-K, Exhibit 10-44-1). | |
471
| Exhibit No. |
Description | |
| 10-43-2 | First Amendment dated as of July 16, 2004 to Three Year Credit Agreement dates as of October 31, 2003 among Exelon Corporation, Commonwealth Edison Company, PECO Energy Company and Exelon Generation Company, LLC, various financial institutions and Bank One, NA, as administrative agent (Form 10-Q for quarter ended June 30, 2004, Exhibit 10-3). | |
| 10-44 | $850,000,000 Credit Agreement dated as of September 29, 2003 among Exelon Generation Company, LLC as Borrower and Various Financial Institutions as Lenders (File No. 333-85496, 2003 Form 10-K, Exhibit 10-45). | |
| 10-45 | Michael B. Bemis separation letter, dated December 19, 2003. (File Nos. 1-01839 and 0-16844, Commonwealth Edison Company and PECO Energy Company, Form 10-Q for quarter ended March 31, 2004, Exhibit 10.1). | |
| 10-46 | Letter Agreement dated November 1, 2004 between Exelon Corporation and Oliver D. Kingsley, Jr. | |
| 10-47 | First Amendment to Employment Agreement between Exelon Corporation and John W. Rowe dated as of December 20, 2004 (File No. 1-16169, Form 8-K dated December 21, 2004, Exhibit 10.1). | |
| 10-48 | Exelon Corporation Senior Management Severance Plan (as amended through September 1, 2004). | |
| 10-49 | Exelon Corporation Annual Incentive Plan for Senior Executives (effective January 1, 2004). | |
| 10-50 | Form of change in control employment agreement for Senior Executives newly eligible or promoted after January 1, 2004. | |
| 10-51 | Form of change in control employment agreement (amended and restated as of May 1, 2004). | |
| 10-52 | Amendment One to Exelon Corporation Deferred Compensation Plan. | |
| 10-53 | Amendment Two to Exelon Corporation Supplemental Management Retirement Plan. | |
| 10-54 | Restatement of the Exelon Corporation Employee Stock Purchase Plan effective May 1, 2004 and Appendix One thereto. | |
| 14 | Exelon Code of Conduct | |
| Subsidiaries | ||
| 21-1 | Exelon Corporation | |
| 21-2 | Commonwealth Edison Company | |
| 21-3 | PECO Energy Company | |
| 21-4 | Exelon Generation Company, LLC | |
| Consent of Independent Auditors | ||
| 23-1 | Exelon Corporation | |
| 23-2 | Commonwealth Edison Company | |
| 23-3 | PECO Energy Company | |
| Power of Attorney | ||
| 24-1 | Edward A. Brennan | |
| 24-2 | M. Walter D’Alessio | |
472
| Exhibit No. |
Description | |
| 24-3 | Nicholas DeBenedictis | |
| 24-4 | Bruce DeMars | |
| 24-5 | Nelson A. Diaz | |
| 24-6 | Sue L. Gin | |
| 24-7 | Rosemarie B. Greco | |
| 24-8 | Edgar D. Jannotta | |
| 24-9 | John M. Palms, Ph.D. | |
| 24-10 | John W. Rogers, Jr. | |
| 24-11 | Ronald Rubin | |
| 24-12 | Richard L. Thomas | |
| Certifications Pursuant to Rule 13a-14(a) and 15d-14(a) of the Securities and Exchange Act of 1934 as to the Annual Report on Form 10-K for the year ended December 31, 2004 filed by the following officers for the following registrants: | ||
| 31-1 | Filed by John W. Rowe for Exelon Corporation | |
| 31-2 | Filed by Robert S. Shapard for Exelon Corporation | |
| 31-3 | Filed by John L. Skolds for Commonwealth Edison Company | |
| 31-4 | Filed by J. Barry Mitchell for Commonwealth Edison Company | |
| 31-5 | Filed by John L. Skolds for PECO Energy Company | |
| 31-6 | Filed by J. Barry Mitchell for PECO Energy Company | |
| 31-7 | Filed by John F. Young for Exelon Generation Company, LLC | |
| 31-8 | Filed by J. Barry Mitchell for Exelon Generation Company, LLC | |
| Certifications Pursuant to Section 1350 of Chapter 63 of Title 18 United States Code as to the Annual Report on Form 10-K for the year ended December 31, 2004 filed by the following officers for the following registrants: | ||
| 32-1 | Filed by John W. Rowe for Exelon Corporation | |
| 32-2 | Filed by Robert S. Shapard for Exelon Corporation | |
| 32-3 | Filed by John L. Skolds for Commonwealth Edison Company | |
| 32-4 | Filed by J. Barry Mitchell for Commonwealth Edison Company | |
| 32-5 | Filed by John L. Skolds for PECO Energy Company | |
| 32-6 | Filed by J. Barry Mitchell for PECO Energy Company | |
| 32-7 | Filed by John F. Young for Exelon Generation Company, LLC | |
| 32-8 | Filed by J. Barry Mitchell for Exelon Generation Company, LLC | |
| * | Compensatory plan or arrangements in which directors or officers of the applicable registrant participate and which are not available to all employees. |
473
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized, in the City of Chicago and State of Illinois on the 23rd day of February, 2005.
| EXELON CORPORATION | ||
| By: |
/s/ JOHN W. ROWE | |
| Name: | John W. Rowe | |
| Title: | Chairman, Chief Executive Officer and President | |
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed by the following persons on behalf of the registrant and in the capacities indicated on the 23rd day of February, 2005.
| Signature |
Title | |
| /s/ JOHN W. ROWE John W. Rowe |
Chairman, Chief Executive Officer and President (Principal Executive Officer) | |
| /s/ ROBERT S. SHAPARD Robert S. Shapard |
Executive Vice President and Chief Financial Officer (Principal Financial Officer) | |
| /s/ MATTHEW F. HILZINGER Matthew F. Hilzinger |
Vice President and Corporate Controller (Principal Accounting Officer) | |
This annual report has also been signed below by John W. Rowe, Attorney-in-Fact, on behalf of the following Directors on the date indicated:
| EDWARD A. BRENNAN | ROSEMARIE B. GRECO | |
| M. WALTER D’ALESSIO | EDGAR D. JANNOTTA | |
| NICHOLAS DEBENEDICTIS | JOHN M. PALMS, PHD. | |
| BRUCE DEMARS | JOHN W. ROGERS, JR. | |
| NELSON A. DIAZ | RONALD RUBIN | |
| SUE L. GIN | RICHARD L. THOMAS |
| By: |
/s/ JOHN W. ROWE |
February 23, 2005 | ||
| Name: | John W. Rowe | |||
| Title: | Chairman, Chief Executive Officer and President |
474
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized, in the City of Chicago and State of Illinois on the 23rd day of February, 2005.
| COMMONWEALTH EDISON COMPANY | ||
| By: |
/s/ JOHN W. ROWE | |
| Name: | John W. Rowe | |
| Title: | Chairman, Chief Executive Officer and President, Exelon, and Chair and Director | |
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed by the following persons on behalf of the registrant and in the capacities indicated on the 23rd day of February, 2005.
| Signature |
Title | |
| /s/ JOHN W. ROWE John W. Rowe |
Chairman, Chief Executive Officer and President, Exelon, and Chair and Director | |
| /s/ JOHN L. SKOLDS John L. Skolds |
President, Exelon Energy Delivery, and Director (Principal Executive Officer) | |
| /s/ J. BARRY MITCHELL J. Barry Mitchell |
Senior Vice President, Treasurer and Chief Financial Officer | |
| /s/ FRANK M. CLARK Frank M. Clark |
President and Director | |
| /s/ MATTHEW F. HILZINGER Matthew F. Hilzinger |
Vice President and Corporate Controller, Exelon (Principal Accounting Officer) | |
| /s/ ROBERT S. SHAPARD Robert S. Shapard |
Director | |
| /s/ S. GARY SNODGRASS S. Gary Snodgrass |
Director | |
475
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized, in the City of Chicago and State of Illinois on the 23rd day of February, 2005.
| By: |
/s/ JOHN W. ROWE | |
| Name: | John W. Rowe | |
| Title: | Chairman, Chief Executive Officer and President, Exelon, and Director | |
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed by the following persons on behalf of the registrant and in the capacities indicated on the 23rd day of February, 2005.
| Signature |
Title | |
| /s/ JOHN W. ROWE John W. Rowe |
Chairman, Chief Executive Officer and President, Exelon, and Director | |
| /s/ JOHN L. SKOLDS John L. Skolds |
President, Exelon Energy Delivery, and Director (Principal Executive Officer) | |
| /s/ J. BARRY MITCHELL J. Barry Mitchell |
Senior Vice President, Treasurer and Chief Financial Officer | |
| /s/ DENIS P. O’BRIEN Denis P. O’Brien |
President and Director | |
| /s/ MATTHEW F. HILZINGER Matthew F. Hilzinger |
Vice President and Corporate Controller, Exelon (Principal Accounting Officer) | |
| /s/ ROBERT S. SHAPARD Robert S. Shapard |
Director | |
476
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized, in the City of Chicago and State of Illinois on the 23rd day of February, 2005.
| By: |
/s/ JOHN W. ROWE | |
| Name: | John W. Rowe | |
| Title: | Chairman, Chief Executive Officer and President, Exelon | |
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed by the following persons on behalf of the registrant and in the capacities indicated on the 23rd day of February, 2005.
| Signature |
Title | |
| /s/ JOHN W. ROWE John W. Rowe |
Chairman, Chief Executive Officer and President, Exelon | |
| /s/ JOHN F. YOUNG John F. Young |
President (Principal Executive Officer) | |
| /s/ J. BARRY MITCHELL J. Barry Mitchell |
Senior Vice President, Treasurer and Chief Financial Officer | |
| /s/ JON D. VEURINK Jon D. Veurink |
Vice President and Controller | |
477
Exhibit 10.13
EXELON CORPORATION
EMPLOYEE SAVINGS PLAN
(Incorporating Amendment Nos. 1 through 6)
EXELON CORPORATION EMPLOYEE SAVINGS PLAN
TABLE OF CONTENTS
| Page | ||
| ARTICLE 1 |
1 | |
| TITLE, PURPOSE AND EFFECTIVE DATES |
1 | |
| ARTICLE 2 |
2 | |
| DEFINITIONS |
2 | |
| ARTICLE 3 |
7 | |
| PARTICIPATION |
7 | |
| Section 3.1. Eligibility for Participation |
7 | |
| Section 3.2. Applications for Before-Tax Contributions and After-Tax Contributions |
7 | |
| Section 3.3. Transfer to Affiliates |
9 | |
| ARTICLE 4 |
9 | |
| EMPLOYER CONTRIBUTIONS |
9 | |
| Section 4.1. Before-Tax Contributions |
9 | |
| Section 4.2. 402(g) Annual Limit on Before-Tax Contributions |
13 | |
| Section 4.3. Employer Matching Contributions |
15 | |
| Section 4.4. Limitations on Contributions for Highly-Compensated Eligible Employees |
17 | |
| Section 4.5. Limitation on Employer Contributions |
25 | |
| ARTICLE 5 |
26 | |
| EMPLOYEE CONTRIBUTIONS |
26 | |
| Section 5.1. After-Tax Contributions |
26 | |
| Section 5.2. Rollover Contributions |
27 | |
| Section 5.3. Special Accounting Rules for Rollover Contributions |
28 | |
| ARTICLE 6 |
29 | |
| TRUST AND INVESTMENT FUNDS |
29 | |
| Section 6.1. Trust |
29 | |
| Section 6.2. Investment Funds |
29 | |
| ARTICLE 7 |
30 | |
| PARTICIPANT ACCOUNTS AND INVESTMENT ELECTIONS |
30 | |
| Section 7.1. Participant Accounts and Investment Elections |
30 | |
| Section 7.2. Allocation of Net Income of Trust Fund and Fluctuation in Value of Trust Fund Assets |
32 | |
| Section 7.3. Allocations of Contributions Among Participants’ Accounts |
33 | |
| Section 7.4. Limitations on Allocations Imposed by Section 415 of the Code |
34 | |
| Section 7.5. Correction of Error |
36 | |
| ARTICLE 8 |
36 | |
| WITHDRAWALS AND DISTRIBUTIONS |
36 | |
| Section 8.1. Withdrawals and Distributions Prior to Termination of Employment |
36 | |
| Section 8.2. Loans to Participants |
40 | |
| Section 8.3. Distributions Upon Termination of Employment |
43 | |
| Section 8.4. Time of Distribution |
46 | |
| Section 8.5. Designation of Beneficiary |
48 | |
| Section 8.6. Distributions to Minor and Disabled Distributees |
50 | |
| Section 8.7. “Lost” Participants and Beneficiaries |
50 | |
(i)
| ARTICLE 9 |
51 | |
| PARTICIPANTS’ STOCKHOLDER RIGHTS |
51 | |
| Section 9.1. Voting Shares of Common Stock |
51 | |
| Section 9.2. Tender Offers |
52 | |
| ARTICLE 10 |
53 | |
| SPECIAL PARTICIPATION AND DISTRIBUTION RULES RELATING TO REEMPLOYMENT OF TERMINATED EMPLOYEES AND EMPLOYMENT BY RELATED ENTITIES |
53 | |
| Section 10.1. Change of Employment Status |
53 | |
| Section 10.2. Reemployment of an Eligible Employee Whose Employment Terminated Prior to His or Her Becoming a Participant |
54 | |
| Section 10.3. Reemployment of a Terminated Participant |
54 | |
| Section 10.4. Employment by an Affiliate |
54 | |
| Section 10.5. Leased Employees |
55 | |
| Section 10.6. Reemployment of Veterans |
55 | |
| ARTICLE 11 |
57 | |
| ADMINISTRATION |
57 | |
| Section 11.1. The Administrator and the Investment Committee |
57 | |
| Section 11.2. Claims Procedure |
62 | |
| Section 11.3. Procedures for Domestic Relations Orders |
64 | |
| Section 11.4. Notices to Participants, Etc. |
66 | |
| Section 11.5. Notices to Administrator |
66 | |
| Section 11.6. Records |
67 | |
| Section 11.7. Reports of Trustee and Accounting to Participants |
67 | |
| Section 11.8. Electronic Media |
67 | |
| ARTICLE 12 |
68 | |
| PARTICIPATION BY OTHER EMPLOYERS |
68 | |
| Section 12.1. Adoption of Plan |
68 | |
| Section 12.2. Withdrawal from Participation |
68 | |
| Section 12.3. Company as Agent for Employers |
68 | |
| ARTICLE 13 |
69 | |
| CONTINUANCE BY A SUCCESSOR |
69 | |
| ARTICLE 14 |
70 | |
| MISCELLANEOUS |
70 | |
| Section 14.1. Expenses |
70 | |
| Section 14.2. Non-Assignability |
70 | |
| Section 14.3. Employment Non-Contractual |
72 | |
| Section 14.4. Limitation of Rights |
72 | |
| Section 14.5. Merger or Consolidation with Another Plan |
73 | |
| Section 14.6. Gender and Plurals |
73 | |
| Section 14.7. Applicable Law |
73 | |
| Section 14.8. Severability |
73 | |
| Section 14.9. No Guarantee |
73 | |
| ARTICLE 15 |
74 | |
| TOP-HEAVY PLAN REQUIREMENTS |
74 | |
| Section 15.1. Top-Heavy Plan Determination |
74 | |
| Section 15.2. Definitions and Special Rules |
74 | |
| Section 15.3. Minimum Contribution for Top-Heavy Years |
75 | |
(ii)
| ARTICLE 16 |
77 | |
| AMENDMENT, ESTABLISHMENT OF SEPARATE PLAN AND TERMINATION |
77 | |
| Section 16.1. Amendment. |
77 | |
| Section 16.2. Establishment of Separate Plan. |
77 | |
| Section 16.3. Termination and Distributions upon Termination of the Plan. |
78 | |
| Section 16.4. Trust Fund to Be Applied Exclusively for Participants and Their Beneficiaries. |
79 | |
| SUPPLEMENT I |
1 | |
| Transfers from Other Plans |
1 | |
| SUPPLEMENT II |
3 | |
| Elective Transfers Between This Plan and Plans of Affiliates or the TXU 401(k) Plan |
3 | |
| SUPPLEMENT III |
5 | |
| Merger of Certain AmerGen Plans into this Plan |
5 | |
(iii)
ARTICLE 1
TITLE, PURPOSE AND EFFECTIVE DATES
The title of this Plan shall be the “Exelon Corporation Employee Savings Plan.” This Plan is an amendment and restatement of the Commonwealth Edison Employee Savings and Investment Plan as in effect on March 29, 2001, and shall be effective March 30, 2001 in respect of Participants whose employment terminates on or after such date, provided, however, that:
| (i) | any provision that specifies a different effective date shall be effective as of such date; |
| (ii) | the deletion of the family aggregation rules shall be effective as of January 1, 1997; |
| (iii) | the provisions respecting Military Service shall be effective with respect to reemployments initiated on or after December 12, 1994; |
| (iv) | Section 4.4 (relating to the nondiscrimination rules imposed by sections 401(k) and 401(m) of the Code) shall be effective as of January 1, 1997, provided, that the average deferral percentage and the average contribution percentage for the 1997-2000 plan years under the PECO Energy Company Employee Savings Plan shall be determined by using prior plan year data for non-highly compensated eligible employees; and |
| (v) | Section 7.4 (relating to the limitations imposed by section 415 of the Code) shall be effective (a) as of January 1, 1995 with respect to the deletion of the reference to “one fourth of the dollar limitation under former section 415(b)(1)(A) of the Code,” (b) as of January 1, 1998 with respect to the definition of “compensation” contained therein, (c) as of January 1, 2000 with respect to the deletion of the combined plan limit formerly required by section 415(e) of the Code and (d) as of January 1, 2001 with respect to the increase in the dollar limit on aggregate annual additions from $30,000 to $35,000. |
As of March 30, 2001, the PECO Energy Company Employee Savings Plan is merged into the Plan and shall be governed by the provisions hereof. In order to implement the changes made by and incidental to this amendment and restatement of the Plan and the merger of the PECO Energy Company Employee Savings Plan into the Plan, during a transition period beginning on March 30, 2001 and ending on a date as soon as administratively practicable thereafter as determined by the Administrator, investments, withdrawals, loans and distributions under the Plan
1
shall (notwithstanding any contrary term of the Plan) be subject to certain rules and restrictions as determined by the Administrator.
This Plan is designated as a “profit sharing plan” within the meaning of section 1.401-1(a)(2)(ii) of the Regulations; and is also designated as an ERISA section 404(c) Plan within the meaning of section 2550.404c-1 of the Regulations. In addition, the portion of the Plan invested in the Employer Stock Fund described in Section 6.2 is designated as an “employee stock ownership plan” within the meaning of section 4975(e)(7) of the Code and, as such, is designed to invest primarily in “qualifying employer securities” as defined in section 4975(e)(8) of the Code.
ARTICLE 2
DEFINITIONS
As used herein, the following words and phrases shall have the following respective meanings when capitalized:
(1) Administrator. The person or committee responsible for certain administrative matters related to the Plan, which is appointed by the Compensation Committee of the Board of Directors of the Company pursuant to Section 11.1.
(2) Affiliate. (a) A corporation that is a member of the same controlled group of corporations (within the meaning of section 414(b) of the Code) as an Employer, (b) a trade or business (whether or not incorporated) under common control (within the meaning of section 414(c) of the Code) with an Employer, (c) any organization (whether or not incorporated) that is a member of an affiliated service group (within the meaning of section 414(m) of the Code) that includes an Employer, a corporation described in clause (a) of this subdivision or a trade or business described in clause (b) of this subdivision or (d) any other entity that is required to be aggregated with an Employer pursuant to Regulations promulgated under section 414(o) of the Code.
(3) After-Tax Contributions. Contributions made by a Participant pursuant to Section 5.1.
(4) After-Tax Contributions Account. The account established pursuant to Section 7.1 to which shall be credited (i) a Participant’s After-Tax Contributions, (ii) any after-tax contributions transferred to the Plan from the PECO Energy Company Employee Savings Plan (including any after-tax contributions transferred to such plan from the Philadelphia Electric
2
Company Tax Reduction Act Stock Ownership Plan) on behalf of such Participant and (iii) earnings (or losses) thereon.
(5) Before-Tax Contributions. Contributions made on behalf of a Participant pursuant to Section 4.1.
(6) Before-Tax Contributions Account. The account established pursuant to Section 7.1 to which shall be credited (i) a Participant’s Before-Tax Contributions, (ii) any before-tax contributions transferred to the Plan from the PECO Energy Company Employee Savings Plan on behalf of such Participant and (iii) earnings (or losses) thereon.
(7) Beneficiary. The person or persons entitled under Section 8.5 to receive benefits in the event of the death of a Participant. For any period in which the Plan is not an “ERISA section 404(c) Plan” as defined in Regulations under section 404(c) of ERISA, each Beneficiary shall be a “named fiduciary” within the meaning of section 402(a)(1) of ERISA for the sole purpose of directing the Trustee with respect to the exercise of shareholder rights pursuant to Article 9 (relating to Participant’s stockholder rights).
(8) Code. The Internal Revenue Code of 1986, as amended.
(9) Common Stock. The common stock, without par value, of Exelon Corporation.
(10) Company. Exelon Corporation, a Pennsylvania corporation, or any successor to such corporation that adopts the Plan pursuant to Article 13.
(11) Compensation. The normal base pay under the applicable Exelon East or West payroll of an Employee from an Employer for personal services rendered, including (i) nuclear license premiums for management employees, (ii) meter readers’ bonuses, (iii) solely for employees who are represented by IBEW Local Union 15 and covered under that certain Collective Bargaining Agreement dated September 15, 2000 between Commonwealth Edison Company and IBEW Local Union 15, as such agreement may be amended from time to time, overtime pay, but only amounts paid with respect to hours worked in excess of an Employee’s normally scheduled hours, and excluding (i) salary continuation or lump sum payments under a severance benefit plan, or other severance arrangement, of an Employer, (ii) bonuses or incentive awards (other than meter readers’ bonuses), (iii) overtime pay for management employees, (iv) shift premiums, (v) fringe benefits, (vi) other extraordinary payments and (vii) payments made in a form other than cash, but without reduction on account of the Employee’s election to have his or her pay reduced pursuant to a qualified cash or deferred arrangement described in section 401(k) of the Code, a qualified transportation fringe benefit program described in section 132(f) of the Code or a cafeteria plan described in section 125 of the Code. For purposes of the preceding sentence, the normal base pay of an Employee who works and is compensated based on a shift schedule other than a basic work week consisting of five regularly scheduled eight-hour work days shall be computed by multiplying the number of regularly scheduled basic work hours for which such Employee is paid by his or her basic hourly rate, determined without regard to any premium payments made at an overtime rate for such work. An Employee’s “compensation” (within the meaning of section 415 of the Code) for any Plan Year in excess of the applicable dollar limitation contained in Code Section 401(a)(17) (as adjusted for changes in the cost of living pursuant to
3
section 401(a)(17) of the Code), shall be not be taken into account for any purpose under the Plan. Notwithstanding the preceding, effective January 1, 2003, normal base pay shall also include lump sum merit increases to base pay.
(12) Disability. A physical or mental condition which, in the judgment of the Administrator, based upon medical reports and other evidence satisfactory to the Administrator, permanently prevents a Participant from satisfactorily performing his or her usual duties or the duties of such other position available to him and for which he is qualified by reason of his or her training, education or experience.
(13) Effective Date. March 30, 2001.
(14) Eligible Employee. An Employee other than (i) an Employee the terms of whose employment are subject to a collective bargaining agreement that does not provide for participation in this Plan, (ii) an Employee on an unpaid leave of absence (except as required by applicable law respecting Military Service), (iii) an Employee paid on the temporary payroll of an Employer who has never completed 1,000 Hours of Service in any period of twelve consecutive months beginning with the Employee’s date of employment or any anniversary thereof and (iv) an individual rendering services to an Employer who is not on the payroll of any Employer. It is expressly intended that an individual rendering services to an Employer pursuant to any of the following agreements shall be excluded from Plan participation pursuant to clause (iv) of this subdivision even if a court or administrative agency determines that such individual is an Employee: (a) an agreement providing that such services are to be rendered as an independent contractor, (b) an agreement with an entity, including a leasing organization within the meaning of section 414(n)(2) of the Code, that is not an Employer or (c) an agreement that contains a waiver of participation in the Plan.
(15) Employee. An individual whose relationship with an Employer is, under common law, that of an employee.
(16) Employer. The Company, any Affiliate thereof that was an Employer under the Plan or a participating employer under the PECO Energy Company Employee Savings Plan immediately prior to the Effective Date (including IBEW Local Union 15, but only with respect to Employees the terms of whose employment are subject to a collective bargaining agreement that provides for participation in the Plan), and any other Affiliate that, with the consent of the Company elects to participate in the Plan in the manner described in Article 12 and any successor Affiliate that adopts the Plan pursuant to Article 13. If any entity described in the preceding sentence withdraws from participation in the Plan pursuant to Section 12.2, such entity shall thereupon cease to be an Employer.
(17) Employer Matching Contributions. Contributions made by an Employer pursuant to Section 4.3.
(18) Employer Matching Contributions Account. The account established pursuant to Section 7.1 to which shall be credited (i) any Employer Matching Contributions made on behalf of a Participant, (ii) any employer matching contributions transferred to the Plan from the PECO Energy Company Employee Savings Plan (including any employer matching contributions
4
transferred to such plan from the Philadelphia Electric Company Tax Reduction Act Stock Ownership Plan) on behalf of such Participant and (iii) earnings (or losses) thereon.
(19) ERISA. The Employee Retirement Income Security Act of 1974, as amended.
(20) Hour of Service. Each hour for which an Employee is directly or indirectly compensated by, or entitled to receive compensation from, an Employer. For purposes of this subdivision (20), compensation shall mean the total earnings paid, directly or indirectly, to the Employee by an Employer, including any back pay, irrespective of mitigation of damages, either awarded to the Employee or agreed to by an Employer. The computation of Hours of Service and the periods to which Hours of Service are credited shall be determined under uniform rules adopted by the Administrator in accordance with Department of Labor regulations §2530.200b-2(b), (c) and (f).
(21) Investment Committee. The committee responsible for certain investment matters related to the Plan, which is appointed by the Risk Management Committee of the Board of Directors of the Company pursuant to Section 11.1.
(22) Military Service. The performance of duty on a voluntary or involuntary basis in a “uniformed service” (as defined below) under competent authority of the United States government and includes active duty, active duty for training, initial active duty for training, inactive duty training, full-time National Guard duty, and a period for which a person is absent from employment for the purpose of an examination to determine the fitness of the person to perform any such duty. For purposes of the preceding sentence, the term “uniformed service” means the Armed Forces, the Army National Guard and the Air National Guard when engaged in active duty for training, inactive duty training, or full-time National Guard duty, the commissioned corps of the Public Health service, and any other category of persons designated by the President of the United States in time of war or emergency.
(23) Participant. An Eligible Employee who satisfies the conditions set forth in Section 3.1. An individual shall cease to be a Participant upon the complete distribution, or transfer of his or her account under the Plan. For any period in which the Plan is not an “ERISA section 404(c) Plan” as defined in Regulations under section 404(c) of ERISA, each Participant shall be a “named fiduciary” within the meaning of section 402(a)(1) of ERISA for the sole purpose of directing the Trustee with respect to the exercise of shareholder rights pursuant to Article 9 (relating to Participants’ stockholder rights).
(24) Plan. The plan herein set forth, and as from time to time amended.
(25) Plan Year. The twelve-month period beginning on each January 1.
(26) Regulations. Written final or temporary promulgations of the Department of Labor construing Title I of ERISA or the Internal Revenue Service construing the Code.
(27) Rollover Account. The account established pursuant to Section 7.1 to which shall be credited (i) any rollover contribution made by or on behalf of an Eligible Employee or a Participant, (ii) any rollover contribution transferred to the Plan from the PECO Energy Company Employee Savings Plan on behalf of such Participant and (iii) earnings (or losses) thereon.
5
(28) Termination Date. (a) The date an Employee quits, retires, is discharged from employment by an Employer or dies, (b) the date the Employee’s employer ceases to be an Employer on account of its sale to a party or parties that do not qualify as an Affiliate of any Employer, (c) the first anniversary of the Employee’s first date of absence from employment by an Employer for any other reason, except as provided in clause (d) or (e) below, (d) in the case of an Employee who is absent from employment for maternity or paternity reasons, the second anniversary of the first date of such absence or (e) the last date following a period of Military Service as of which the Employee has reemployment rights under applicable law. For purposes of this subdivision (27), an absence from employment for maternity or paternity reasons means an absence (1) by reason of the pregnancy of the Employee, (2) by reason of the birth of a child of the Employee, (3) by reason of the placement of a child with the Employee in connection with the adoption of such child by such Employee or (4) for purposes of caring for such child for a period beginning immediately following such birth or placement. Notwithstanding the foregoing sentences, an Employee’s absence from employment for maternity or paternity reasons or for Military Service shall not be considered in determining the Employee’s Termination Date unless the Employee, upon the Administrator’s request, provides certification that the leave was taken for one of the reasons enumerated in the preceding sentence.
(29) Trust. The trust created by agreement between the Company and the Trustee, as from time to time amended.
(30) Trust Fund. All money and property of every kind of the Trust held by the Trustee pursuant to the terms of the Trust agreement.
(31) Trustee. The trustee that executes the Trust instrument provided for in Article 6, or any successor trustee or, if there is more than one trustee acting at any time, all of such trustees collectively.
(32) Valuation Date. Each business day, as determined by the Trustee, or such other days as the Administrator may designate.
(33) VRU. The telephonic voice response unit designated by the Administrator, which may be used to make certain elections under the Plan. The VRU shall require each Participant, or Beneficiary, as the case may be, to provide such identification data as may, from time to time, be required by the VRU. The Administrator shall cause to be kept such records of VRU activity as it shall deem necessary or appropriate, and such records shall constitute valid authorization of the elections made by each Participant and Beneficiary for all purposes of the Plan and applicable Regulations. No written authorization shall be required from a Participant or Beneficiary after an election has been made by calling the VRU.
6
ARTICLE 3
PARTICIPATION
Section 3.1. Eligibility for Participation.
Each Eligible Employee who immediately before the Effective Date was a Participant in the Plan or a participant in the PECO Energy Company Employer Savings Plan shall continue to be a Participant as of the Effective Date. Each other Eligible Employee who is a member of a bargaining unit represented by IBEW Local Union 15 shall be eligible to become a Participant on the first day of the payroll period coinciding with or next following the date he or she has completed three months of employment with an Employer (regardless of the number of Hours of Service actually performed). Each other Eligible Employee shall be eligible to become a Participant on the first day of the payroll period coinciding with or next following the date of his or her employment.
Section 3.2. Applications for Before-Tax Contributions and After-Tax Contributions.
(a) Regular Payroll Before-Tax and After-Tax Contributions. Each Eligible Employee who desires to commence Before-Tax Contributions or After-Tax Contributions shall make a request in the manner prescribed by the Administrator specifying the Employee’s chosen rate of Before-Tax Contributions for each payroll period or his or her chosen rate of After-Tax Contributions for each payroll period, or both. Such request shall authorize the Employee’s Employer to reduce the Eligible Employee’s Compensation by the amount of any such Before-Tax Contributions, to make regular payroll deductions of any such After-Tax Contributions or both, as the case may be. The request shall also specify the Employee’s investment elections pursuant to Section 7.1(b) and shall evidence the Employee’s acceptance of and agreement to all provisions of
7
the Plan. In addition, an Eligible Employee who is not a member of a bargaining unit represented by IBEW Local Union 15 on the date of his or her employment may elect, in accordance with the provisions of this paragraph (a), to become a Participant on the first day of the payroll period coinciding with or next following such date. All requests to commence contributions pursuant to this paragraph (a) shall be effective as of such time after the Administrator (or its delegate) receives such request as shall be established by the Administrator, provided, that all such requests shall be effective on the first day of a payroll period commencing not more than 30 days after receipt thereof by the Administrator (or its delegate). A Participant’s request to make before-tax contributions under the PECO Energy Company Employee Savings Plan as in effect immediately prior to the Effective Date shall be effective for purposes of the Plan on the Effective Date.
(b) Quarterly Incentive Award Before-Tax Contributions. With respect to quarterly incentive awards earned prior to January 1, 2002, each Eligible Employee may request, in the manner prescribed by the Administrator, to reduce his or her compensation by an amount equal to 100 percent of any such quarterly incentive awards that would otherwise be paid to such Participant; provided, however, that for the Plan Year which includes the Effective Date, such reduction shall be available solely with respect to quarterly incentive awards payable on or after the later of (i) the Effective Date and (ii) the first date thereafter which the Administrator determines is administratively practicable with respect to Employees of such Participant’s Employer. Before-Tax Contributions pursuant to this paragraph (b) shall be invested in accordance with the Participant’s investment election under paragraph (a) of this Section (or, if no such election is in effect, in accordance with an investment election made by such Participant in the manner prescribed by the Administrator).
8
Section 3.3. Transfer to Affiliates.
If a Participant is transferred from one Employer to another Employer or from an Employer to an Affiliate, such transfer shall not terminate the Participant’s participation in the Plan and such Participant shall continue to participate in the Plan until an event occurs that would have terminated his or her participation had the Participant continued in the service of an Employer until the occurrence of such event; provided, however, that a Participant shall not be entitled (i) to make contributions to the Plan, or (ii) to have contributions made on his or her behalf to the Plan during any period of employment by any Affiliate that is not an Employer. Periods of employment with an Affiliate shall be taken into account only to the extent set forth in Section 10.4 (relating to employment by Affiliates). Payments received by a Participant from an Affiliate that is not an Employer shall not be treated as compensation for any purposes under the Plan.
ARTICLE 4
EMPLOYER CONTRIBUTIONS
Section 4.1. Before-Tax Contributions.
(a) Initial Election Respecting Regular Payroll Before-Tax Contributions. Subject to the limitations set forth in Sections 4.2 (relating to the 402(g) annual limit on Before-Tax Contributions), 4.4 (relating to limitations on contributions for highly compensated Eligible Employees), 4.5 (relating to the limitation on Employer contributions) and 7.4 (relating to limitations on allocations imposed by section 415 of the Code), each Employer shall contribute (i) on behalf of each Participant who is an Eligible Employee of such Employer and is a member of a bargaining unit represented by IBEW Local Union 15 an amount equal to a whole percentage not less than 1 and not more than 15 percent of such Participant’s Compensation for each payroll period as designated by the Participant in his or her request pursuant to Section 3.2(a), and (ii) on
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behalf of any other Participant who is an Eligible Employee of such Employer an amount equal to a whole percentage not less than 1 and not more than 20 percent of such Participant’s Compensation for each payroll period as designated by the Participant on his or her request pursuant to Section 3.2(a). Before-Tax Contributions described in the preceding sentence shall be delivered to the Trustee no less frequently than bi-weekly. In addition, if back-pay is awarded to a Participant who is an Eligible Employee and any portion of such back-pay constitutes Compensation as defined in subsection (22) of Article 2 (relating to the definition of compensation), the Employer of such Participant shall contribute on behalf of such Participant an amount equal to the Before-Tax Contribution percentage, which was most recently chosen by the Participant in his or her request pursuant to Section 3.2(a), of such back-pay that constitutes Compensation. A Before-Tax Contribution described in the preceding sentence shall be treated under the Plan in the same manner as all other Before-Tax Contributions and shall be delivered to the Trustee as soon as practicable after the back-pay is paid to the Participant.
If a Participant receives a hardship withdrawal pursuant to Section 8.1(a), then: (1) all Before-Tax Contributions made on behalf of such Participant pursuant to this Section 4.1 and After-Tax Contributions made by the Participant pursuant to Section 5.1 shall cease beginning with the first payroll period beginning after the date on which the Participant receives such hardship withdrawal; (2) such Participant shall not again be eligible to elect such contributions until the first payroll period that coincides with or follows the date on which contributions ceased by twelve months (or, for hardship withdrawals made after December 31, 2001, six months); and (3) effective for Before-Tax Contributions made in taxable years beginning before January 1, 2002, such Participant may not elect Before-Tax Contributions for his or her taxable year next following the taxable year of such withdrawal in an amount greater than the excess of the dollar
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limitation then in effect under Section 4.2 (relating to the 402(g) Annual Limit on Before-Tax Contributions) over the amount of the Participant’s Before-Tax Contributions for the taxable year in which the Participant received such hardship withdrawal.
(b) Changes in the Rate or Suspension of Regular Payroll Before-Tax Contributions. A Participant’s Before-Tax Contributions pursuant to paragraph (a) of this Section 4.1 shall continue in effect at the rate designated by a Participant in his or her request until the Participant changes such designation or suspends such contributions. A Participant may change such designation at any time by giving direction to the Administrator (or its delegate) in the manner prescribed by the Administrator. Any such direction shall be limited to the contribution rates described in paragraph (a) of this Section 4.1.
A Participant may suspend future Before-Tax Contributions pursuant to paragraph (a) of this Section by giving notice to the Administrator (or its delegate) in the manner prescribed by the Administrator. A Participant who has ceased Before-Tax Contributions pursuant to this subsection may resume Before-Tax Contributions by so directing the Administrator (or its delegate) in the manner prescribed by the Administrator. All such directions to change the rate of, suspend or resume Before-Tax Contributions shall be effective as of such time after the Administrator (or its delegate) receives any such direction as shall be established by the Administrator, provided that such direction shall be effective on the first day of a payroll period commencing not more than 30 days after receipt thereof by the Administrator (or its delegate).
(c) Elections Respecting Quarterly Incentive Award Before-Tax Contributions. With respect to quarterly incentive awards earned prior to January 1, 2002, and subject to the limitations set forth in subdivision (11) of Article 2 (relating to the $170,000 limitation on compensation) and Sections 4.2 (relating to the 402(g) limit on Before-Tax Contributions), 4.4 (relating to limitations
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on contributions for highly compensated Eligible Employees), 4.5 (relating to the limitation on Employer Contributions) and 7.4 (relating to limitations on allocations imposed by section 415 of the Code), each Employer shall contribute on behalf of each Participant who has filed a request in accordance with Section 3.2(b) an amount equal to 100 percent of the amount of any such quarterly incentive awards payable to such Participant on or after the effective date of such request. A Participant’s Before-Tax Contributions pursuant to this paragraph (c) shall continue in effect until the Participant suspends such contributions. A Participant may suspend such contributions by giving direction to the Administrator (or its delegate) in the manner prescribed by the Administrator. Any such direction to suspend Before-Tax Contributions pursuant to this paragraph (c) shall be effective beginning with the quarterly incentive award payable in the calendar quarter immediately following the calendar quarter in which such direction is received by the Administrator (or its delegate). Before-Tax Contributions pursuant to this paragraph (c) shall be delivered to the Trustee not later than the fifteenth business day of the month following the month in which the related quarterly incentive award is payable.
(d) Catch-up Contributions. Effective for payroll periods beginning on or after August 1, 2002, each Participant who pursuant to paragraph (a) of this Section 4.1 is eligible to make Before-Tax Contributions for any Plan Year and who shall attain age 50 before the close of such Plan Year shall be eligible to have Before-Tax Contributions made in addition to those described in paragraph (a) of this Section 4.1 (“Additional Before-Tax Contributions”) if no other Before-Tax Contributions to be made pursuant to paragraph (a) of this Section 4.1 may be made to the Plan for such payroll period by reason of the limitations of Section 4.2 (relating to the 402(g) annual limit on Before-Tax Contributions). Such Additional Before-Tax Contributions shall be elected, made, suspended, resumed and credited in a manner similar to that described in
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paragraphs (a), (b) and (c) of this Section 4.1 and in accordance with and subject to such additional rules and limitations of section 414(v) of the Code and otherwise as the Administrator determines. To the extent such Additional Before-Tax Contributions are not “catch-up contributions” as defined for purposes of section 414(v) of the Code, they shall be taken into account, and to the extent such Additional Before-Tax Contributions are catch-up contributions they shall not be taken into account, for purposes of Article 4 or 7 or other provisions of the Plan implementing the required limitations of sections 401(k)(3), 401(k)(11), 401(k)(12), 402(g), 404, 410(b), 415 or 416 of the Code, as applicable.
Section 4.2. 402(g) Annual Limit on Before-Tax Contributions.
(a) General Rule. Notwithstanding the provisions of Section 4.1 (relating to Before-Tax Contributions), a Participant’s Before-Tax Contributions for any calendar year, excluding any Additional Before-Tax Contributions made to the Plan pursuant to paragraph (d) of Section 4.1 which are catch-up contributions described in such paragraph, shall not exceed the applicable dollar amount under section 402(g) of the Code for such calendar year.
(b) Correction of Excess Before-Tax Contributions. If for any calendar year a Participant determines that the aggregate of the (i) Before-Tax Contributions to this Plan, excluding any Additional Before-Tax Contributions made to the Plan pursuant to paragraph (d) of Section 4.1 which are catch-up contributions described in such paragraph, and (ii) amounts contributed under other plans or arrangements described in section 401(k), 408(k) or 403(b) of the Code will exceed the limit imposed by paragraph (a) of this Section 4.2 for the calendar year in which such contributions were made (“Excess Before-Tax Contributions”), such Participant shall, pursuant to such rules and at such time following such calendar year as determined by the Administrator, be allowed to submit a written request that the Excess Before-Tax Contributions
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plus any income and minus any loss allocable thereto be distributed to him or her. The request described in this subsection shall be made in the manner and form prescribed by the Administrator and shall state the amount of the Participant’s Excess Before-Tax Contributions for the calendar year. The request shall be accompanied by the Participant’s written statement that if such Excess Before-Tax Contributions are not distributed, such Excess Before-Tax Contributions, when added to amounts deferred under other plans or arrangements described under section 401(k), 408(k), or 403(b) of the Code, excluding any contributions which are catch-up contributions described in Section 414(v) of the Code, will exceed the limit for such Participant under section 402(g) of the Code. A distribution of Excess Before-Tax Contributions (reduced by any amounts recharacterized or distributed pursuant to Section 4.4(e)(1) (relating to adjustments to comply with section 401(k)(3) of the Code)), plus earnings, shall be made no later than the April 15 of the calendar year following the calendar year for which such Excess Before-Tax Contributions were made. The amount of any income or loss allocable to such Excess Before-Tax Contributions shall be determined pursuant to applicable Regulations. If Excess Before-Tax Contributions are distributed pursuant to this Section 4.2, any corresponding Employer Matching Contributions allocated to the Participant’s Employer Matching Contributions Account, adjusted for income or loss pursuant to Regulations, to which such Participant would be entitled under Section 8.3 (relating to distributions upon termination of employment) if such Participant had terminated employment on the last day of the calendar year during which contributions were made (or earlier if such Participant actually terminated employment at an earlier date) shall be distributed to such Participant and any remaining amount of such corresponding Employer Matching Contributions, adjusted for income or loss, shall be forfeited. Notwithstanding the provisions of this paragraph,
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any such Excess Before-Tax Contributions shall be treated as “annual additions” for purposes of Section 7.4 (relating to limitations on allocations imposed by section 415 of the Code).
Section 4.3. Employer Matching Contributions.
(a) Amount of Contributions. Subject to the limitations set forth in Sections 4.4 (relating to limitations on contributions for highly compensated Eligible Employees), 4.5 (relating to the limitations on Employer contributions) and 7.4 (relating to limitations on allocations imposed by section 415 of the Code), and except as otherwise provided below, each Employer shall contribute the following for each payroll period on behalf of each Participant who is an Employee of such Employer:
| (i) | For each Participant who is a member of a bargaining unit represented by IBEW Local Union 15, an amount equal to the sum of (w), (x), (y) and (z), where (w) is 100 percent of Matched Contributions, as defined below, but only to the extent that Matched Contributions do not exceed 2 percent of the Participant’s Compensation for the payroll period, (x) is 84 percent of Matched Contributions in excess of 2 percent of the Participant’s Compensation but not in excess of 3 percent of the Participant’s Compensation for the payroll period, (y) is 83 percent of Matched Contributions in excess of 3 percent of the Participant’s Compensation but not in excess of 5 percent of the Participant’s Compensation for the payroll period, and (z) is 25 percent of Matched Contributions in excess of 5 percent of the Participant’s Compensation, but not in excess of 6 percent of the Participant’s Compensation for the payroll period; and |
| (ii) | For each other Participant, an amount equal to 100 percent of Matched Contributions, as defined below, but only to the extent that Matched Contributions do not exceed 5 percent of the Participant’s Compensation for the payroll period. |
For purposes of this Section 4.3, “Matched Contributions” means the sum of (i) the Before-Tax Contributions made on behalf of the Participant for a payroll period, excluding Before-Tax Contributions made with respect to any quarterly incentive awards pursuant to Section 3.2(b) and excluding Additional Before-Tax Contributions which are catch-up contributions described in
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Section 414(v) of the Code, and (ii) the After-Tax Contributions made by the Participant for such payroll period.
(b) Special Part-Time Employees. Notwithstanding paragraph (a) hereof, no Employer shall make a contribution pursuant to this Section 4.3 on behalf of any Participant who is a “part-time regular employee” as defined in an Agreement dated July 23, 1993 between the Company and the System Council U-25, I.B.E.W. (the “July 23, 1993 Agreement”), unless one of the following applies:
| (1) | the Participant had in effect on July 23, 1993 an authorization to make contributions under the Plan as then in effect and elected pursuant to the July 23, 1993 Agreement and request by the Company to become a part-time regular employee during the initial staffing period that began July 23, 1993 and ended December 31, 1993 (the “Initial Staffing Period”); |
| (2) | the Participant had in effect on the date the Participant became a part-time regular employee an authorization to make contributions under the Plan as then in effect and chose the Option II Benefits Package as described in the July 23, 1993 Agreement, as amended; |
| (3) | the Participant did not have in effect on the date the Participant became a part-time regular employee an authorization to make contributions under the Plan as then in effect and elected pursuant to the July 23, 1993 Agreement and request by the Company to become a part-time regular employee during the Initial Staffing Period; provided such Participant had in effect on any date after December 24, 1995 and before February 20, 1996 an authorization to make contributions under the Plan; or |
| (4) | the Participant elected other than pursuant to the July 23, 1993 Agreement to become a part-time regular employee during the Initial Staffing Period; provided that such Participant had in effect on any date after December 24, 1995 and before February 20, 1996 and authorization to make contributions under the Plan. |
(c) Time of Delivery of Contributions. Employer Matching Contributions for any Plan Year shall be delivered to the Trustee at the same time the Before-Tax contributions or After-Tax Contributions to which such Employer Matching Contributions relate are delivered to the Trustee.
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Section 4.4. Limitations on Contributions for Highly-Compensated Eligible Employees.
(a) Limits Imposed by Section 401(k)(3) of the Code. Notwithstanding the provisions of Section 4.1 (relating to Before-Tax Contributions), if the Before-Tax Contributions for a Plan Year fail, or in the judgment of the Administrator are likely to fail, to satisfy both of the tests set forth in paragraphs (1) and (2) of this subsection, the adjustments prescribed in paragraph (e)(1) of this Section 4.4 shall be made.
| (1) | The average deferral percentage for the group consisting of highly compensated eligible employees of all Employers does not exceed the product of the average deferral percentage for the group consisting of non-highly compensated eligible employees multiplied by 1.25. |
| (2) | The average deferral percentage for the group consisting of highly compensated eligible employees of all Employers (i) does not exceed the average deferral percentage for the group consisting of non-highly compensated eligible employees by more than two percentage points, and (ii) does not exceed two times the average deferral percentage for such group. |
Effective for payroll periods beginning on or after August 1, 2002, any Additional Before-Tax Contributions which are “catch-up contributions” described in paragraph (d) of Section 4.1 shall not be considered as Before-Tax Contributions for purposes of determining whether the tests set forth in paragraphs (1) and (2) of this subsection are satisfied or for purposes of making any adjustments prescribed in paragraph (e) of this Section 4.4.
(b) Limits Imposed by Section 401(m) of the Code. Notwithstanding the provisions of Section 4.3 (relating to Employer Matching Contributions) and Section 5.1 (relating to After-Tax Contributions), if the Employer Matching Contributions and After-Tax Contributions for a Plan Year fail, or in the judgment of the Administrator are likely to fail, to satisfy both of the tests set forth in paragraphs (1) and (2) of this subsection, the adjustments prescribed in paragraph (e)(2) of this Section 4.4 shall be made.
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| (1) | The average contribution percentage for the group consisting of highly compensated eligible employees of all Employers does not exceed the product of the average contribution percentage for the group consisting of non-highly compensated eligible employees multiplied by 1.25. |
| (2) | The average contribution percentage for the group consisting of highly compensated eligible employees of all Employers (i) does not exceed the average contribution percentage for the group consisting of non-highly compensated eligible employees by more than two percentage points, and (ii) does not exceed two times the average contribution percentage for such group. |
(c) Aggregate Limit on Contributions. Deleted in its entirety.
(d) Definitions. For purposes of this Section:
| (1) | the “average deferral percentage” for a group of Eligible Employees with respect to a Plan Year shall be the average of the ratios, calculated separately for each Eligible Employee in such group to the nearest one-hundredth of one percent, of the Before-Tax Contributions made for the benefit of such Eligible Employee to the total compensation paid to such Eligible Employee for the portion of such Plan Year during which such Eligible Employee was a Participant, except that no Additional Before-Tax Contributions which are “catch-up contributions” described in paragraph (d) of Section 4.1 shall be considered as Before-Tax Contributions for purposes of determining a Participant’s average deferral percentage; |
| (2) | the “average contribution percentage” for a group of Eligible Employees with respect to a Plan Year shall be the average of the ratios, calculated separately for each Eligible Employee in such group to the nearest one-hundredth of one percent, of the Employer Matching Contributions made, After-Tax Contributions made and, in the Administrator’s sole discretion, to the extent permitted under Regulations or otherwise under the Code, the Before-Tax Contributions made during such year for the benefit of such Eligible Employee, except that no Additional Before-Tax Contributions which are “catch-up contributions” described in paragraph (d) of Section 4.1, shall be considered as Before-Tax Contributions for purposes of determining a Participant’s average contribution percentage, to such Eligible Employee’s compensation for the portion of such Plan Year during which such Eligible Employee was a Participant; |
| (3) | the term “highly compensated eligible employee” shall mean any Eligible Employee who is a Participant, who performs service in the determination year and who is (a) a 5%-owner (as determined under section 416(i)(1)(A)(iii) of the Code) at any time during the Plan Year or the preceding Plan Year or (b) is paid compensation in excess of $80,000 (as adjusted for increases in the cost of living in accordance with |
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| section 414(q)(1)(B)(ii) of the Code) from an Employer for the preceding Plan Year; |
| (4) | the term “non-highly compensated eligible employee” shall mean any Eligible Employee who is a Participant, who performs services in the determination year and is not a highly compensated eligible employee; |
| (5) | the term “compensation” shall have the meaning set forth in section 414(s) of the Code or, in the discretion of the Administrator, any other meaning in accordance with the Code for these purposes, except that for purposes of determining whether an Eligible Employee is a “highly compensated eligible employee”, as described in paragraph (d)(3) of this Section 4.4, “compensation” shall have the meaning set forth in section 415(c)(3) of the Code; |
| (6) | if this Plan and one or more other plans of the Employer to which Before-Tax Contributions, After-Tax Contributions, or qualified nonelective contributions (as such term is defined in section 401(m)(4)(C) of the Code) are made are treated as one plan for purposes of section 410(b) of the Code, such plans shall be treated as one plan for purposes of this Section. If a highly compensated eligible employee participates in this Plan and one or more other plans of the Employer to which any such contributions are made, all such contributions shall be aggregated for purposes of this Section 4.4; and |
| (7) | if this Plan benefits Employees who are included in a unit of employees covered by a collective bargaining agreement and employees who are not included in such collective bargaining unit, this Plan shall be treated as comprising two or more separate plans, as determined by the Administrator in accordance with applicable Regulations, for purposes of this Section 4.4. |
This paragraph is inserted at the request of the Internal Revenue Service in order to obtain a favorable determination letter. In computing the “average deferral percentage” for a group of Eligible Employees with respect to a Plan Year, the Before-Tax Contributions that will be taken into account for such Plan Year will be only those that relate to compensation that would have been received by the Eligible Employee in the Plan Year or is attributable to services performed by the Eligible Employee in the Plan Year and would have been received by the Eligible Employee within 2-1/2 months after the close of the Plan Year. In computing the “average contribution percentage” for a group of Eligible
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Employees with respect to a Plan Year, (i) an After-Tax Contribution will be taken into account only if it is paid to the Trust during such Plan Year or paid to an agent of the Plan and transmitted to the Trust within a reasonable time after the end of the Plan Year; (ii) an excess contribution that is recharacterized will be taken into account during the Plan Year in which the contribution would have been received in cash by the Eligible Employee had the Eligible Employee not elected to defer the contribution; (iii) an Employer Matching Contribution will be taken into account only if it is made on account of the Eligible Employee’s Before-Tax Contributions or After-Tax Contributions, allocated to the Eligible Employee’s Account as of a date within that Plan Year and paid to the Trust by the end of the twelfth month following the close of such Plan Year; and (iv) qualified matching contributions which are used to meet the requirements of section 401(k)(3)(A) of the Code are not to be taken into account for purposes of the actual deferral percentage test of section 401(m) of the Code. To the extent required by law, the following will be treated as separate plans for purposes of sections 401(a)(4) and 410(b) of the Code: (i) the portion of the Plan that is a 401(k) plan, (ii) the portion of the Plan that is a section 401(m) plan; (iii) the portion of the plan that provides for contributions other than elective, employee or matching; (iv) the portion of the Plan that is an ESOP; and (v) the portion of the plan that is not an ESOP.
(e) Adjustments to Comply with Limits.
(1) Adjustments to Comply with Section 401(k)(3) of the Code. The Administrator shall cause to be made such periodic computations as it shall deem necessary or appropriate to determine whether either of the tests set forth in paragraph (a)(1) or (a)(2) of this Section 4.4 shall be satisfied during a Plan Year, and, if it appears to
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the Administrator that neither of such tests will be satisfied, the Administrator shall take such steps as it deems necessary or appropriate to reduce or otherwise adjust the Before-Tax Contributions contributed or to be contributed for all or a portion of such Plan Year on behalf of Participants who are highly compensated eligible employees to the extent necessary in order for one of such tests to be satisfied. If, as of the end of the Plan Year, the Administrator determines that, notwithstanding any adjustments made pursuant to the preceding sentence, neither of the tests set forth in paragraph (a)(1) and (a)(2) of this Section 4.4 shall be satisfied with respect to such Plan Year, the total amount by which Before-Tax Contributions must be reduced in order to satisfy either such test shall be calculated in the manner prescribed by section 401(k)(8)(B) of the Code (the “excess contributions amount”). The Before-Tax Contributions made on behalf of the Participant who is a highly compensated eligible employee and whose actual dollar amount of Before-Tax Contributions is the highest shall be reduced until such dollar amount equals the next highest actual dollar amount of Before-Tax Contributions made for such Plan Year on behalf of any highly compensated employee, or until the total reduction equals the excess contributions amount. If further reductions are necessary, then the Before-Tax Contributions on behalf of each Participant who is a highly compensated eligible employee and whose actual dollar amount of Before-Tax Contributions is the highest (after the reduction described in the preceding sentence) shall be reduced in accordance with the previous sentence. Such reductions shall continue to be made to the extent necessary so that the total reduction equals the excess contributions amount.
To the extent that the sum of such reductions with respect to a Participant and the amount of other After-Tax Contributions allocated to such Participant’s After-Tax
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Contributions Account does not exceed 20 percent (10 percent in the case of a Participant who is a member of a bargaining unit represented by IBEW Local Union 15) of the Participant’s Compensation, the amount of such reductions shall be treated as an After-Tax Contribution. To the extent such amount cannot be treated as an After-Tax Contribution because of the limitation described in the preceding sentence, distribute no later than the last day of the subsequent Plan Year to such Participant (i) the amount of such reductions plus any income and minus any loss allocable thereto and (ii) any corresponding Employer Matching Contributions related thereto plus any income and minus any loss allocable thereto to which such Participant would be entitled under Section 8.3 (relating to distributions upon termination of employment) if such Participant had terminated employment on the last day of the Plan Year for which contributions were made (or earlier if any such Participant actually terminated employment at any earlier date), and any remaining amount of such corresponding Employer Matching Contributions plus any income and minus any loss allocable thereto shall be forfeited.
The amount of Before-Tax Contributions to be distributed to a Participant pursuant to this Section shall be reduced by any Before-Tax Contributions previously distributed to such Participant pursuant to Section 4.2(b) (relating to correction of Excess Before-Tax Contributions) for such Plan Year. The amount of any income or loss allocable to any such reductions to be so distributed shall be determined pursuant to Regulations. The unadjusted amount of any such reductions so distributed shall be treated as “annual additions” for purposes of Section 7.4 (relating to limitations on allocations imposed by section 415 of the Code).
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(2) Adjustments to Comply with Section 401(m) of the Code. The Administrator shall cause to be made such periodic computations as it shall deem necessary or appropriate to determine whether either of the tests set forth in paragraph (b)(1) or (b)(2) of this Section 4.4 shall be satisfied during a Plan Year, and, if it appears to the Administrator that neither of such tests will be satisfied, the Administrator shall take such steps as it deems necessary or appropriate to adjust the Employer Matching Contributions made, After-Tax Contributions made, and any Before-Tax Contributions treated as Employer Matching Contributions pursuant to paragraph (d)(2) of this Section 4.4 for all or a portion of such Plan Year on behalf of Participants who are highly compensated eligible employees to the extent necessary in order for one of such tests to be satisfied. If after the end of a Plan Year it is determined that regardless of any steps taken neither of the tests set forth in paragraph (b)(1) or (b)(2) of this Section 4.4 shall be satisfied with respect to such Plan Year, the Administrator shall calculate the total amount by which any such contributions on behalf of Participants who are highly compensated eligible employees must be reduced in order to satisfy either such test, in the manner prescribed by section 401(m)(6) of the Code (the “excess aggregate contributions amount”). The amount to be reduced with respect to Participants who are highly compensated eligible employees shall be determined by first reducing the After-Tax Contributions (including Before-Tax Contributions recharacterized as After-Tax Contributions pursuant to paragraph (e)(1) of this Section 4.4) and then by reducing the Employer Matching Contributions for each Participant whose actual dollar amount of such aggregate contributions for such Plan Year is highest until such reduced dollar amount equals the next highest dollar amount of such contributions for such Plan Year on behalf of
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any other highly compensated eligible employee, or until the total reduction equals the excess aggregate contributions amount. If further reductions are necessary, such contributions on behalf of each Participant who is a highly compensated eligible employee and whose actual dollar amount of such contributions is the highest (after the reduction described in the preceding sentence) shall be reduced in accordance with the preceding sentence. Such reductions shall continue to be made to the extent necessary until the total reduction equals the excess aggregate contributions amount. If After-Tax Contributions are distributed pursuant to this paragraph (e)(2), any corresponding Employer Matching Contributions related thereto plus any income and minus any loss allocable thereto to which such Participant would be entitled under Section 8.3 (relating to distributions upon termination of employment) if such Participant had terminated employment on the last day of the Plan Year for which contributions were made (or earlier if any such Participant actually terminated employment at any earlier date) shall also be distributed with such After-Tax Contributions (and taken into account to determine whether further reductions are necessary), and any remaining amount of such corresponding Employer Matching Contributions plus any income and minus any loss allocable thereto shall be forfeited. If the reductions required by this subparagraph exceed the amount of After-Tax Contributions made or to be made by any Participant for such Plan Year and the amount of Employer Matching Contributions made or to be made on behalf of such Participant for such Plan Year, any Before-Tax Contributions made on behalf of such Participant that the Administrator has elected to treat as Employer Matching Contributions pursuant to paragraph (d)(2) of this Section 4.4 shall also be adjusted and taken into account in
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accordance with this subparagraph, except that such Before-Tax Contributions may not be recharacterized as After-Tax Contributions.
Section 4.5. Limitation on Employer Contributions.
The contributions of an Employer for any Plan Year shall not exceed the maximum amount for which a deduction is allowable to such Employer for federal income tax purposes for the fiscal year of such Employer that coincides with such Plan Year.
Any contribution made by an Employer by reason of a good faith mistake of fact, or the portion of any contribution made by an Employer that exceeds the maximum amount for which a deduction is allowable to such Employer for federal income tax purposes by reason of a good faith mistake in determining the maximum allowable deduction, shall upon the request of such Employer be returned by the Trustee to the Employer. An Employer’s request and the return of any such contribution must be made within one year after such contribution was mistakenly made or after the deduction of such excess portion of such contribution was disallowed, as the case may be. The amount to be returned to an Employer pursuant to this paragraph shall be the excess of (i) the amount contributed over (ii) the amount that would have been contributed had there not been a mistake of fact or a mistake in determining the maximum allowable deduction. Earnings attributable to the mistaken contribution shall not be returned to the Employer, but losses attributable thereto shall reduce the amount to be so returned. If the return to the Employer of the amount attributable to the mistaken contribution would cause the balance of any Participant’s account as of the date such amount is to be returned (determined as if such date coincided with the close of a Plan Year) to be reduced to less than what would have been the balance of such account as of such date had the mistaken amount not been contributed, the amount to be returned to the Employer shall be limited so as to avoid such reduction.
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ARTICLE 5
EMPLOYEE CONTRIBUTIONS
Section 5.1. After-Tax Contributions.
Subject to the limitations set forth in Section 4.4 (relating to limitations on contributions for highly-compensated Eligible Employees) and Section 7.4 (relating to limitations on allocations imposed by section 415 of the Code), each Participant who is an Eligible Employee may elect in accordance with Section 3.2(a) to make After-Tax Contributions under the Plan by payroll deduction. After-Tax Contributions made by a Participant who is a member of a bargaining unit represented by IBEW Local Union 15 for any payroll period shall equal a whole percentage not less than 1 nor more than 10 percent of the Participant’s Compensation for such payroll period, as designated by the Participant in his or her request pursuant to Section 3.2(a). After-Tax Contributions made by any other Participant for any payroll period shall equal a whole percentage not less than 1 nor more than 20 percent of the Participant’s Compensation for such payroll period, as designated by the Participant in his or her request pursuant to Section 3.2(a). Except as set forth below, After-Tax Contributions shall be delivered to the Trustee no less frequently than bi-weekly. In addition, if back-pay is awarded to a Participant who is an Eligible Employee and any portion of such back-pay constitutes Compensation as defined in subsection (22) of Article 2 (relating to the definition of compensation), After-Tax Contributions shall be made for such Participant in an amount equal to the After-Tax Contribution percentage, which was most recently chosen by the Participant in his or her request pursuant to Section 3.2(a), of such back-pay that constitutes Compensation. An After-Tax Contribution described in the preceding sentence shall be treated under the Plan in the same manner as all other After-Tax Contributions and shall be delivered to the Trustee as soon as practicable after the back-pay is paid to the Participant. After-Tax
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Contributions shall be delivered to the Trustee no less frequently than bi-weekly. Except as provided in the following sentence and in Section 4.1, After-Tax Contributions shall be subject to the same provisions regarding commencement, change and suspension applicable to Before-Tax Contributions as set forth in Section 4.1. If a Participant who has not attained age 59½ makes a withdrawal of After-Tax Contributions pursuant to Section 8.1(c), then: (a) After-Tax Contributions made by such Participant pursuant to this Section shall cease beginning with the first payroll period beginning after the date on which the Participant receives such withdrawal and (b) such Participant shall not again be eligible to elect such contributions until the first payroll period that coincides with or follows the date on which contributions ceased by 6 months.
Section 5.2. Rollover Contributions.
(a) The Trustee shall be authorized to receive, hold and distribute in accordance with the Plan, a direct rollover contribution consisting of cash, transferred to the Plan by (i) a qualified plan described in section 401(a) or 403(a) of the Code, including after-tax employee contributions to such plan, (ii) an annuity contract described in section 403(b) of the Code, excluding after-tax employee contributions or (iii) an eligible plan under section 457(b) of the Code which is maintained by a state, political subdivision of a state, or any agency or instrumentality of a state or political subdivision of a state. The Trustee shall also be authorized to receive, hold and distribute in accordance with the Plan, a Participant contribution of an eligible rollover distribution from (A) a qualified plan described in section 401(a) or 403(a) of the Code, (B) an annuity contract described in section 403(b) of the Code, (C) an eligible plan under section 457(b) of the Code which is maintained by a state, political subdivision of a state, or any agency or instrumentality of a state or political subdivision of a state or (D) an individual retirement account or annuity described in section 408(a) or 408(b) of the Code that is eligible to be rolled over and would
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otherwise be includible in gross income. The amounts transferred must be eligible rollover distributions, as defined in section 402(c) of the Code. An eligible rollover distribution to a “Separation Eligible Participant” from the PECO Energy Company Service Annuity System may also be contributed to this Plan in accordance herewith no later than December 31, 2002.
(b) Delivery of Rollover Contributions to Administrator. Except as otherwise provided in paragraph (a) of this Section, if an individual desires to make a rollover contribution pursuant to such paragraph (a), such contribution either (i) shall be delivered by the individual to the Administrator and by the Administrator to the Trustee on or before the 60th day after the day on which the Employee receives the distribution or on or before such later date as may be prescribed by law, or (ii) shall be transferred on behalf of the individual directly from the trust from which the eligible rollover distribution is made. Any contribution that is delivered by the Eligible Employee must be accompanied by (i) a statement of the Employee that to the best of his or her knowledge the amount so transferred meets the conditions specified in paragraph (a) of this Section, (ii) a copy of such documents as may have been received by the Employee advising him or her of the amount of and the character of such distribution and (iii) any investment election with respect to such contribution in such form and manner as may be required by the Administrator. Notwithstanding the foregoing, the Administrator shall not accept a rollover contribution if in its judgment accepting such contribution would cause the Plan to violate any provision of the Code or Regulations, and the Administrator shall not be required to accept such a contribution to the extent it consists of property other than cash.
Section 5.3. Special Accounting Rules for Rollover Contributions.
If a rollover contribution is made by or on behalf of an Employee, the Administrator shall cause a Rollover Account to be established and maintained for such Employee to which shall be
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credited all rollover contributions made pursuant to Section 5.2. A rollover contribution shall be credited to such Rollover Account as of the Valuation Date coinciding with or next following the date on which such contribution is delivered to the Trustee.
If a rollover contribution is made by, or a direct transfer is made on behalf of, an Eligible Employee prior to becoming a Participant, such Eligible Employee shall until such time as he or she becomes a Participant be deemed to be a Participant, and his or her Rollover Account and After-Tax Contributions Account, if any, shall be deemed to be an account of a Participant, for all purposes of the Plan except for the purposes of the allocation of contributions provided for in paragraphs (a), (b), (c) and (d) of Section 7.3 and any determination of when he or she becomes a Participant pursuant to Article 3.
ARTICLE 6
TRUST AND INVESTMENT FUNDS
Section 6.1. Trust.
A Trust shall be created by the execution of a trust agreement between the Company and the Trustee. All contributions under the Plan shall be paid to the Trustee. The Trustee shall hold all monies and other property received by it and invest and reinvest the same, together with the income therefrom, on behalf of the Participants collectively in accordance with the provisions of the trust agreement. The Trustee shall make distributions from the Trust Fund at such time or times to such person or persons and in such amounts as the Administrator directs in accordance with the Plan.
Section 6.2. Investment Funds.
The Trustee shall establish and maintain, or shall cause to be established and maintained, an investment fund herein called the “Employer Stock Fund” which shall be invested in Common Stock, and shall also include such short-term obligations and short-term liquid investments
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purchased by the Trustee, in accordance with the Trust Agreement, pending the selection and purchase of the Common Stock or as otherwise determined by the Trustee to be necessary to satisfy such fund’s cash needs. In addition, as directed by the Investment Administrator, one or more additional separate investment funds shall be established and maintained and shall be invested as directed by the Investment Committee. For purposes of the preceding sentence, the Investment Committee may purchase a group annuity contract from an insurance company that permits investment in one or more separate investment funds. The Investment Committee also may, from time to time, and in its sole discretion, segregate any of the assets held under any investment fund established pursuant to this Section and allocate the investment results from such segregated assets among all or a portion of the accounts of Participants in such manner as it shall determine to be appropriate. All charges and expenses incurred in connection with the purchase and sale of investments for a fund shall be charged to such fund except to the extent such charges and expenses are paid by the Employers.
ARTICLE 7
PARTICIPANT ACCOUNTS AND INVESTMENT ELECTIONS
Section 7.1. Participant Accounts and Investment Elections.
(a) Participant Accounts. For each Participant the Administrator shall establish and maintain, or shall cause to be established and maintained, investment accounts to which amounts contributed under the Plan shall be credited according to each Participant’s investment elections pursuant to paragraph (b) of this Section 7.1, subject to the last sentence of the first paragraph of Section 6.2 (relating to the Investment Committee’s authority to segregate any of the assets held under any investment fund).
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Each such investment account shall, to the extent appropriate, be composed of the following accounts: (A) a Before-Tax Contributions Account, (B) an Employer Matching Contributions Account, (C) an After-Tax Contributions Account, and (D) a Rollover Account. Earnings and losses on investment of funds in each account shall be credited or debited to that account.
All such accounts and subaccounts shall be for accounting purposes only, and there shall be no segregation of assets within the investment funds among the separate Participants’ accounts.
(b) Investment Election. Each Participant, as part of his or her request for participation described in Section 3.2 (or in connection with the delivery of a rollover contribution pursuant to Section 5.2), shall make an investment election that shall apply to the investment of contributions to be made on his or her behalf or by him or her pursuant to Article 4 or Article 5 and any earnings on such contributions. Such election shall specify that such contributions be invested either (i) wholly in one of the funds maintained or employed by the Trustee pursuant to paragraph (a) of this Section 7.1 or (ii) divided among such funds in 1 percent increments or in such other increments established by the Administrator or the Investment Committee from time to time. Each Eligible Employee for whom a Rollover Account is established before such Eligible Employee has become a Participant shall, in the manner prescribed by the Administrator, make such investment election as of the Valuation Date on which such account is established. During any period in which no direction as to the investment of an Employee’s account is on file with the Administrator, contributions or direct transfers made by him or her, or on his or her behalf, to the Plan will be invested in such manner as the Investment Committee shall determine.
(c) Change of Investment Election. Subject to such restrictions as may be imposed by the Administrator or the Investment Committee (including, without limitation, any restrictions
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imposed with respect to transfers of funds to or from the Employer Stock Fund described in Section 6.2 by individuals who are subject to Rule16b-3 under section 16 of the Securities Exchange Act of 1934), a Participant may elect to change as of any Valuation Date his or her investment election applicable to all or any portion of his or her current account balance. In addition, a Participant may elect to change as of the first day of any payroll period his or her investment election applicable to future contributions made pursuant to Articles 4 or 5, or both, as specified by the Participant. Such changes shall be limited to the investment funds then maintained or employed by the Trustee pursuant to Section 7.1(a). A Participant’s change of investment election must be made in the manner and at the time prescribed by the Administrator (or its delegate). Any such change shall specify that such contributions be invested either (i) wholly in one of the funds maintained or employed by the Trustee pursuant to Section 7.1(a), or (ii) divided among such funds in 1 percent increments or such other increments established by the Administrator or the Investment Committee from time to time.
Section 7.2. Allocation of Net Income of Trust Fund and Fluctuation in Value of Trust Fund Assets.
In the event that contributions, income and losses are not otherwise specifically allocated to Participant accounts by the Trustee, as soon as practical after each Valuation Date, the net worth of each investment fund (as defined in Section 6.2) as of such Valuation Date shall be determined. If the net worth of such investment fund as so determined is more or less than the total of all balances credited as of such Valuation Date to the subaccounts of Participants invested in the investment fund as of such Valuation Date who are Participants as of such Valuation Date, the amount of any excess or deficiency shall be prorated and credited or charged to such subaccounts proportionally to the balances of such subaccounts as of the preceding Valuation Date after
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making all allocations for such preceding Valuation Date prescribed by this Article and after decreasing each such subaccount by any loans, withdrawals or distributions from such subaccount during such period (but not less than zero), with all of such decreases to be made in such manner as the Administrator determines in its discretion to be necessary.
Section 7.3. Allocations of Contributions Among Participants’ Accounts.
(a) Allocation of Before-Tax Contributions. Before-Tax Contributions shall be allocated to the Before-Tax Contributions Account of each Participant for whom such contributions are made as soon as practical after such contributions are delivered to the Trustee or insurer maintaining a group annuity contract.
(b) Allocation of Employer Matching Contributions. Employer Matching Contributions shall be allocated to the Matching Contributions Account of each Participant for whom such contributions are made as soon as practical after such contributions are delivered to the Trustee or insurer maintaining a group annuity contract.
(c) Allocation of After-Tax Contributions. After-Tax Contributions shall be allocated to the After-Tax Contributions Account of the Participant who makes such contributions as soon as practical after such contributions are delivered to the Trustee or insurer maintaining a group annuity contract.
(d) Allocation of Rollover Contributions and Direct Transfers. Rollover contributions made pursuant to Article 5 shall be credited to the Rollover Account of the Participant on whose behalf such contribution is made as of the Valuation Date coinciding with or next following the date on which the contribution is delivered to the Trustee.
(e) Allocation of Forfeitures. The total amount forfeited during any Plan Year shall first be used to restore the accounts of “lost” Participants and Beneficiaries as described in Section 8.7,
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next to restore the accounts of Participants who are reemployed by the Employer of such Participant as described in Section 10.3 and, to the extent any forfeitures are still remaining, shall be allocated as of the last day of such Plan Year per capita among the accounts of all Participants who are Employees on that day. Any such allocation shall be made as soon as practical after the close of such Plan Year.
Section 7.4. Limitations on Allocations Imposed by Section 415 of the Code.
Notwithstanding any other provision of the Plan, the amount allocated to a Participant’s accounts under the Plan for each Plan Year shall be limited so that (1) the aggregate annual additions to the Participant’s accounts under this Plan and in all other defined contribution plans maintained by an Employer shall not exceed the lesser of (A) $40,000 and (B) 100% of the Participant’s compensation for such Plan Year.
If the amount to be allocated to a Participant’s accounts pursuant to Section 7.3 (relating to allocations of contributions among Participant’s accounts) for a Plan Year would exceed the limitation set forth in clause (1) of this Section 7.4, such excess shall be reduced before allocations are made to the Participant’s accounts. If in any Plan Year the annual additions of a Participant would exceed the limitation set forth in clause (1) of this Section 7.4 as a result of (i) a reasonable error in estimating a Participant’s compensation, (ii) the allocation of forfeitures, (iii) a reasonable error in determining the amount of Before-Tax Contributions that may be allocated to a Participant’s account, or (iv) under other limited facts and circumstances as determined by the Commissioner of Internal Revenue, then the Administrator shall reduce the Participant’s annual additions to the extent of such excess in the manner described below:
(a) First, by reducing the Participant’s After-Tax Contributions allocated to his or her account and any Employer Matching Contributions attributable thereto and distributing to the Participant the amount by which his or her After-Tax Contributions have been reduced, plus or minus any earnings attributable thereto, determined in accordance
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with Regulations. The amount by which the Participant’s Matching Contributions have been reduced shall be forfeited. The amount so forfeited shall be used to reduce Matching Contributions in the next following Plan Year and each Plan Year thereafter until such amount is reduced to zero.
(b) Second, by reducing the Participant’s Before-Tax Contributions allocated to his or her account and any Employer Matching Contributions attributable thereto and distributing to the Participant the amount by which his or her Before-Tax Contributions have been reduced, plus or minus any earnings attributable thereto, determined in accordance with Regulations. The amount by which the Participant’s Matching Contributions have been reduced shall be forfeited. The amount so forfeited shall be used to reduce Matching Contributions in the next following Plan Year and each Plan Year thereafter until such amount is reduced to zero.
(c) Third, by reducing forfeitures allocated to the Participant’s account and allocating the amount of such reduction among the accounts of all other Participants, of the same Employer, who have in effect an election to make contributions pursuant to Section 4.1 or 5.1.
(d) Fourth, by reducing the Employer Matching Contributions allocated to the Participant’s account and allocating the amount of such reduction among the accounts of all other Participants, of the same Employer, who have in effect an election to make contributions pursuant to Section 4.1 or 5.1.
For purposes of this Section 7.4, the “annual additions” for a Plan Year to a Participant’s accounts in this Plan and in any other defined contribution plan maintained by an Employer is the sum during such Plan Year of:
| (i) | the amount of Employer contributions and Employee contributions (but excluding any rollover contribution or direct transfers made to such plan) allocated to such Participant’s accounts, |
| (ii) | the amount of forfeitures allocated to such Participant’s accounts, and |
| (iii) | contributions allocated on behalf of the Participant to any individual medical benefit account as defined in section 415(l) of the Code. |
For purposes of this Section 7.4, ”defined contribution plan” shall have the meaning set forth in section 415 of the Code and Regulations, and the term “Employer” shall include all Affiliates except that in defining Affiliates “more than 50 percent” shall be substituted for “at least 80 percent” where required by section 415(g) of the Code. In addition, for purposes of this
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Section 7.4, “compensation” shall mean a Participant’s compensation reportable on a Form W-2, but without reduction on account of an Employee’s election to have his or her pay reduced pursuant to (i) a qualified cash or deferred arrangement described in section 401(k) of the Code, (ii) a cafeteria plan described in section 125 of the Code or, (iii) effective for Plan Years beginning on or after January 1, 2001, a qualified transportation fringe benefit plan year under section 132(f) of the Code, and excluding amounts so reportable on account of (x) a disposition of common stock of an Employer or Affiliate, pursuant to any stock purchase plan, (y) moving expenses deductible under section 217 of the Code and (z) other items receiving a special tax treatment within the meaning of section 1.415-2(d)(3)(iv) of the Regulations.
Section 7.5. Correction of Error.
If it comes to the attention of the Administrator that an error has been made in any of the allocations prescribed by this Article, appropriate adjustment shall be made to the accounts of all Participants and designated Beneficiaries that are affected by such error, except that no adjustment need be made with respect to any Participant or Beneficiary whose account has been distributed in full prior to the discovery of such error.
ARTICLE 8
WITHDRAWALS AND DISTRIBUTIONS
Section 8.1. Withdrawals and Distributions Prior to Termination of Employment.
(a) Hardship Withdrawals. An Employee who has not attained age 59½ may make a request by calling the VRU, or in such other manner as may be prescribed by the Administrator, to withdraw as of any date all or a portion of the balance of his or her Before-Tax Contributions Account (other than earnings credited to such account after December 31, 1988) and Employer Matching Contributions Account only if the Participant has incurred a financial hardship, except
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that while any loan to the Participant under Section 8.2 remains outstanding, the amount available for withdrawal under this Section 8.1(a) shall be the balance in such account less the balance of all outstanding loans to the Participant. The determination of the existence of financial hardship and the amount required to be distributed to satisfy the need created by the hardship will be made by the Administrator in a uniform and non-discriminatory manner subject to the following rules:
(A) A financial hardship shall be deemed to exist if, and only if, the Participant certifies to the Administrator that the financial need is on account of:
| (i) | medical expenses described in section 213(d) of the Code incurred or anticipated to be incurred by the Participant, the Participant’s spouse or any dependents of the Participant (as defined in section 152 of the Code); |
| (ii) | the purchase (excluding mortgage payments) of a principal residence of the Participant; |
| (iii) | the payment of tuition, related educational fees, and room and board expenses, for the next twelve months of post-secondary education for the Participant, the Participant’s spouse, children or dependents; |
| (iv) | the need to prevent eviction of the Participant from his or her principal residence or foreclosure of the mortgage of the Participant’s principal residence. |
(B) A distribution shall be deemed to be necessary to satisfy a financial need of the Participant if, and only if, the Participant:
| (i) | has obtained all distributions, other than hardship withdrawals, and all nontaxable loans under any Employer’s plan in which the Participant participates, and |
| (ii) | demonstrates to the satisfaction of the Administrator that the distribution is not in excess of the amount of the immediate and heavy financial need, which need shall include amounts necessary to pay any federal, state and local income taxes, excise taxes and penalties. |
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If a Participant receives a hardship withdrawal pursuant to this Section 8.1(a), then, in addition to the cessation of Before-Tax Contributions and After-Tax Contributions required by Section 4.1(a), contributions by the Participant to qualified or nonqualified plans of deferred compensation, including a stock option, stock purchase or similar plan, maintained by an Employer also shall cease beginning with the first payroll period beginning after the date on which the Participant receives such hardship withdrawal and continuing until the first payroll period that coincides with or follows the date on which contributions ceased by twelve months (or, for hardship withdrawals made after December 31, 2001, six months).
(b) Withdrawals After Age 59½. An Employee who has attained age 59½ may make a request by calling the VRU, or in such other manner as may be prescribed by the Administrator, to withdraw as of any date an amount which is not greater than the balance of his or her Before-Tax Contributions Account and Employer Matching Contributions Account as of the most recent Valuation Date determined by the Administrator, except that while any loan to the Participant under Section 8.2 remains outstanding, the amount available for withdrawal shall be the balance in such accounts less the balance of all outstanding loans to the Participant.
(c) Withdrawals From the After-Tax Contributions Account. An Employee may make a request by calling the VRU, or in such other manner as may be prescribed by the Administrator, no more than once during any Plan Year, to withdraw from his or her After-Tax Contributions Account an amount which is not greater than the balance of the Participant’s After-Tax Contributions Account as of the most recent Valuation Date determined by the Administrator, except that while any loan to the Participant under Section 8.2 remains outstanding, the amount available for withdrawal shall be the balance in such account less the balance of all outstanding loans to the Participant.
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(d) Withdrawals from the Rollover Account. A Participant may make a request by calling the VRU, or in such other manner as may be prescribed by the Administrator, to withdraw an amount which is not greater than the balance in his or her Rollover Account as of the most recent Valuation Date determined by the Administrator, except that while any loan to the Participant under Section 8.2 remains outstanding, the amount available for withdrawal shall be the balance in such account less the balance of all outstanding loans to the Participant.
(e) Provisions Applicable to All Withdrawals. Any withdrawal made pursuant to this Section 8.1 shall be made at such time as prescribed by the Administrator and shall be made pro-rata from each of the investment funds in which as of the date of the withdrawal (i) in the case of a withdrawal pursuant to paragraph (a) or (b) of this Section 8.1, the Participant’s Before-Tax Contributions Account (and, if applicable, Employer Matching Contributions Account) is invested, (ii) in the case of a withdrawal pursuant to paragraph (c) of this Section 8.1, the Participant’s After-Tax Contributions Account is invested and (iii) in the case of a withdrawal pursuant to paragraph (d) of this Section 8.1, the Participant’s Rollover Account is invested. Notwithstanding anything in the Plan to the contrary, the Administrator or the Investment Administrator may impose any restrictions it deems necessary or appropriate with respect to withdrawals by individuals who have any portion of their accounts invested in the Employer Stock Fund described in Section 6.2 and who are subject to Rule 16b-3 under section 16 of the Securities Exchange Act of 1934.
(f) Dividend Distributions in Respect of the Employer Stock Fund. Dividends shall be allocated to the accounts of each Participant, any portion of whose account balance is invested in the Employer Stock Fund in accordance with Section 7.1(b), based upon the total number of shares of Common Stock represented by the Participant’s proportionate share of the Employer
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Stock Fund as of such date as may be determined from time to time by the Administrator on or before each dividend record date. Cash dividends shall be reinvested in Common Stock (through the Employer Stock Fund) unless the Participant (or his or her Beneficiary) elects, at the time and in the manner prescribed by the Administrator, to receive a cash distribution in an amount equal to such dividend, payable not later than 90 days after the end of the Plan Year in which such dividend was paid.
Section 8.2. Loans to Participants.
(a) Making of Loans. Subject to the restrictions set forth in this Section, the Administrator shall establish a loan program whereby any Participant who is a party-in-interest (within the meaning of section 3(14) of ERISA) or any Beneficiary who is a party-in-interest other than a Participant who is an Employee of IBEW Local Union 15 and any such Participant’s Beneficiary may request, in the manner and form prescribed by the Administrator, to borrow funds from the Plan. The principal amount of such loan shall be not less than $1,000 and the aggregate amount of all outstanding loans to a Participant or Beneficiary shall not exceed the lesser of: (1) 50% of the value of the aggregate of the Participant’s vested account balances as of the Valuation Date coinciding with or immediately preceding the day on which the loan is made; and (2) $50,000, reduced by the excess, if any, of the highest outstanding loan balances of the Participant under all plans maintained by the Employer during the period of time beginning one year and one day prior to the date such loan is to be made and ending on the date such loan is to be made over the outstanding balance of loans from all such plans on the date on which such loan was made.
(b) Restrictions. Any loan approved by the Administrator pursuant to the preceding paragraph (a) shall be made only upon the following terms and conditions:
(1) The period for repayment of the loan shall be arrived at by mutual agreement between the Administrator and the Participant but such period shall not exceed
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five years or, in the case of a loan to acquire a principal place of residence, shall not be less than five years or more than 15 years, from the date of the loan. Such loan may be prepaid at any time, without penalty, by delivery to the Administrator of a check in an amount equal to the entire unpaid balance of such loan. No partial prepayment shall be permitted. Except as otherwise provided under uniform and nondiscriminatory procedures established by the Administrator, any loan to a Participant who is an Employee is due in full immediately after termination of employment.
(2) No loan shall be made to a Participant who is an Employee unless such Participant consents to have such loan repaid in substantially equal installments deducted from the regular payments of the Participant’s compensation during the term of the loan. A Participant who (a) was an Employee at the time the Participant received a loan from the Plan, (b) is no longer an Employee and no longer receives compensation from an Employer, but (c) continues to perform services for an Employer, shall consent, either at the time the loan is taken or prior to the date prescribed by the Administrator, to have the balance of any loan outstanding at the time the Participant no longer is an Employee repaid in substantially equal installments over the remaining life of the loan. Such installments shall be paid in the manner specified by the Administrator.
(3) Each loan shall be evidenced by the Participant’s collateral promissory note, in the form prescribed by the Administrator, for the amount of the loan, with interest, payable to the order of the Plan, and shall be secured by an assignment of 50% of the Participant’s vested account balance.
(4) Each loan shall bear a fixed interest rate commensurate with the interest rates then being charged by persons in the business of lending money for loans made under similar circumstances, as determined by the Administrator.
(5) Except as otherwise provided in this Plan, no withdrawal (other than a withdrawal from a Participant’s accounts to the extent that such withdrawal would not reduce the Participant’s vested account balances to less than the then outstanding balance of any loan to such Participant or such higher amount determined by the Administrator to be appropriate security for such loan) or distribution shall be made to any Participant who has borrowed from the Trust, or to a Beneficiary of any such Participant, unless and until the loan, including interest, has been repaid.
(6) A charge shall be made against the account of each Participant requesting a loan equal to such reasonable loan application fee (and loan acceptance fee, if required by the Administrator) as shall be set from time to time by the Administrator.
(7) A Participant is permitted only one loan in any calendar year; provided, however, that no more than five loans to a Participant may be outstanding at any time.
(8) Loan repayments shall be invested in the various investment funds as elected by the Participant.
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(9) The Administrator may, in its sole discretion, restrict the amount to be disbursed pursuant to any loan request to the extent it deems necessary to take into account any fluctuations in the value of a Participant’s accounts since the Valuation Date immediately preceding the date on which such loan is to be made.
(10) Any restrictions the Administrator or the Investment Committee determines are necessary or appropriate with respect to loans requested by individuals who have any portion of their accounts invested in the Employer Stock Fund described in Section 6.2 and who are subject to Rule 16b-3 under section 16 of the Securities Exchange Act of 1934.
If any loan or portion of a loan made to a Participant under the Plan, together with the accrued interest thereon, is in default (taking into account any grace period permitted by law, and as determined by the Administrator), the Administrator shall take appropriate steps to collect on the note and foreclose on the security. If upon a Participant’s termination of employment entitling the Participant to a distribution under Section 8.3 (relating to distributions upon termination of employment), death or retirement, any loan or portion of a loan made to such Participant under the Plan, together with the accrued interest thereon, remains unpaid, such unpaid amount may be repaid to the Plan no later than the last day of the calendar quarter following the calendar quarter in which such termination of employment occurred or as of such later date or dates permitted under uniform and nondiscriminatory procedures established by the Administrator. If full repayment is not so made, an amount equal to the unpaid portion of such loan, together with the accrued interest thereon, shall be charged to the Participant’s accounts after all other adjustments required under the Plan, but before any distribution pursuant to Section 8.3 (relating to distributions upon termination of employment).
(c) Loan Subaccount. The Trustee shall establish and maintain a loan subaccount on behalf of each Participant or Beneficiary to whom a loan is made under this Section 8.2. Such subaccount shall represent the investment of the Participant’s or Beneficiary’s account in such loan. As of the Valuation Date immediately preceding the date on which a loan is approved, the
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Participant’s or Beneficiary’s loan subaccount shall be credited with the amount of the loan and thereafter shall be debited with repayments of the principal of such loan. The various accounts maintained for the Participant or Beneficiary shall be invested in the loan subaccount and debited by the amount of the loan and credited with payments of interest on, and repayments of principal of, such loan in accordance with uniform rules established by the Administrator.
(d) Sarbanes-Oxley. Notwithstanding any provision of the Plan to the contrary, the Administrator reserves the right to deny the request of a Participant for a loan that, in the judgment of the Administrator, would violate any provision of the Sarbanes-Oxley Act of 2002.
Section 8.3. Distributions Upon Termination of Employment.
(a) Termination of Employment under Circumstances Entitling Participant to Full Distribution of His or Her Account Balance. If a Participant terminates employment, the Participant, or his or her designated Beneficiary, as the case may be, shall be entitled to receive the entire balance of the Participant’s accounts, at the time set forth in Section 8.4 and in the manner set forth in paragraph (b) of this Section 8.3.
(b) Form of Distribution. (1) Subject to Section 8.4(d) any distribution to which a Participant or Beneficiary, as the case may be, becomes entitled upon termination of employment shall be distributed by whichever of the following forms of distribution the Participant or Beneficiary, as the case may be, elects by calling the VRU, or in such other manner as may be prescribed by the Administrator:
| (A) | By payment in a lump sum. |
| (B) | By payment in a series of approximately equal annual, quarterly, or monthly installments, over a period of up to 15 years; provided that installments shall not be available with respect to amounts invested in the CNA 1997 guaranteed investment contract. |
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A Participant who elected to receive distribution of his or her vested account balance in the form of installments may, at any time after such election is made, elect to receive the remaining amount of his or her vested account balance in the form of a lump sum payment. If no election is made by a Participant or Beneficiary, as the case may be, as to the form of distribution, the Participant’s vested account balance shall be distributed in the form of a lump sum payment.
The amount distributed hereunder shall be paid in cash, except that if the Participant’s account is paid in a lump sum, then the Participant may request that all of his or her account invested in the Employer Stock Fund be distributed in whole shares of Common Stock held in such Fund with any fractional share being paid in cash. The number of shares of Common Stock to be distributed shall be based on the current fair market value of a share of Common Stock as determined by the Trustee under Section 7.2 as of the Valuation Date coinciding with or immediately preceding the date payment of the Participant’s account is to be made. Requests for distribution in the form of Common Stock shall be made at such time and in such manner as the Administrator shall determine under rules and regulations which are uniformly applied.
Notwithstanding the preceding paragraphs, no distribution shall be made in the form of installments with respect to a Participant’s Rollover Account that was established to hold the amount distributed or directly transferred from the Commonwealth Edison Company Employee Stock Ownership Plan upon such plan’s termination if the Participant elected not to receive distribution of such amount until his or her 65th birthday.
(c) Notice of Availability of Election of Optional Forms of Benefits. No less than 30 days (or such shorter period as permitted by law) and no more than 90 days before distribution is to be made hereunder, the Administrator, or its designee, shall explain to the Participant that he or she may elect either form of distribution set forth in paragraph (b) of this Section 8.3. Such
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explanation shall include a general description of the eligibility conditions and other material features of the optional forms of distribution provided under the Plan. Notwithstanding the first sentence of this subsection, distribution may commence less than 30 days after the description described above is given, provided that: (i) the Administrator, or its designee, clearly informs the Participant that the Participant has a right to a period of at least 30 days after receiving the explanation to consider the decision of whether or not to elect a distribution (and, if applicable, a particular distribution option), and (ii) the Participant, after receiving the explanation, affirmatively elects a distribution. The description referred to in this subsection, as well as the explanation of the participant’s right to a period of at least 30 days to consider such explanation before electing a distribution, shall be provided to the Participant through the VRU or in such other manner prescribed by the Administrator.
(d) Small Benefits Payable in Lump Sum. Notwithstanding any provision of the Plan to the contrary, if the vested amount of the Participant’s account balances does not exceed $5,000 (or such other amount prescribed by section 411(a)(11) of the Code), not including the value of the Participant’s Rollover Account (such amount referred to herein as the “small benefit amount”), such vested amount shall be distributed in a lump sum cash payment as soon as administratively practicable after the Participant’s termination of employment in accordance with such procedures as may be established by the Administrator.
(e) Direct Rollover Option. In the case of a distribution from the Plan (excluding any amount offset against the Participant’s account balance to repay the outstanding balance of any unpaid loan) which is an “eligible rollover distribution” within the meaning of section 402(c)(4) of the Code (excluding hardship distributions, as described in section 410(k)(2)(B)(i)(IV) of the Code, which are attributable to the Participant’s Before-Tax Contributions), a Participant (or
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surviving spouse of a Participant) may elect that all or any portion of such distribution shall be directly transferred as a rollover contribution from this Plan to (i) an individual retirement account described in section 408(a) of the Code, (ii) an individual retirement annuity described in section 408(b) of the Code, (iii) an annuity plan described in section 403(a) of the Code, another plan qualified under section 401(a) of the Code and (v) effective January 1, 2002, an annuity contract described in Section 403(b) of the Code or an eligible deferred compensation plan described in Section 457(b) of the Code which is maintained by an eligible employer described in Section 457(e)(1)(A) of the Code (the terms of which permit the acceptance of rollover contributions) (provided, however, that for distributions made prior to January 1, 2002, a surviving spouse of a Participant may only elect to have such distribution directly transferred to an individual retirement account or individual retirement annuity); provided, however, that the portion of any such distribution consisting of after-tax contributions may only be so transferred as part of a distribution made on or after January 1, 2002 and may only be transferred to such an account or annuity described in section 408 of the Code, or to such a retirement or annuity plan described in Section 401(a) or 403(a) of the Code that is a defined contribution plan that agrees to separately account for amounts so transferred, including separately accounting for the portion of such amount which is includible of gross income and the portion of such distribution which is not so includible.
Section 8.4. Time of Distribution.
A Participant who has terminated employment shall commence receiving distribution of his or her vested account balance as soon as administratively practical after the Valuation Date coinciding with or immediately following the date on which the Participant attains age 65, except as provided below.
| (1) | Early Distribution. Except as provided in subparagraph (7), a Participant whose Termination Date is prior to his or her 65th birthday may elect by calling the VRU, |
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| or in such other manner as may be prescribed by the Administrator, prior to his or her termination of employment to have distribution of his or her vested account balance commence within 60 days after the Valuation Date coinciding with or immediately following the Participant’s Termination Date. |
| (2) | Deferral of Distribution. A Participant may elect by calling the VRU, or in such other manner as may be prescribed by the Administrator, which election shall be made at the time prescribed by the Administrator, that distribution of his or her vested account balance commence as soon as practicable after the Participant’s attainment of age 70½. |
| (3) | Elections After Termination Date. Except as provided in subparagraph (7), a Participant who has terminated employment and whose distribution is to commence either after the Participant’s attainment of age 65 or 70½ may elect at any time by calling the VRU, or in such other manner as may be prescribed by the Administrator, to have distribution of his or her vested account balance made within 60 days after the date such election is made. |
| (4) | Required Beginning Date. Distributions paid or commencing during the Participant’s lifetime shall commence not later than April 1 of the calendar year following the calendar year in which the Participant attains age 70½, except that distributions made to a Participant who is not a “five percent owner” (as defined in section 416(i) of the Code) may commence on April 1 of the calendar year following the later of the calendar year in which the Participant attains age 70½ or the calendar year in which the Participant retires. Notwithstanding any provision of the Plan to the contrary, any distributions required by this subparagraph (i) with respect to calendar years beginning on or after January 1, 2001 and prior to January 1, 2003 shall be made not less rapidly than in accordance with the regulations under section 401(a)(9) of the Code that were proposed on January 17, 2001, and (ii) with respect to calendar years beginning on or after January 1, 2003 shall be made not less rapidly than in accordance with the regulations under section 401(a)(9) that were final effective January 1, 2003. |
| (5) | Distributions Commencing After Participant’s Death. Distributions commencing after the Participant’s death shall be completed within five years after the death of the Participant, except that (i) effective with respect to any Participant whose death occurs on or after January 1, 1995, regardless of when such Participant’s employment terminated, if the Participant’s Beneficiary is the Participant’s spouse, distribution may be deferred until the date on which the Participant would have attained age 70½ had he or she survived and (ii) if the Participant’s Beneficiary is a natural person other than the Participant’s spouse and distributions commence not later than one year after the Participant’s death, such distributions may be made over a period not longer than the life expectancy of such Beneficiary. If at the time of the Participant’s death, distribution of the Participant’s benefit has commenced, the remaining portion of the Participant’s benefit shall be paid in the manner elected by the Participant’s Beneficiary, but at least as rapidly as was the method of distribution being used prior to the Participant’s death. |
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| (6) | Distribution of Rollover Account After Termination Date. A Participant who has terminated employment or the Beneficiary of such Participant, as the case may be, may elect by calling the VRU, or in such other manner as may be prescribed by the Administrator prior to the time his or her vested account balance is distributed under this Section 8.4 to have distribution of the balance of his or her Rollover Account commence at such prior time as the Participant or Beneficiary shall elect, provided that, while any loan to the Participant under Section 8.2 remains outstanding, such distribution shall be made only to the extent that the balance of such Participant’s vested account balance remaining after such distribution will equal or exceed the balance of all outstanding loans to the Participant. |
| (7) | Compliance with Section 401(a)(9) of the Code. Notwithstanding any provision of the Plan to the contrary, all distributions will be made in accordance with section 401(a)(9) of the Code and the regulations promulgated thereunder, including the minimum distribution incidental death benefit requirement thereof. |
Notwithstanding anything contained herein to the contrary and except as provided in subparagraph (4) above, in the event that the recordkeeper for the Plan is changed, distributions may be made at such time as prescribed by the Administrator in order to accommodate the transfer of records to the new recordkeeper.
Section 8.5. Designation of Beneficiary.
Each Participant shall have the right to designate a Beneficiary or Beneficiaries (who may be designated contingently or successively and that may be an entity other than a natural person) to receive any distribution to be made under Section 8.3 (relating to distributions upon termination of employment) upon the death of such Participant or, in the case of a Participant who dies subsequent to termination of his or her employment but prior to the distribution of the entire amount to which he or she is entitled under the Plan, any undistributed balance to which such Participant would have been entitled, provided, however, that no such designation (or change thereof) shall be effective if the Participant was married on the date of the Participant’s death unless such designation (or change thereof) was consented to at the time of such designation (or change thereof) by the person who was the Participant’s spouse, in writing, acknowledging the effect of such consent and witnessed by a notary public or a Plan representative, or it is established
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to the satisfaction of the Administrator that such consent could not be obtained because the Participant’s spouse cannot be located or such other circumstances as may be prescribed in Regulations. Subject to the preceding sentence, a Participant may from time to time, without the consent of any Beneficiary, change or cancel any such designation. Such designation and each change therein shall be made in the form prescribed by the Administrator and shall be filed with the Administrator. A Participant’s beneficiary designation in effect under the PECO Energy Company Employee Savings Plan immediately prior to the Effective Date shall remain in effect under the Plan on and after the Effective Date until such time as such designation is changed or canceled in accordance with this Section 8.5. If (i) no Beneficiary has been named by a deceased Participant, (ii) such designation is not effective pursuant to the proviso contained in the first sentence of this section, or (iii) the designated Beneficiary has predeceased the Participant, any undistributed balance of the deceased Participant shall be distributed by the Trustee at the direction of the Administrator (a) to the surviving spouse of such deceased Participant, if any, or (b) if there is no surviving spouse, to the surviving children of such deceased Participant, if any, in equal shares, or (c) if there is no surviving spouse or surviving children, to the surviving parents of such deceased Participant, if any, in equal shares, or (d) if there is no surviving spouse, surviving children or surviving parents, to the executor or administrator of the estate of such deceased Participant or (e) if no executor or administrator has been appointed for the estate of such deceased Participant within six months following the date of the Participant’s death, in equal shares to the person or persons who would be entitled under the intestate succession laws of the state of the Participant’s domicile to receive the Participant’s personal estate. The marriage of a Participant shall be deemed to revoke any prior designation of a Beneficiary made by him or her and a divorce
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shall be deemed to revoke any prior designation of the Participant’s divorced spouse if written evidence of such marriage or divorce is received by the Administrator.
Section 8.6. Distributions to Minor and Disabled Distributees.
Any distribution under this Article that is payable to a distributee who is a minor or to a distributee who, in the opinion of the Administrator, is unable to manage his or her affairs by reason of illness or mental incompetency may be made to or for the benefit of any such distributee at such time consistent with the provisions of Section 8.5 and in such of the following ways as the legal representative of such distributee shall direct: (a) directly to any such minor distributee if, in the opinion of such legal representative, the distributee is able to manage his or her affairs, (b) to such legal representative, (c) to a custodian under a Uniform Gifts to Minors Act for any such minor distributee, or (d) to some near relative of any such distributee to be used for the latter’s benefit. Neither the Administrator nor the Trustee shall be required to see to the application by any third party other than the legal representative of a distributee of any distribution made to or for the benefit of such distributee pursuant to this Section.
Section 8.7. “Lost” Participants and Beneficiaries.
If within a period of five years following the death or other termination of employment of any Participant the Administrator in the exercise of reasonable diligence has been unable to locate the person or persons entitled to benefits under this Article 8, the rights of such person or persons shall be forfeited, provided, however, that the Plan shall reinstate and pay to such person or persons the amount of the benefits so forfeited upon a claim for such benefits made by such person or persons. The amount to be so reinstated shall be obtained from the total amount that shall have been forfeited pursuant to Section 8.3 during the Plan Year that the claim for such forfeited benefit is made. If the amount to be reinstated exceeds the amount of such forfeitures, the Employer in
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respect of whose Employee the claim for forfeited benefit is made shall make a contribution in an amount equal to the remainder of such excess. Any such contribution shall be made without regard to whether or not the limitations set forth in Section 4.5 will be exceeded by such contribution.
ARTICLE 9
PARTICIPANTS’ STOCKHOLDER RIGHTS
Section 9.1. Voting Shares of Common Stock.
Each Participant and Beneficiary shall be entitled to direct the Trustee as to the exercise of any voting rights attributable to shares of Common Stock then allocated to his or her account and the Trustee shall vote such shares according to the voting directions of the Participant or Beneficiary that have been timely submitted to the Trustee on forms provided by the Trustee for such purpose. Participants and Beneficiaries shall be permitted to direct the Trustee as to the exercise of any voting rights, including, but not limited to, any corporate matter that involves the voting of shares of Common Stock with respect to the approval or disapproval of any corporate merger or consolidation, recapitalization, reclassification, liquidation, dissolution, sale of substantially all assets of a trade or business, or similar transaction prescribed in Regulations. The Trustee shall with respect to any matter vote the shares of Common Stock credited to Participants’ accounts with respect to which the Trustee does not timely receive voting instructions in the same proportion as to shares the Trustee has received voting instructions. Written notice of any meeting of stockholders of the Company and a request for voting instructions shall be given by the Administrator or the Trustee, at such time and in such manner as the Administrator shall determine, to each Participant or Beneficiary entitled to give instructions for voting shares of Common Stock at such meeting. The Administrator shall establish and pay for a means by which Participants and Beneficiaries can expeditiously deliver such voting instructions to the Trustee.
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All instructions delivered by Participants or Beneficiaries shall be confidential and shall not be disclosed to any person, including the Employer.
Section 9.2. Tender Offers.
(a) In the event a tender offer is made generally to the stockholders of the Company to transfer all or a portion of their shares of Common Stock in return for valuable consideration, including but not limited to, offers regulated by section 14(d) of the Securities Exchange Act of 1934, as amended, each Participant or Beneficiary shall be entitled to direct the Trustee regarding how to respond to any such tender offer with respect to the number of shares of Common Stock then allocated to his or her account and the Trustee shall vote such shares according to the voting directions of the Participant or Beneficiary that have been timely submitted to the Trustee on forms provided by the Trustee for such purpose. A Participant or Beneficiary shall not be limited in the number of directions to tender or withdraw from tender that he or she can give, but shall not have the right to give directions to tender or withdraw from tender after a reasonable time established by the Trustee pursuant to paragraph (c) of this Section. The Trustee shall with respect to a tender offer decline to vote the shares of Common Stock credited to Participants’ accounts with respect to which the Trustee does not timely receive directions on how to respond to any such tender offer. All such directions shall be confidential and shall not be disclosed to any person, including the Employer.
(b) Within a reasonable time after the commencement of a tender offer, the Administrator shall provide to each Participant and Beneficiary:
| (i) | the offer to purchase as distributed by the offeror to the stockholders of the Company, |
| (ii) | a statement of the shares of Common Stock allocated to his or her account, and |
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| (iii) | directions as to the means by which a Participant can give directions with respect to the tender offer. |
The Administrator shall establish and pay for a means by which a Participant and Beneficiary can expeditiously deliver directions to the Trustee with respect to a tender offer. The Administrator shall transmit or cause to be transmitted to the Trustee aggregate numbers of shares to be tendered or withheld from tender representing directions of Participants and Beneficiaries. The Administrator, at its election, may engage an agent to receive directions from Participants and Beneficiaries and transmit them to the Trustee.
(c) The Trustee may establish a reasonable time, taking into account the time restrictions of the tender offer, after which it shall not accept directions of Participants or Beneficiaries.
ARTICLE 10
SPECIAL PARTICIPATION AND DISTRIBUTION RULES RELATING TO
REEMPLOYMENT OF TERMINATED EMPLOYEES AND EMPLOYMENT BY RELATED
ENTITIES
Section 10.1. Change of Employment Status.
If an Employee who is not a Participant becomes eligible to participate because of a change in his or her employment status, such Employee shall become a Participant as of the date of such change if either the Employee is not a member of a bargaining unit represented by IBEW Local Union 15 or the Employee has satisfied the eligibility service requirement set forth in Section 3.1; otherwise the Employee shall become a Participant in accordance with Section 3.1 following satisfaction of the eligibility service requirement.
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Section 10.2. Reemployment of an Eligible Employee Whose Employment Terminated Prior to His or Her Becoming a Participant.
(a) If the employment of an Eligible Employee who is a member of a bargaining unit represented by IBEW Local Union 15 terminated before the Employee satisfied the eligibility service requirement set forth in Section 3.1 and such Employee is thereafter reemployed by an Employer, such Employee shall be eligible to become a Participant in accordance with Section 3.1.
(b) If the employment of an Eligible Employee who is a member of a bargaining unit represented by IBEW Local Union 15 terminated after he or she had satisfied the eligibility service requirement set forth in Section 3.1 but prior to becoming a Participant is reemployed by an Employer, he or she shall not be required to satisfy again such requirement and shall be eligible to become a Participant upon filing an application in accordance with Section 3.2.
Section 10.3. Reemployment of a Terminated Participant.
If a terminated Participant is reemployed, the Participant shall not be required to satisfy again the eligibility service requirement set forth in Section 3.1 and shall again become a Participant upon filing an application in accordance with Section 3.2.
Section 10.4. Employment by an Affiliate.
If an individual is employed by an Affiliate, then any period of such employment shall be taken into account solely for the purposes of determining whether and when such individual is eligible to participate in the Plan under Article 3, when such individual has retired or otherwise terminated his or her employment for purposes of Article 8 to the same extent it would have been had such period of employment been as an Employee of his or her Employer.
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Section 10.5. Leased Employees.
A leased employee (within the meaning of section 414(n)(2) of the Code) shall not be eligible to participate in the Plan. If an individual who performed services as a leased employee (as defined below) of an Employer or an Affiliate becomes an Employee, or if an Employee becomes such a leased employee, then any period during which such services were so performed shall be taken into account solely for the purposes of determining whether and when such individual is eligible to participate in the Plan under Article 3 and determining when such individual has retired or otherwise terminated his or her employment for purposes of Article 8 to the same extent it would have been had such service been as an Employee. This Section shall not apply to any period of service during which such a leased employee was covered by a plan described in section 414(n)(5) of the Code. For purposes of this Plan, a “leased employee” shall mean any person who is not an employee of an Employer and who pursuant to an agreement between an Employer or Affiliate has performed services for an Employer or an Affiliate on a substantially full-time basis for a period of at least one year, which services were performed under the primary direction or control of an Employer or an Affiliate.
Section 10.6. Reemployment of Veterans.
(a) General. The provisions of this Section shall apply in the case of the reemployment by an Employer of an Eligible Employee, within the period prescribed by the Uniformed Service Employment and Reemployment Rights Act (“USERRA”), after the Employee’s completion of a period of Military Service. The provisions of this Section are intended to provide such Employees with the rights required USERRA and section 414(u) of the Code, and shall be interpreted in accordance with such intent.
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(b) Make Up of Before-Tax and After-Tax Contributions. Such Employee shall be entitled to make contributions under the Plan (“Make-Up Employee Contributions”), in addition to Before-Tax and After-Tax Contributions which the Employee elects to have made under the Plan pursuant to Section 4.1. From time to time while employed by an Employer, such Employee may elect to contribute Make-Up Employee Contributions during the period beginning on the date of such Employee’s reemployment and ending on the earlier of:
| (i) | the end of the period equal to the product of three and such Employee’s period of Military Service, and |
| (ii) | the fifth anniversary of the date of such reemployment. |
Such Employee shall not be permitted to contribute Make-Up Employee Contributions to the Plan in excess of the amount which the Employee could have elected to have made under the Plan in the form of Before-Tax and After-Tax Contributions if the Employee had continued in employment with his or her Employer during such period of Military Service. Such Employee shall be deemed to have earned “Compensation” from his or her Employer during such period of Military Service for this purpose in the amount prescribed by sections 414(u)(2)(B) and 414(u)(7) of the Code. The manner in which an Eligible Employee may elect to contribute Make-Up Employee Contributions pursuant to this paragraph (b) shall be prescribed by the Administrator.
(c) Make Up of Matching Contributions. An Eligible Employee who contributes Make-Up Employee Contributions as described in paragraph (b) shall be entitled to an allocation of Matching Contributions (“Make-Up Matching Contributions”) in an amount equal to the amount of Matching Contributions which would have been allocated to the Matching Contributions Account of such Eligible Employee under the Plan if such Make-Up Employee Contributions had been made in the form of Before-Tax or After-Tax Contributions (as applicable) during the period of such Employee’s Military Service. The amounts necessary to make such
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allocation of Make-Up Matching Contributions shall be derived from any forfeitures not yet applied towards Matching Contributions for the Plan Year in which the Make-Up Employee Contributions are made, and if such forfeitures are not sufficient for this purpose, then the Eligible Employee’s Employer shall make a special contributions which shall be utilized solely for purposes of such allocation.
(d) Application of Limitations and Nondiscrimination Rules. Any contributions made by an Eligible Employee or an Employer pursuant to this Section on account of a period of Military Service in a prior Plan Year shall not be subject to the limitations prescribed by Sections 4.2, 4.5 and 7.4 of the Plan (relating to sections 402(g), 404 and 415 of the Code) for the Plan Year in which such contributions are made. The Plan shall not be treated as failing to satisfy the nondiscrimination rules of Section 4.4 of the Plan (relating to sections 401(k)(3) and 401(m) of the Code) for any Plan Year solely on account of any make up contributions made by an Eligible Employee or an Employer pursuant to this Section.
ARTICLE 11
ADMINISTRATION
Section 11.1. The Administrator and the Investment Committee.
(a) The Administrator. The Company’s Director, Employee Benefit Plans & Programs, or such other person or committee appointed by the Compensation Committee of the Board of Directors from time to time (such director or other person or committee, the “Administrator”), shall be the “administrator” of the Plan, within the meaning of such term as used in ERISA. In addition, the Administrator shall be the “named fiduciary” of the Plan, within the meaning of such term as used in ERISA, solely with respect to administrative matters involving
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the Plan and not with respect to any investment of the Plan’s assets. The Administrator shall have the following duties, responsibilities and rights:
| (i) | The Administrator shall have the duty and discretionary authority to interpret and construe the Plan in regard to all questions of eligibility, the status and rights of Participants, distributees and other persons under the Plan, and the manner, time, and amount of payment of any distribution under the Plan. Benefits under the Plan shall be paid to a Participant or Beneficiary only if the Administrator, in its discretion, determines that such person is entitled to benefits. |
| (ii) | The Administrator shall direct the Trustee to make payments of amounts to be distributed from the Trust under Article 8. |
| (iii) | The Administrator shall supervise the collection of Participants’ contributions made pursuant to Article 5 and the delivery of such contributions to the Trustee. |
| (iv) | The Administrator shall have all powers and responsibilities necessary to administer the Plan, except those powers that are specifically vested in the Investment Committee or the Trustee. |
| (v) | Each Employer shall, from time to time, upon request of the Administrator, furnish to the Administrator such data and information as the Administrator shall require in the performance of its duties. |
| (vi) | The Administrator may require a Participant or Beneficiary to complete and file certain applications or forms approved by the Administrator and to furnish such information requested by the Administrator. The Administrator and the Plan may rely upon all such information so furnished to the Administrator. |
| (vii) | The Administrator shall be the Plan’s agent for service of legal process and forward all necessary communications to the Trustee. |
(b) Appointment of the Administrator. Pursuant to a resolution of the Compensation Committee of the Board of Directors of the Company, the Compensation Committee shall appoint the Administrator. The Compensation Committee shall have the right at any time, with or without cause, to remove the Administrator (including any member of a committee that constitutes the Administrator). The Administrator may resign and the resignation shall be effective upon delivery
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of the written resignation to the Compensation Committee. Upon the resignation, removal or failure or inability for any reason of the Administrator to act hereunder, the Compensation Committee shall appoint a successor. Any successor Administrator member shall have all the rights, privileges and duties of the predecessor, but shall not be held accountable for the acts of the predecessor. The power and authority of the Compensation Committee with respect to the Plan shall be limited solely to the appointment and removal of the Administrator and the Compensation Committee shall have no other duties or responsibilities with respect to the Plan. None of the Company, any member of the Board of Directors who is not a member of the Compensation Committee, nor any other person shall have any responsibility regarding the appointment or removal of the Administrator.
(c) The Investment Committee. The Investment Committee shall be the “named fiduciary” of the Plan, within the meaning of such term as used in ERISA, solely with respect to matters involving the investment of assets of the Plan and, any contrary provision of the Plan notwithstanding, in all events subject to the limitations contained in Sections 404(a)(2) and 404(c) of ERISA and all other applicable limitations. The Investment Committee shall have the following duties, responsibilities and rights:
| (i) | The Investment Committee shall be the “named fiduciary” for purposes of designating the investment funds under Section 6.2 and for purposes of appointing one or more investment managers as described in ERISA. |
| (ii) | The Investment Committee shall be solely responsible for all matters involving investment of the Employer Stock Fund described in Section 6.2 and neither the Company nor any other person shall have any responsibility with respect to investment of such fund. |
| (iii) | Each Employer shall, from time to time, upon request of the Investment Committee, furnish to the Investment Committee such data and information as the Investment Committee shall require in the performance of its duties. |
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(d) Appointment of the Investment Committee. Pursuant to a resolution of the Risk Management Committee of the Board of Directors of the Company, the Risk Management Committee shall appoint the Investment Committee, which shall consist of not less than three members. The Risk Management Committee shall have the right at any time, with or without cause, to remove one or more members of the Investment Committee. Any member of the Investment Committee may resign and the resignation shall be effective upon delivery of the written resignation to the Risk Management Committee. Upon the resignation, removal or failure or inability for any reason of any member of the Investment Committee to act hereunder, the Risk Management Committee shall appoint a successor. Any successor Investment Committee member shall have all the rights, privileges and duties of the predecessor, but shall not be held accountable for the acts of the predecessor. The power and authority of the Risk Management Committee with respect to the Plan shall be limited solely to the appointment and removal of the members of the Investment Committee and the Risk Management Committee shall have no other duties or responsibilities with respect to the Plan. None of the Company, any member of the Board of Directors who is not a member of the Risk Management Committee, nor any other person shall have any responsibility regarding the appointment or removal of the members of Investment Committee.
(e) Status of Administrator and Members of the Investment Committee. The Administrator and any member of the Investment Committee may, but need not, be an Employee, trustee or officer of an Employer and such status shall not disqualify such person from taking any action hereunder or render such person accountable for any distribution or other material advantage received by him or her under this Plan, provided that no Administrator or member of
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the Investment Committee who is a Participant shall take part in any action of the Administrator or the Investment Committee or any matter involving solely his or her rights under this Plan.
(f) Notice to Trustee of Members. Promptly after the appointment of the Administrator or the Investment Committee and from time to time thereafter, and promptly after the appointment of any successor member of either the Administrator or the Investment Committee, the Trustee shall be notified as to the names of the persons so appointed by delivery to the Trustee of a written instrument duly adopted by the Compensation Committee of the Board of Directors or Risk Management Committee of the Board of Directors, as applicable, making such appointments.
(g) Allocation of Responsibilities. Each of the Administrator and the Investment Committee may allocate its respective responsibilities and may designate any person, persons, partnership or corporation to carry out any of such responsibilities with respect to the Plan. Any such allocation or designation shall be reduced to writing and such writing shall be kept with the records of the Plan.
(h) General Governance. Each of the Administrator and the Investment Committee may act at a meeting or by written consent approved by a majority of its respective members. The Investment Committee shall elect one of its members as chairman and appoint a secretary, who may or may not be a member of such committee. The secretary of the Investment Committee shall keep a record of all meetings and forward all necessary communications to the Employers or the Trustee. All decisions of the Investment Committee shall be made by the majority, including actions taken by written consent. The Administrator and the Investment Committee may adopt such rules and procedures as it deems desirable for the conduct of its affairs, provided that any such rules and procedures shall be consistent with the provisions of the Plan.
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(i) Indemnification. The Employers hereby jointly and severally indemnify the Administrator, the Investment Committee, the Risk Management Committee of the Board of Directors of the Company, the Compensation Committee of the Board of Directors of the Company, and the directors, officers and employees of the Employers and each of them, from the effects and consequences of their acts, omissions and conduct in their official capacity with respect to the Plan (including but not limited to judgments, attorney fees and costs with respect to any and all related claims, subject to the Company’s notice of and right to direct any litigation, select any counsel or advisor, and approve any settlement), except to the extent that such effects and consequences result from their own willful misconduct. The foregoing indemnification shall be in addition to (and secondary to) such other rights such persons may enjoy as a matter of law or by reason of insurance coverage of any kind.
(j) No Compensation. Neither the Administrator nor any member of the Investment Committee may receive any compensation or fee from the Plan for services as the Administrator or a member of the Investment Committee. The Employers shall reimburse the Administrator and the members of the Investment Committee for any reasonable expenditures incurred in the discharge of their duties hereunder.
(k) Employ of Counsel and Agents. The Administrator and the Investment Committee may employ such counsel (who may be counsel for an Employer) and agents and may arrange for such clerical and other services as each may require in carrying out its respective duties under the Plan.
Section 11.2. Claims Procedure.
Any Participant or distributee who believes he or she is entitled to benefits in an amount greater than those which he or she is receiving or has received may file a claim with the
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Administrator. Such a claim shall be in writing and state the nature of the claim, the facts supporting the claim, the amount claimed, and the address of the claimant. The Administrator shall review the claim and, unless special circumstances require an extension of time, within 90 days after receipt of the claim, give notice to the claimant, either in writing by registered or certified mail or in an electronic notification, of the Secretary’s decision with respect to the claim. Any electronic notice delivered to the claimant shall comply with the standards imposed by applicable Regulations. If the Administrator determines that special circumstances require an extension of time for processing the claim, the claimant shall be so advised in writing within the initial 90-day period and in no event shall such an extension exceed 90 days. The extension notice shall indicate the special circumstances requiring an extension of time and the date by which the Administrator expects to render the benefit determination. The notice of the decision of the Administrator with respect to the claim shall be written in a manner calculated to be understood by the claimant and, if the claim is wholly or partially denied, the Administrator shall notify the claimant of the adverse benefit determination and shall set forth the specific reasons for the adverse determination, the references to the specific Plan provisions on which the determination is based, a description of any additional material or information necessary for the claimant to perfect the claim, an explanation of why such material or information is necessary, and a description of the claim review procedure under the Plan and the time limits applicable to such procedures, including a statement of the claimant’s right to bring a civil action under Section 502 of ERISA following an adverse benefit determination on review. The Administrator shall also advise the claimant that the claimant or the claimant’s duly authorized representative may request a review by the Company’s Vice President, Employee Health and Benefits (or such other officer designated from time to time by the Compensation Committee) of the adverse benefit determination by filing
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with such officer, within 60 days after receipt of a notification of an adverse benefit determination, a written request for such review. The claimant shall be informed that, within the same 60-day period, he or she (a) may be provided, upon request and free of charge, reasonable access to, and copies of, all documents, records and other information relevant to the claimant’s claim for benefits and (b) may submit to such officer written comments, documents, records and other information relating to the claim for benefits. If a request is so filed, review of the adverse benefit determination shall be made by the officer within, unless special circumstances require an extension of time, 60 days after receipt of such request, and the claimant shall be given written notice of the officer’s final decision. If the officer determines that special circumstances require an extension of time for processing the claim, the claimant shall be so advised in writing within the initial 60-day period and in no event shall such an extension exceed 60 days. The extension notice shall indicate the special circumstances requiring an extension of time and the date by which the officer expects to render the determination on review. The review of the officer shall take into account all comments, documents, records and other information submitted by the claimant relating to the claim, without regard to whether such information was submitted or considered in the initial benefit determination. The notice of the final decision shall include specific reasons for the determination and references to the specific Plan provisions on which the determination is based and shall be written in a manner calculated to be understood by the claimant.
Section 11.3. Procedures for Domestic Relations Orders.
If the Administrator receives any written judgment, decree or order (including approval of a property settlement agreement) pursuant to domestic relations or community property laws of any state relating to the provision of child support, alimony or marital property rights of a spouse,
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former spouse, child or other dependent of a Participant and purporting to provide for the payment of all or a portion of the Participant’s benefit under the Plan to or on behalf of one or more of such persons (such judgment, decree or order being hereinafter called a “domestic relations order”), the Administrator shall promptly notify the Participant and each other payee specified in such domestic relations order of its receipt and of the following procedures. After receipt of a domestic relations order, the Administrator shall determine whether such order constitutes a “qualified domestic relations order,” as defined in Section 14.2(b), and shall notify the Participant and each payee named in such order in writing of its determination. Such notice shall be written in a manner calculated to be understood by the parties and shall set forth specific reasons for the Administrator’s determination, and shall contain an explanation of the review procedure under the Plan. The Administrator shall also advise each party that the party or his or her duly authorized representative may request a review by the Administrator’s determination by filing a written request for such review. The Administrator shall give each party affected by such request notice of such request for review. Each party also shall be informed that he or she may have reasonable access to pertinent documents and submit comments in writing to the Committee in connection with such request for review. Each party shall be given written notice of the Administrator’s final determination, which notice shall be written in a manner calculated to be understood by the parties and shall include specific reasons for such final determination. Any amounts subject to a domestic relations order which would be payable to the alternate payee prior to the determination that such order is a qualified domestic relations order shall be separately accounted for and not distributed prior to such determination. If within a reasonable time after receipt of written evidence of such order it is determined that such domestic order constitutes a qualified domestic relations order, the amounts so separately accounted for (plus any interest thereon) shall be paid to the alternate payee.
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If within such reasonable period of time it is determined that such order does not constitute a qualified domestic relations order, the amounts so separately accounted for (plus any interest thereon) shall be paid to such other persons, if any, entitled to such amounts at such time. Prior to the issuance of regulations, the Administrator shall establish the time periods in which the Administrator’s determination, a request for review thereof and the review by the Administrator shall be made, provided that the total of such time periods shall not be longer than 18 months from the date written evidence of a domestic relations order is received by the Administrator.
The duties of the Administrator under this Section may be delegated by the Administrator to one or more persons other than the Administrator.
Section 11.4. Notices to Participants, Etc.
All notices, reports and statements given, made, delivered or transmitted to a Participant or distributee or any other person entitled to or claiming benefits under the Plan shall be deemed to have been duly given, made or transmitted when mailed by first class mail with postage prepaid and addressed to the Participant or distributee or such other person at the address last appearing on the records of the Administrator. A Participant or distributee or other person may record any change of his or her address from time to time by written notice filed with the Administrator.
Section 11.5. Notices to Administrator.
Written directions, notices and other communications from Participants or distributees or any other person entitled to or claiming benefits under the Plan to the Administrator shall be deemed to have been duly given, made or transmitted either when delivered to such location as shall be specified upon the forms prescribed by the Administrator for the giving of such directions,
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notices and other communications or when mailed by first class mail with postage prepaid and addressed to the addressee at the address specified upon such forms.
Section 11.6. Records.
Each of the Administrator and the Investment Committee shall keep a record of all of their respective proceedings, if any, and shall keep or cause to be kept all books of account, records and other data as may be necessary or advisable in their respective judgment for the administration of the Plan or the administration of the investments of the Plan.
Section 11.7. Reports of Trustee and Accounting to Participants.
The Administrator shall keep on file, in such form as it shall deem convenient and proper, all reports concerning the Trust Fund received by it from the Trustee, and the Administrator may, as soon as possible after the close of each Plan Year, advise each Participant and Beneficiary of the balance credited to any account for his or her benefit as of the close of such Plan Year pursuant to Article 7 hereof.
Section 11.8. Electronic Media.
Notwithstanding any provision of the Plan to the contrary and for all purposes of the Plan, to the extent permitted by the Administrator and any applicable law or Regulation, the use of electronic technologies shall be deemed to satisfy any written notice, consent, delivery, signature, disclosure or recordkeeping requirement under the Plan, the Code or ERISA to the extent permitted by or consistent with applicable law and Regulations. Any transmittal by electronic technology shall be deemed delivered when successfully sent to the recipient, or such other time specified by the Administrator.
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ARTICLE 12
PARTICIPATION BY OTHER EMPLOYERS
Section 12.1. Adoption of Plan.
With the consent of the Company, any entity may become a participating Employer under the Plan by (a) taking such action as shall be necessary to adopt the Plan and (b) executing and delivering such instruments and taking such other action as may be necessary or desirable to put the Plan into effect with respect to such entity.
Section 12.2. Withdrawal from Participation.
Any Employer shall terminate its participation in the Plan at any time, under such circumstances as the Company may provide, by delivering to the Company a duly certified copy of a resolution of its board of directors (or other governing body) to that effect, or by ceasing to be a member of the same controlled group as the Company (within the meaning of section 1563(a) of the Code). A complete discontinuance of contributions by an Employer shall be deemed a termination of such Employer’s participation in the Plan for purposes of this Section.
Section 12.3. Company as Agent for Employers.
Each entity that becomes a participating Employer pursuant to Section 12.1 or Article 13 by so doing shall be deemed to have appointed the Company its agent to exercise on its behalf all of the powers and authorities hereby conferred upon the Company by the terms of the Plan, including, but not by way of limitation, the power to amend and terminate the Plan. The authority of the Company to act as such agent shall continue unless and until the portion of the Trust Fund held for the benefit of Employees of the particular Employer and their Beneficiaries is set aside in a separate Trust Fund as provided in Section 16.2.
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ARTICLE 13
CONTINUANCE BY A SUCCESSOR
In the event that the Employer is reorganized by way of merger, consolidation, transfer of assets or otherwise, so that another entity succeeds to all or substantially all of the Employer’s business, such successor entity may be substituted for the Employer under the Plan by adopting the Plan and becoming a party to the Trust agreement. Contributions by the Employer shall be automatically suspended from the effective date of any such reorganization until the date upon which the substitution of such successor entity for the Employer under the Plan becomes effective. If, within 90 days following the effective date of any such reorganization, such successor entity shall not have elected to become a party to the Plan, or if the Employer adopts a plan of complete liquidation other than in connection with a reorganization, the Plan shall be automatically terminated with respect to Employees of such Employer as of the close of business on the 90th day following the effective date of such reorganization or as of the close of business on the date of adoption of such plan of complete liquidation, as the case may be, and the Administrator shall direct the Trustee to distribute the portion of the Trust Fund applicable to such Employer in the manner provided in Article 16.
If such successor entity is substituted for an Employer by electing to become a party to the Plan as described above, then, for all purposes of the Plan, employment of such Employee with such Employer, including service with and compensation paid by such Employer, shall be considered to be employment with an Employer.
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ARTICLE 14
MISCELLANEOUS
Section 14.1. Expenses.
Except as provided in the last sentence of Section 6.2 (relating to expenses of investments for an investment fund), all costs and expenses incurred in administering the Plan and the Trust, including the expenses of the Administrator and the Investment Committee, the fees of counsel and any agents for the Administrator and the Investment Committee, the fees and expenses of the Trustee, the fees of counsel for the Trustee and other administrative expenses shall, to the extent permitted by law, be paid from the Trust Fund to the extent such expenses are not paid by the Employers. Notwithstanding the foregoing, the Administrator may authorize an Employer to pay any expenses, and the Employer shall be reimbursed from the Trust Fund for such payments. The Administrator, in its discretion, having regard to the nature of a particular expense, shall determine the portion of the expense that is to be borne by each Employer.
Section 14.2. Non-Assignability.
(a) In general. It is a condition of the Plan, and all rights of each Participant and Beneficiary shall be subject thereto, that no right or interest of any Participant or Beneficiary in the Plan shall be assignable or transferable in whole or in part, either directly or by operation of law or otherwise, including, but not by way of limitation, execution, levy, garnishment, attachment, pledge or bankruptcy, but excluding devolution by death or mental incompetency, and no right or interest of any Participant or Beneficiary in the Plan shall be liable for, or subject to, any obligation or liability of such Participant or Beneficiary, including claims for alimony or the support of any spouse, except as provided below.
(b) Exception for Qualified Domestic Relations Orders. Notwithstanding any provision of the Plan to the contrary, if a Participant’s account balance under the Plan, or any portion
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thereof, is the subject of one or more qualified domestic relations orders, as defined below, such account balance or portion thereof shall be paid to the person and at the time and in the manner specified in any such order. For purposes of this paragraph (b), “qualified domestic relations order” shall mean any “domestic relations order” as defined in Section 11.3 that creates (or recognizes the existence of) or assigns to a person other than the Participant (an “alternate payee”) rights to all or a portion of the Participant’s account balance under the Plan, and:
| (A) | clearly specifies |
| (i) | the name and last known mailing address (if any) of the Participant and each alternate payee covered by such order, |
| (ii) | the amount or percentage of this Participant’s benefits to be paid by the Plan to each such alternate payee, or the manner in which such amount or percentage is to be determined, |
| (iii) | the number of payments to, or period of time for which, such order applies, and |
| (iv) | each plan to which such order applies; |
| (B) | does not require |
| (i) | the Plan to provide any type or form of benefit or any option not otherwise provided under the Plan at the time such order is issued, |
| (ii) | the Plan to provide increased benefits (determined on the basis of actuarial equivalence), and |
| (iii) | the payment of benefits to an alternate payee that at the time such order is issued already are required to be paid to a different alternate payee under a prior qualified domestic relations order; and |
| (C) | does not require the commencement of payment of benefits to any alternate payee before the earlier of (I) the date on which the Participant is entitled to a distribution under the Plan and (II) the date the Participant attains age 50, except that the order may require the commencement of payment of benefits as soon as administratively practicable after the date such order is determined by the Administrator to be a “qualified domestic relations order”; |
all as determined by the Administrator pursuant to the procedures contained in Section 11.3. Any amounts subject to a domestic relations order prior to determination of its status as a qualified
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domestic relations order that but for such order would be paid to the Participant shall be segregated in a separate account or an escrow account pending such determination. If within the reasonable time period beginning with the date on which the first payment would be required to be made under a domestic relations order the Administrator determines that the domestic relations order constitutes a qualified domestic relations order, the amount so segregated (plus any interest thereof) shall be paid to the alternate payee. If such determination is not made within such reasonable time period, then the amount so segregated (plus any interest thereon), shall, as soon as practicable after the end of such reasonable time period, be paid to the Participant. Any determination regarding the status of such order after such reasonable time period shall be applied only to payments on or after the date of such determination.
Section 14.3. Employment Non-Contractual.
The Plan confers no right upon an Employee to continue in employment.
Section 14.4. Limitation of Rights.
A Participant or distributee shall have no right, title or claim in or to any specific asset of the Trust Fund, but shall have the right only to distributions from the Trust Fund on the terms and conditions herein provided.
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Section 14.5. Merger or Consolidation with Another Plan.
A merger or consolidation with, or transfer of assets or liabilities to, any other plan shall not be effected unless the terms of such merger, consolidation or transfer are such that each Participant, distributee, Beneficiary or other person entitled to receive benefits from the Plan would, if the Plan were to terminate immediately after the merger, consolidation or transfer, receive a benefit equal to or greater than the benefit such person would be entitled to receive if the Plan were to terminate immediately before the merger, consolidation, or transfer.
Section 14.6. Gender and Plurals.
Wherever used in the Plan, words in the masculine gender shall include masculine or feminine gender, and, unless the context otherwise requires, words in the singular shall include the plural, and words in the plural shall include the singular.
Section 14.7. Applicable Law.
The Plan and all rights hereunder shall be governed by and construed in accordance with the laws of the State of Illinois to the extent such laws have not been preempted by applicable federal law.
Section 14.8. Severability.
If a provision of the Plan shall be held illegal or invalid, the illegality or invalidity shall not affect the remaining parts of the Plan and the Plan shall be construed and enforced as if the illegal or invalid provision had not been included in the Plan.
Section 14.9. No Guarantee.
Neither the Administrator or the Investment Committee, the Employer, nor the Trustee in any way guarantees the Trust from loss or depreciation nor the payment of any money that may be
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or become due to any person from the Trust Fund. Nothing herein contained shall be deemed to give any Participant, distributee, or Beneficiary an interest in any specific part of the Trust Fund or any other interest except the right to receive benefits out of the Trust Fund in accordance with the provisions of the Plan and the Trust Fund.
ARTICLE 15
TOP-HEAVY PLAN REQUIREMENTS
Section 15.1. Top-Heavy Plan Determination.
If as of the determination date (as defined in Section 15.2) for any Plan Year (a) the sum of the account balances under the Plan and all other defined contribution plans in the aggregation group (as defined in Section 15.2) and (b) the present value of accrued benefits under all defined benefit plans in such aggregation group of all Participants in such plans who are key employees (as defined in Section 15.2) for such Plan Year exceeds 60 percent of the aggregate of the account balances and present value of accrued benefits of all participants in such plans as of the determination date (as defined in Section 15.2), then this Plan shall be a top-heavy plan for such Plan Year, and the requirements of Sections 15.3 and 15.4 shall be applicable for such Plan Year as of the first day thereof. If the Plan shall be a top-heavy plan for any Plan Year and not be a top-heavy plan for any subsequent Plan Year, the requirements of this Article shall not be applicable for such subsequent Plan Year.
Section 15.2. Definitions and Special Rules.
(a) Definitions. For purposes of this Article, the following definitions shall apply:
| (1) | Determination Date. The determination date for all plans in the aggregation group shall be the last day of the preceding Plan Year, and the valuation date applicable to a determination date shall be (i) in the case of a defined contribution plan, the date as of which account balances are determined which is coincident with or immediately precedes the determination date, and (ii) in the case of a defined benefit plan, the date as of which the most |
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| recent actuarial valuation for the Plan Year that includes the determination date is prepared, except that if any such plan specifies a different determination or valuation date, such different date shall be used with respect to such plan. |
| (2) | Aggregation Group. The aggregation group shall consist of (a) each plan of an Employer in which a key Employee is a participant, (b) each other plan that enables such a plan to be qualified under section 401(a) of the Code, and (c) any other plans of an Employer that the Company designates as part of the aggregation group and that shall permit the aggregation group to continue to meet the requirements of sections 401(a) and 410 of the Code with such other plan being taken into account. |
| (3) | Key Employee. Key Employee shall have the meaning set forth in section 416(i) of the Code. |
| (4) | Compensation. Compensation shall have the meaning set forth in section 415(c)(3) of the Code. |
(b) Special Rules. For the purpose of determining the accrued benefit or account balance of a Participant, the accrued benefit or account balance of any person who has not performed services for an employer at any time during the 1-year period ending on the determination date shall not be taken into account pursuant to this Section. Any person who received a distribution from a plan (including a plan that has terminated) in the aggregation group during the 1-year period ending on the last day of the preceding Plan Year shall be treated as a Participant in such plan, and any such distribution shall be included in such Participant’s account balance or accrued benefit, except that in the case of any distribution made for a reason other than separation from service, death or disability, this sentence shall be applied by substituting “5-year period” for the “1-year period” stated herein.
Section 15.3. Minimum Contribution for Top-Heavy Years.
Notwithstanding any provision of the Plan to the contrary, the sum of the Employer contributions under Article 4 (other than Before-Tax Contributions described in Section 4.1) allocated to the account of each Participant (other than a key Employee) during any Plan Year and
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the forfeitures allocated to the account of such Participant (other than a key Employee) during any Plan Year for which the Plan is a top-heavy plan shall in no event be less than the lesser of (i) three percent of such Participant’s compensation during such Plan Year and (ii) the highest percentage at which contributions are made on behalf of any key Employee for such Plan Year. Notwithstanding the preceding sentence, if the percentage determined pursuant to clause (ii) of the preceding sentence is less than 3%, such percentage shall be recalculated by including Before-Tax Contributions made on behalf of key employees. Such minimum contribution shall be made even if, under other provisions of the Plan, the Participant would not otherwise be entitled to receive an allocation or would receive a lesser allocation for the year because of (i) the Participant’s failure to complete 1,000 Hours of Service, or (ii) compensation of less than a stated amount. If, during any Plan Year for which this Section is applicable, a defined benefit plan is included in the aggregation group and such defined benefit plan is a top-heavy plan for such Plan Year, the percentage set forth in clause (i) of the first sentence of this Section shall be five percent. The percentage referred to in clause (ii) of the first sentence of this Section shall be obtained by dividing the aggregate of contributions made pursuant to Article 4 and pursuant to any other defined contribution plan that is required to be included in the aggregation group (other than a defined contribution plan that enables a defined benefit plan that is required to be included in such group to be qualified under section 401(a) of the Code) during the Plan Year on behalf of such key Employee by such key Employee’s compensation for the Plan Year. Notwithstanding the above, the provisions of this Section 15.3 shall not apply for any Plan Year with respect to an Eligible Employee who has accrued the defined benefit minimum provided under section 416 of the Code under a qualified defined benefit plan maintained by an Employer or Affiliate.
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ARTICLE 16
AMENDMENT, ESTABLISHMENT OF SEPARATE PLAN AND TERMINATION
Section 16.1. Amendment.
The Company may at any time and from time to time amend or modify the Plan by resolution of the Board of Directors of the Company or the Compensation Committee thereof; provided, however, that the Plan may be amended or modified by action of the Company’s Senior Vice President and Chief Human Resources Officer or another executive officer holding a title of equivalent or greater responsibility to the extent such amendment or modification is consistent with any delegation of such authority by the Compensation Committee of the Board of Directors. No amendment shall be made in respect of Eligible Employees who are members of a bargaining unit represented by IBEW Local Union 15 that is inconsistent with that portion of the collective bargaining agreement between such an Employer and IBEW Local Union 15 concerning the Plan.
Section 16.2. Establishment of Separate Plan.
If an Employer withdraws from the Plan under Section 12.2, the Administrator may determine the portion of the Trust Fund held by the Trustee that is applicable to the Participants and former Participants of such Employer and direct the Trustee to segregate such portion in a separate Trust Fund. Such separate Trust Fund shall thereafter be held and administered as a part of the separate plan of such Employer.
The portion of the Trust Fund applicable to the Participants and former Participants of a particular Employer shall be the sum of:
| (a) | the total amount credited to all accounts that are applicable to the Participants and former Participants of such Employer and |
| (b) | an amount that bears the same ratio to the excess, if any, of |
| (i) | the total value of the Trust Fund over |
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| (ii) | the total amount credited to all accounts |
as the total amount credited to the accounts that are applicable to the Participants of such Employer bears to the total amount credited to such accounts of all Participants.
Section 16.3. Termination and Distributions upon Termination of the Plan.
The Company has established the Plan with the bona fide intention and expectation that contributions will be continued indefinitely, but the Company will not have any obligation or liability whatsoever to maintain the Plan for any given length of time and may terminate the Plan at any time by resolution of the Board of Directors or the Compensation Committee thereof, to that effect, without any liability whatsoever for any such termination. Notwithstanding the preceding sentence, the Plan shall not be terminated in respect of Eligible Employees who are members of a bargaining unit represented by IBEW Local Union 15 if such termination is inconsistent with the portion of the collective bargaining agreement between the Employer of such Eligible Employees and IBEW Local Union 15 concerning the Plan. The Plan will be deemed terminated: (a) if and when the Company is judicially declared bankrupt, or (b) upon dissolution of the Company.
Upon termination of the Plan by the Company or withdrawal from participation in the Plan by any Employer pursuant to Section 12.2 or the partial termination of the Plan with respect to a group of Employees or complete discontinuance of contributions hereunder, distributions shall be made to each affected Participant or other persons entitled to distributions pursuant to Article 8 (relating to withdrawals and distributions). If the entire Plan is terminating, upon the completion of distribution to all Participants, the Trust will terminate, the Trustee will be relieved from all liability under the Trust, and no Participant or other person will have any claims thereunder, except as required by applicable law.
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Notwithstanding the preceding paragraph, no distribution shall be made to any Participant (i) until he or she attains age 59½ except as otherwise provided in Section 8.3 (relating to distributions upon termination of employment) or (ii) if a successor plan, as defined in Regulations, is established or maintained by the Participant’s Employer.
To the extent that no discrimination in value results, any distribution after termination or partial termination of the Plan may be made, in whole or in part, in cash, in securities or other assets in kind, or in non-transferable annuity contracts, as the Administrator (in its discretion) may determine. All non-cash distributions shall be valued at fair market value at date of distribution.
If the Internal Revenue Service refuses to issue an initial, favorable determination letter that the Plan and Trust Fund as adopted by an Employer meet the requirements of section 401(a) of the Code and that the Trust Fund is exempt from tax under section 501(a) of the Code, the Employer may terminate its participation in the Plan and shall direct the Trustee to pay and deliver the portion of the Trust Fund applicable to the Participants of such Employer, determined pursuant to Section 16.2 to such Employer and such Employer shall pay to Participants or their beneficiaries the part of such Employer’s portion of the Trust Fund as is attributable to contributions made by Participants.
Section 16.4. Trust Fund to Be Applied Exclusively for Participants and Their Beneficiaries.
Subject only to the provisions of Section 4.5 (relating to the limitation on Employer contributions), 7.4 (relating to limitations on allocations imposed by section 415 of the Code) and 16.3 (relating to distribution upon termination of the Plan), and any other provision of the Plan to the contrary notwithstanding, it shall be impossible for any part of the Trust Fund to be used for or diverted to any purpose not for the exclusive benefit of Participants and their Beneficiaries either by operation or termination of the Plan, power of amendment or other means.
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SUPPLEMENT I
Transfers from Other Plans
With the consent of the Administrator, whenever a participant in any other qualified savings or profit sharing plan maintained for employees of an entity any of whose assets or stock are acquired by an Employer (the “Other Plan”) becomes a Participant in this Plan, then such Participant’s interest in the Other Plan may be transferred to the Trustee of this Plan and credited to administrative subaccounts to be held, invested, reinvested and distributed pursuant to the terms of the Plan and the Trust and, as of the date of the transfer of any such Participant’s interest in the Other Plan,
| (a) | there shall be credited to the Before-Tax Contributions Account of such Participant that portion of his interest in the Other Plan which is transferred to the Trustee and which represents the Participant’s salary reduction contributions, if any, made to the Other Plan on behalf of the Participant, |
| (b) | there shall be credited to the After-Tax Account of such Participant that portion of his interest in the Other Plan which is transferred to the Trustee and which represents the Participant’s after-tax contributions, if any, made to the Other Plan, |
| (c) | there shall be credited to the Employer Matching Contributions Account of such Participant that portion of his interest in the Other Plan which is transferred to the Trustee and which represents the matching contributions and other employer contributions, if any, made to the Other Plan on behalf of the Participant, and |
| (d) | there shall be credited to the Rollover Account of such Participant that portion of his interest in the Other Plan which is transferred to the Trustee and which represents the Participant’s rollover contributions, if any, to the Other Plan. |
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Any amounts credited to a Participant’s Before-Tax Contributions Account, After-Tax Contributions Account, Employer Matching Contributions Account and Rollover Account shall be credited to the administrative subaccounts in accordance with such Participant’s investment direction in effect as of the date of such transfer. Any special provisions applicable to amounts transferred to the Trustee from any Other Plan shall be set forth in an Exhibit hereto.
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SUPPLEMENT II
Elective Transfers Between This Plan and Plans of Affiliates or the TXU 401(k) Plan
A. Transfers to this Plan. Whenever an individual who is employed by an Affiliate that is not an Employer has a change in employment status that results in such individual (a) becoming an Eligible Employee and (b) being ineligible to make additional elective contributions under a plan maintained by such Affiliate (an “Affiliate Plan”), such Eligible Employee may elect to transfer his or her benefits under the Affiliate Plan to this Plan. Such election must be conditioned upon a voluntary, fully-informed election by the Eligible Employee. In the event that the Eligible Employee makes such election, his or her benefits under the Affiliate Plan shall be credited to his account under this Plan, and such benefits shall be subject to the terms of, and paid as prescribed by, this Plan, and the terms of the Affiliate Plan shall not apply with respect to such benefits.
An individual who becomes an Eligible Employee in connection with the Company’s 2002 acquisition of from Texas Utilities, Inc. (“TXU”) may elect to transfer his or her benefits under TXU’s 401(k) plan (the “TXU Plan”) to this Plan. Such election must be conditioned upon a voluntary, fully-informed election by the Eligible Employee. In the event that the Eligible Employee makes such election, his or her benefits under the TXU Plan shall be credited to his account under this Plan, and such benefits shall be subject to the terms of, and paid as prescribed by, this Plan, and the terms of the TXU Plan shall not apply with respect to such benefits.
B. Transfers from this Plan. Whenever a Participant has a change in employment status that results in such Participant (a) ceasing to be an Eligible Employee and (b) becoming eligible to participate in an Affiliate Plan, such Participant may elect to transfer his or her benefits under this Plan to the Affiliate Plan. Such election must be conditioned upon a
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voluntary, fully-informed election by the Participant. In the event that the Participant makes such election, the Participant, effective at the time of the transfer, shall not be entitled to any benefits under this Plan and the benefits transferred to the Affiliate Plan shall be subject to the terms of, and paid as prescribed by, the Affiliate Plan, and the terms of this Plan shall not apply with respect to such benefits.
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SUPPLEMENT III
Merger of Certain AmerGen Plans into this Plan
Purpose. The purpose of this Supplement III is to reflect the merger of the AmerGen Clinton Employee Savings Plan for Nonbargaining Employees (the “Clinton Plan”) and the AmerGen TMI and Oyster Creek Employee Savings Plan for Nonbargaining Employees (collectively, the “AmerGen Plans”) into the Plan effective February 1, 2004 (the “Merger Date”) and to preserve those provisions of the AmerGenPlans that cannot be eliminated by amendment without violating section 411(d)(6) of the Internal Revenue Code and applicable Treasury regulations thereunder.
Definitions. Unless the context clearly indicates otherwise, a term defined in the Plan shall have the same meanings for purposes of this Supplement III.
Conflicts Between the Plan and this Supplement III. This Supplement III and the Plan together comprise the Plan with respect to AmerGen Plan Participants (as defined below). In case of any conflict between the provisions of the Plan and this Supplement III, the terms and provisions of this Supplement III shall govern to the extent necessary to eliminate such conflict.
AmerGen Plan Participants. This Supplement III shall be applicable to all AmerGen Plan Participants. “AmerGen Plan Participants” are participants in the Plan who were participants in the AmerGen Plans and whose account balances under the AmerGen Plans were merged into the Plan.
Vesting. All AmerGen Plan Participants shall be fully vested in their accounts under the Plan.
Withdrawals of Employer Matching Contributions. Notwithstanding any provision in the Plan to the contrary, an AmerGen Plan Participant who, immediately prior to the Merger Date was a participant in the Clinton Plan (“Clinton Participant”) who has completed 60 months as either a participant in the Clinton Plan or a participant in this Plan may elect, in accordance with procedures established by the Administrator, to receive a distribution of all or any part of his or her Employer Matching Contributions Account that is attributable to contributions made under the Clinton Plan, as adjusted for gains, earnings and losses attributable thereto determined as of the Valuation Date next succeeding the date of receipt of the request for distribution.
Additionally, a Clinton Participant, regardless of his or her period of participation in the Clinton Plan or this Plan, may elect, in accordance with procedures established by the Administrator, to receive a distribution of all or any part of that portion of the Employer Matching Contributions Account that is attributable to contributions made under the Clinton Plan and that is derived from Employer Matching Contributions in excess of Employer Matching Contributions allocated to his or her Employer Matching Contributions Account during the two Plan Years preceding the Plan Year in which the withdrawal takes place, adjusted for gains, earnings and losses attributable thereto determined as of the Valuation Date next succeeding the date of receipt of the request for distribution.
No distribution made pursuant to this paragraph F may be for an amount which is less than the lesser of (i) $200; or (ii) that portion of the Participant’s Employer Matching Contributions Account that is attributable to contributions made under the Clinton Plan, as adjusted for gains, earnings and losses attributable thereto. In addition, a Participant may not make more than one withdrawal pursuant to this paragraph F in any Plan Year.
Loans. With respect to any loan to an AmerGen Plan Participant that is outstanding at the Merger Date, the terms of such loan shall continue to be governed by the note evidencing such loan and the terms applicable to such loan as in effect under the AmerGen Plans as of the Merger Date. All loans made after the Merger Date shall be governed by and in accordance with the terms of the Plan and any loan policy issued thereunder by the Administrator.
S-5
Exhibit 10-46
Exelon Corporation
10 South Dearborn Street – 37th Floor
Chicago, Illinois 60603
November 1, 2004
Mr. Oliver D. Kingsley, Jr.
252 Highland View Drive
Birmingham, Alabama 35242
Dear Oliver:
I am writing to confirm our agreement regarding the disposition of the shares of Exelon Corporation (“Exelon”) common stock that you currently own, any shares of Exelon common stock that you may receive from us pursuant to any performance share or other incentive awards, and any shares of Exelon common stock that you may acquire upon the exercise of your options to purchase such shares of common stock.
Share Repurchase. We have agreed to repurchase shares (including shares deliverable upon the exercise of options) held by you as follows:
| • | 172,765 shares on November 17, 2004 and |
| • | 187,235 shares on February 9, 2005. |
We have agreed to make those repurchases at a purchase price per share (the “Purchase Price”) equal to the weighted-average of the closing prices of Exelon common stock as reported on the New York Stock Exchange composite transactions tape for each of the ten trading days ending immediately before the second business day preceding the scheduled repurchase date. You will receive the Purchase Price, in the case of shares that you hold that we repurchase, and will receive the difference between the Purchase Price and the option exercise price per share, in the case of shares that you would hold if you exercised any unexercised vested options that you elect to include in such repurchase. You have agreed to notify us at least three business days in advance of a scheduled repurchase date if you wish to include in that repurchase any shares issuable upon the exercise of any unexercised vested options that you hold. The aggregate amount we remit to you in connection with any repurchase (i) will be reduced for any federal income or other taxes that we are required to withhold in connection with that repurchase and any stock option exercise fees and (ii) will be wire transferred to such bank account as you shall direct in a written notice delivered to us at least three business days in advance of the scheduled repurchase date. You will deliver to us any documentation required to effect or confirm the transfer of the repurchased shares to us, including, in the case of any unexercised stock option, any required notice of exercise.
Other Permitted Sales. You have agreed not to transfer beneficial ownership of any shares of Exelon common stock that you currently own, any shares of Exelon common stock that you may receive from us pursuant to any performance share or other incentive awards, and any shares of Exelon common stock that you may acquire upon the exercise of your options to purchase such shares (including any shares retained or liquidated to pay the exercise price or any applicable exercise fees or taxes), except as provided in the preceding paragraph and this paragraph. We have agreed that you may sell up to 360,000 shares (including any shares acquired upon the exercise of stock options and any shares retained or liquidated to pay the exercise price or any applicable exercise fees or taxes) at any time after May 1, 2005. We have also agreed that you may sell or otherwise transfer any shares that you continue to hold (including any shares acquired upon the exercise of stock options) at any time after January 1, 2006. Finally, we have agreed that you may transfer any shares and, subject to the terms of the applicable agreement and related plan, any unexercised stock options, that you currently hold to
Mr. Oliver D. Kingsley, Jr.
November 1, 2004
Page 2
Sally Y. Kingsley, not individually but as Trustee of the Kingsley 2004 Charitable Lead Annuity Trust, and to Sally Y. Kingsley, not individually but as Trustee of the Kingsley 2004 Annuity Trust; provided any such transferee trust must agree in writing to observe the transfer restrictions contained in this letter with respect to such shares or options to the same extent as you would be required and you shall remain responsible for any such transferee trust’s compliance. In connection with any sales permitted under this paragraph, you have agreed to consult us in advance as to the timing and amount of the proposed sale. You have also agreed to use reasonable efforts to moderate those sales.
We have indicated to you that we will consider removing some or all of the sales restrictions contained in the foregoing paragraph. Any such removal would be subject to our discretion. Notwithstanding any such removal, you would still be responsible for compliance with any restrictions on your sales and reporting obligations arising under the Federal securities laws.
Representations. We represent to you that we are authorized to enter into the agreements set forth in this letter. You have represented to us that (i) you are able to enter into the agreements set forth in this letter, (ii) you have had sufficient access to information regarding Exelon and its business, financial condition, results of operations and prospects, and are sufficiently knowledgeable regarding those matters, in order to make an informed decision regarding the repurchases described in this letter under “Share Repurchase,” including the timing and pricing of those repurchases, (iii) you are not relying upon Exelon or any of its officers to make any further disclosures to you or to update any disclosures previously made, (iv) you own the shares and the options to acquire shares that are the subject of this agreement and (v) upon transfer of any shares to us in connection with our purchase of such shares, we shall acquire title to them free and clear of all liens, claims and encumbrances.
Notices. Any notices under this agreement shall be in writing, shall be sent by U.S. mail or recognized overnight delivery service, and shall be effective when received. Notices shall be addressed to you and us (attention Executive Vice President and General Counsel) at our respective addresses set forth above or to such other address(es) as you or we shall have notified the other by written notice.
Amendments; Waivers. Any change to the terms of this agreement must be in writing, state that it is an amendment and be signed by you and us. Any waiver must also be in writing and shall be effective only with respect to the action or inaction described therein and not with respect to any reoccurrence of such action or inaction (unless the waiver otherwise expressly so states).
Governing Law. This agreement shall be governed by and construed in accordance with the internal laws (as opposed to the conflict of laws provisions) of the State of Illinois.
* * * *
If the foregoing accurately reflects our agreement, please so indicate by signing a copy of this letter in the space provided below and returning it to us.
Sincerely,
S/ RANDALL E. MEHRBERG
Randall E. Mehrberg
Executive Vice President and General Counsel
AGREED:
S/ OLIVER D. KINGSLEY, JR.
Oliver D. Kingsley, Jr.
Date: November 8, 2004
Exhibit 10.48
EXELON CORPORATION
SENIOR MANAGEMENT
SEVERANCE PLAN
(As Amended Through September 1, 2004)
EXELON CORPORATION
SENIOR MANAGEMENT SEVERANCE PLAN
(As Amended Through September 1, 2004)
| 1. | PURPOSE OF THE PLAN |
The Exelon Corporation Senior Management Severance Plan, as set forth herein (the “Plan”), is effective as of September 1, 2004. The Plan was originally amended and restated effective July 1, 2003 (the “Effective Date”), and is an amendment and restatement of, and supersedes in its entirety, the Second Amended and Restated Exelon Corporation Key Management Severance Plan. The Plan provides severance benefits to eligible executives of Exelon Corporation (“Exelon”) and its subsidiaries of which Exelon owns at least 50% of the outstanding voting power that are participating employers in the Plan (Exelon and such subsidiaries jointly and severally referred to as the “Company”) who submit a Notice of Termination or who are notified of their termination of employment on or after the Effective Date, and to provide additional protection in the event of a Change in Control of Exelon or an Imminent Control Change of Exelon.
| 2. | ELIGIBILITY |
| 2.1. | Eligibility in General. In order to be eligible to become a Participant, each employee of the Company whose position is Vice President(or equivalent executive grade) or above (an “Executive”) must execute and return to the Company by the later of 90 days after becoming an Executive, or 90 days after delivery thereof to the Executive, non-competition, non-solicitation, confidential information and intellectual property covenants (“Restrictive Covenants”) which are acceptable to Exelon and are either substantially in the form attached hereto and made a part hereof as Exhibit I (as may be modified from time to time by Exelon in its sole discretion) or set forth in another agreement between the Company and the Executive. Notwithstanding any provision of the Plan to the contrary, eligibility for benefits under the Plan shall be subject to the provisions of any agreement (including but not limited to a grant instrument) between an Executive and the Company providing that that such Executive would be ineligible for (or waives) all or a portion of the benefits under the Plan or “change in control” benefits in the event of a termination of employment, or under which the Executive had agreed, prior to the Applicable Trigger Date, to terminate his or her employment. In addition, no Participant shall be entitled to any material enhancement to the separation benefits provided under the Plan without the written approval of the Chief Executive Officer of Exelon and the consent of the Chairman of the Compensation Committee of Exelon’s Board of Directors. |
| 2.2. | Eligibility Under Section 4. Subject to Section 2.1, each Executive shall be eligible for the benefits provided under Section 4 hereof in the event such Executive has a Termination of Employment; provided, however, that any Executive whose Termination of Employment is covered under Section 5 hereof |
| or a change in control agreement entered into between such Executive and the Company (an “Individual Change in Control Agreement”) shall not be eligible for benefits under Section 4, except as expressly provided in Section 5 or such Individual Change in Control Agreement (which expressly refers to the benefits under Section 4 of this Plan). |
| 2.3. | Eligibility Under Section 5. Eligibility for the benefits provided under Section 5 hereof due to a Termination of Employment during a Post-Change Period or an Imminent Control Change Period shall be subject to Section 2.1, and shall be limited to persons who are Executives immediately prior to the Applicable Trigger Date and who are not subject to Individual Change in Control Agreements. |
| 3. | PARTICIPATION |
Each eligible Executive shall become a participant in the Plan (“Participant”) upon his or her execution of a separation agreement with the Company in such form as the Company, in its sole discretion, shall require or permit (the “Severance Agreement”). Each Executive shall also be required to execute, no later than the date of the Participant’s Termination of Employment or, if later, the date that is 45 days after the date the Executive is provided with a copy of a Severance Agreement, a waiver and release of claims against the Company (“Waiver and Release”) which is substantially in the form attached hereto and made a part hereof as Exhibit II, as may from time to time be modified by the Company in its sole discretion. The Company shall have no obligation to an Executive under this Plan unless and until the Executive timely executes the Restrictive Covenants, a Severance Agreement and a Waiver and Release.
| 4. | BENEFITS |
Subject to Section 6, a Participant described in Section 2.2 shall be entitled to benefits pursuant to this Section 4 upon the Participant’s Termination of Employment.
| 4.1. | Severance Pay. |
| (a) | In General. Each Participant other than a Participant described in Section 4.1(b) shall receive severance pay at a monthly rate equal to 1/12 of the sum of (a) the Participant’s annual base salary in effect as of the date of Termination of Employment, plus (b) the Severance Incentive. Payment shall be made in regular payroll installments for the duration of the applicable Salary Continuation Period, as indicated below, commencing no later than the second paydate which occurs after the date of the Participant’s Termination of Employment, but in no event earlier than the date which is eight days after the date the Participant returns an executed Waiver and Release to the Plan Administrator. Payment will be made in accordance with the Company’s normal payroll practices, net of applicable taxes and other deductions. |
| Participant Level |
Salary Continuation Period | |
| Senior Executive Management |
24 months | |
| Other Executives |
15 months |
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| (b) | Participants Becoming Executives On or After Effective Date and Employed for Less Than Two Years. Each Participant who becomes an Executive on or after the Effective Date and who has been employed by the Company for less than two years as of the date of the Participant’s Termination Date shall receive severance pay at a monthly rate equal to 1/12 of the Participant’s annual base salary in effect as of the Termination Date. Payment shall be made in regular payroll installments for the duration of the applicable Salary Continuation Period, as indicated below, commencing no later than the second paydate which occurs after the date of the Participant’s Termination Date, but in no event earlier than the date which is eight days after the date the Participant returns an executed Waiver and Release to the Plan Administrator. Payment will be made in accordance with the Company’s normal payroll practices, net of applicable taxes and other deductions. |
| Participant Level |
Salary Continuation Period | |
| Senior Executive Management |
18 months (12 months if employed < 1 year) | |
| Other Executives |
12 months (6 months if employed < 1 year) |
| 4.2. | Annual Incentive Awards. Each Participant shall receive a Target Incentive which shall be prorated by multiplying the amount of such Target Incentive by a fraction the numerator of which is the number of days elapsed during such calendar year as of the Participant’s Termination Date and the denominator of which is 365. Payment of Target Incentives under this Section 4.2 shall be made in a lump sum net of applicable taxes and other deductions no earlier than the date which is eight days after the date the Participant returns an executed Waiver and Release to the Plan Administrator. |
| 4.3. | Stock Options. No Participant shall be entitled to participate in any grants of Stock Options (as defined in Section 5.1(b)) made after such Participant’s notification of his or her Termination of Employment. Except as provided below, any Stock Options previously granted to the Participant shall be exercisable only to the extent such Stock Options are exercisable as of the date of such Participant’s Termination Date and shall thereafter be exercised in accordance with the provisions of the LTIP. Stock Options which remain unexercisable as of the Participant’s Termination Date shall be forfeited. Notwithstanding the preceding, if, as of the Participant’s Termination Date, such Participant has attained at least age 50 and completed at least 10 years of service as defined under the tax-qualified defined benefit plan maintained by Exelon in which the Executive is a participant (the “Pension Plan”) (or who, pursuant to the terms of an offer of employment or employment agreement or under any provision of the Pension Plan or SERP, is credited with a number of additional years of age and/or service that would enable such Participant to satisfy the above eligibility requirements), then any Stock Options granted to such Participant which have not |
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| become exercisable prior to the Participant’s Termination Date shall (i) become fully vested, and (ii) remain exercisable until (1) the option expiration date for any such Stock Options granted prior to January 1, 2002 or (2) the fifth anniversary of the Termination Date or, if earlier, the option expiration date for any such Stock Options granted on or after January 1, 2002. |
| 4.4. | Other LTIP Awards. Awards of Performance Shares and/or Restricted Stock (as defined in Sections 5.1(c) and 5.1(d), respectively) shall be payable to a Participant solely to the extent provided under the terms of such Awards. |
| 4.5. | Health Care Coverage. During the Salary Continuation Period, a Participant (and his or her dependents) shall continue to participate in the health care plans under which he or she was covered immediately prior to his or her Termination of Employment, as such plans may be amended from time to time. The Participant’s out of pocket costs (including premiums, deductibles and co-payments) for such coverage shall be the same as that in effect from time to time for active peer employees during such period. Coverage under this Paragraph 4.5 shall be provided for the duration of the Salary Continuation Period in lieu of continuation coverage under Section 4980B of the Code and Section 601 to 609 of ERISA (“COBRA”) for the same period. At the end of the Salary Continuation Period, COBRA continuation coverage may be elected for the remaining balance of the statutory coverage period, if any; provided, however that a Participant who, as of the last day of the Salary Continuation Period has attained at least age 50 and completed at least 10 years of service (or who has completed any lesser age and service requirement then in effect under Exelon Corporation Severance Benefit Plan as of the relevant time set forth in such plan) under the terms of the Pension Plan (or who, pursuant to the terms of an offer of employment or employment agreement or under any provision of the Pension Plan or SERP, is credited with a number of additional years of age and/or service that would enable such Participant to satisfy the above eligibility requirements) shall be entitled to elect retiree health coverage under the Company’s health care plans on the same terms and subject to the same conditions as active peer employees who have completed 10 years of service after attaining age 45. |
| 4.6. | SERP. During the Salary Continuation Period, a Participant shall accrue service under the SERP solely for purposes of determining whether the Participant is vested (i.e., 5 years of service) and, to the extent relevant under the Pension Plan covering the Participant, the amount of the Participant’s benefit, but not for purposes of determining eligibility for early retirement benefits or any other purpose. In determining the amount of the Participant’s vested benefit, if any, the severance payments made under Section 4.1 shall be taken into account as if such payments were normal base salary and incentive payments. Payment shall be made in accordance with the Participant’s distribution election in effect under the SERP as of the Termination Date (or, if no affirmative election is in effect as of such date, the default election as of such date). In no event shall payment of the Participant’s vested SERP benefit, if any, commence prior to the conclusion of the Salary Continuation Period. |
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| 4.7. | Life Insurance and Disability Coverage. Continued coverage under the applicable life insurance and long term disability plans sponsored by the Company (or equivalent other equivalent coverage or benefits) shall be extended to each Participant through the last day of the Salary Continuation Period applicable to such Participant on the same terms and subject to the same conditions as are applicable to active peer employees (including, without limitation, submission of proof by an Executive who seeks long term disability benefits that such Executive would have satisfied the conditions for such benefits had the Executive been an employee during the Salary Continuation Period and terminated employment on or before the last day of such period). |
| 4.8. | Deferred Compensation Plans. The Participant’s deferral elections in effect as of the Termination Date under the applicable deferred compensation plans sponsored by the Company with respect to base salary and annual incentive awards shall be applied to the Participant’s severance pay under Section 4.1. The Participant’s benefits under such plans shall be paid following the Salary Continuation Period in accordance with the Participant’s distribution elections in effect for such plans as of the Termination Date. |
| 4.9. | Executive Perquisites. Executive perquisites shall terminate effective as of the Participant’s Termination Date, and any Company-owned property shall be required to be returned to the Company no later than such date; provided, however, that each Participant who is an officer of the Company and who has attained age 50 and completed 10 years of service pursuant to the terms of the Pension Plan or SERP shall be entitled to financial counseling services in accordance with the Company’s applicable policies or programs for a period of 24 months following the date of such Participant’s Termination of Employment. |
| 4.10. | Outplacement Services. Each Participant shall be entitled to outplacement services at the expense of the Company for such period (which shall not be less than six months) and subject to such terms and conditions as the Plan Administrator, in its sole discretion, determines are appropriate. No cash shall be paid in lieu of such fees and costs. |
| 5. | CHANGE IN CONTROL BENEFITS |
Subject to Section 6, a Participant described in Section 2.3 shall be entitled to benefits pursuant to this Section 5 if such a Participant has a Termination of Employment during a Post-Change Period or Imminent Control Change Period, and such Participant shall not be eligible for benefits under Section 4 unless so expressly provided in this Section 5.
| 5.1. | Termination During a Post-Change Period. If, during a Post-Change Period, an eligible Executive has a Termination of Employment and becomes a Participant, the Company’s sole obligations under Section 4 and Sections 5.1 and 5.2 shall be as set forth in this Section 5.1 (subject to Sections 5.3, 5.5, 5.6 and 5.7). |
| (a) | Severance Payments. The Company shall pay or provide (or cause to be provided) such Participant, according to the payment terms set forth in Section 5.3 below, the following: |
| (i) | Accrued Obligations. All Accrued Obligations; |
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| (ii) | Annual Incentive for Year of Termination. An amount equal to the Target Incentive applicable to such Participant under the Incentive Plan for the performance period in which the Termination Date occurs; |
| (iii) | Deferred Compensation and Non-Qualified Defined Contribution Plans. All amounts previously deferred by, or accrued to the benefit of, such Participant under the Exelon Corporation Deferred Compensation Plan, the Exelon Corporation Deferred Stock Plan, any successor of either of them, or under any other non-qualified defined contribution or deferred compensation plan of the Company,)) whether vested or unvested, together with any accrued earnings thereon, to the extent that such amounts and earnings have not been previously paid by the Company and are not provided under the terms of any such non-qualified plan; |
| (iv) | SERP Enhancement. An amount payable under the SERP equal to the positive difference, if any, between |
| (1) | the lump sum value of such Participant’s benefit, if any, under the SERP, calculated as if such Participant had |
| (a) | become fully vested in all Pension Plan and SERP benefits, |
| (b) | to the extent age is relevant under the Pension Plan covering the Participant, attained as of the Termination Date an age that is two years greater than such Participant’s actual age and that includes the number of years of age credited to such Participant pursuant to any other agreement between the Company and such Participant, |
| (c) | to the extent service is relevant under the Pension Plan covering the Participant, accrued a number of years of service (for purposes of determining the amount of such benefits, entitlement to - but not commencement of - early retirement benefits, and all other purposes of the Pension Plan and SERP) that is two years greater than the number of years of service actually accrued by such Participant as of the Termination Date and that includes the number of years of service credited to such Participant pursuant to any other agreement between the Company and such Participant, and |
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| (d) | received the severance benefits specified in Sections 5.1(a)(ii) and 5.1(a)(vi) as covered compensation in regular installments during the Severance Period, minus |
| (2) | the aggregate amounts paid or payable to such Participant under the SERP; |
| (v) | Unvested Benefits Under Pension Plan. An amount equal to the actuarial equivalent present value of any unvested portion of such Participant’s accrued benefit or cash balance account (as applicable) under the Pension Plan as of the Termination Date and forfeited by such Participant by reason of the Termination of Employment; and |
| (vi) | Multiple of Salary and Severance Incentive. An amount equal to two (2) times the sum of (x) Base Salary plus (y) the Severance Incentive, net of applicable taxes and other deductions. |
| (b) | Stock Options. Each of such Participant’s stock options granted under the LTIP (“Stock Options”) shall (i) become fully vested, and (ii) remain exercisable until (1) the option expiration date for any such Stock Options granted prior to January 1, 2002 or (2) the fifth anniversary of the Termination Date or, if earlier, the option expiration date for any such Stock Options granted on or after January 1, 2002. |
| (c) | LTIP Vesting. On the Termination Date, all of the performance shares granted to such Participant under the Exelon Performance Share Program under the LTIP (“Performance Shares”) to the extent earned by and awarded to such Participant (i.e. as to which the applicable performance cycle has elapsed) as of the Termination Date, shall become fully vested at the actual level earned and awarded, and, to the extent not yet earned by and awarded to such Participant (i.e. as to which the current performance cycle has not elapsed) as of the Termination Date, shall become fully vested at the LTIP Target Level. |
| (d) | Other Restricted Stock. All forfeiture conditions that as of the Termination Date are applicable to any deferred stock unit, restricted stock or restricted share units awarded to such Participant by Exelon other than under the Exelon Performance Share Program under the LTIP (“Restricted Stock”) shall (except as expressly provided to the contrary in the applicable awards) lapse immediately and all such awards will become fully vested, and within ten business days after the Termination Date, Exelon shall deliver or cause to be delivered to such Participant all of such shares theretofore held by or on behalf of Exelon. |
| (e) | Continuation of Welfare Benefits. During the Severance Period, the Company shall continue to provide to the Executive and the Executive’s dependents under its welfare plans, including medical, prescription, dental, |
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| disability, employee life, group life and accidental death benefits but excluding any severance pay (“Welfare Plans”) that covered the Participant or such Participant’s dependents prior to such Participant’s Termination of Employment, to the same extent as if such Participant had remained employed during the Severance Period. Such provision of welfare benefits shall be subject to the following: |
| (i) | In determining benefits applicable under such Welfare Plans, such Participant’s annual compensation attributable to base salary and incentives for any plan year or calendar year, as applicable, shall be deemed to be not less than such Participant’s Base Salary and annual incentive for the year in which the Termination Date occurs. |
| (ii) | The cost of such welfare benefits to such Participant and dependents under this Section 5.1(e) shall not exceed the cost of such benefits to peer executives who are actively employed during the Severance Period . |
| (iii) | Such Participant’s rights under this Section 5.1(e) shall be in addition to and not in lieu of any post-termination continuation coverage or conversion rights such Participant may have pursuant to applicable law, including, without limitation, continuation coverage required by COBRA. |
| (iv) | If such Participant has, as of the last day of the Severance Period, attained age 50 and completed at least 10 years of service with the Company, such Participant shall be entitled to the retiree benefits provided under any Welfare Plan of the Company; provided, however, that for purposes hereof, any years of age and/or credited service granted to such Participant in any other plan or agreement between such Participant and the Company shall be taken into account. For purposes of determining eligibility for (but not the time of commencement of) such retiree benefits, such Participant shall also be considered (1) to have remained employed until the last day of the Severance Period and to have retired on the last day of such period, and (2) to have attained at least the age such Participant would have attained on the last day of the Severance Period. |
Notwithstanding the foregoing, if such Participant obtains a specific type of coverage under welfare plan(s) sponsored by another employer of such Participant (e.g. medical, prescription, vision, dental, disability, individual life insurance benefits, group life insurance benefits, but excluding for the purposes of this sentence retiree benefits if such Participant is so eligible), then the Company shall not be obligated to provide any such specific type of coverage. The Participant shall promptly notify the Plan Administrator of any such coverage.
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| (f) | Outplacement. To the extent actually incurred by such Participant, the Company shall pay or cause to be paid on behalf of such Participant, as incurred, all reasonable fees and costs charged by a nationally recognized outplacement firm selected by such Participant for outplacement services provided for up to 12 months after the Termination Date. No cash shall be paid in lieu of such fees and costs. |
| (g) | Indemnification. Such Participant shall be indemnified and held harmless by the Company to the greatest extent permitted under applicable law and the Company’s by-laws if such Participant was, is, or is threatened to be, made a party to any pending, completed or threatened action, suit, arbitration, alternate dispute resolution mechanism, investigation, administrative hearing or any other proceeding brought by a third party (and not by or on behalf of the Company or its shareholders) whether civil, criminal, administrative or investigative, and whether formal or informal, by reason of the fact that such Participant is or was, or had agreed to become, a director, officer, employee, agent, or fiduciary of the Company any other entity which such Participant is or was serving at the request of the Company (“Proceeding”), against all expenses (including all reasonable attorneys’ fees) and all claims, damages, liabilities and losses incurred or suffered by such Participant or to which such Participant may become subject for any reason; provided, that the Company shall have the right to direct all related litigation, approve any settlement and shall not be required to indemnify the Participant in connection with any proceeding initiated by the Participant, including a counterclaim or crossclaim, unless such proceeding was authorized by the Company. |
| (h) | Directors’ and Officers’ Liability Insurance. For a period of six years after the Termination Date, the Company shall provide such Participant with coverage under a directors’ and officers’ liability insurance policy in an amount no less than, and on terms no less favorable than, those provided to peer executives of the Company on the Applicable Trigger Date. |
| 5.2. | Termination During an Imminent Control Change Period. If, during an Imminent Control Change Period, a Participant has a Termination of Employment, then such Participant shall receive benefits at the time and in the manner provided in Section 4 and the Company’s sole obligations to such Participant under Sections 5.1 and 5.2 shall be as set forth in this Section 5.2 (and subject to Sections 5.3, 5.5, 5.6 and 5.7). The Company’s obligations to such Participant under this Section 5.2 shall in all events be reduced by any amounts or benefits paid or provided pursuant to Section 4. |
| (a) | Cash Severance Payments. If the Imminent Control Change Period culminates in a Change Date, the Company shall pay (or cause to be paid) to such Participant, a lump-sum cash amount, within thirty business days after the later of the Termination Date or the Change Date, equal to the sum of all amounts described in Section 5.1(a)(i) through (v). The amount |
9
| described in Section 5.1(a)(vi) shall be paid to such Participant as described in Section 5.3, provided that amounts that would have been paid prior to the Change Date shall be paid in a lump sum (without interest) within 30 business days after the Change Date. |
| (b) | Vested Stock Options. Such Participant’s Stock Options, to the extent vested on the Termination Date, |
| (i) | will not expire (unless such Stock Options would have expired had such Participant remained an employee of the Company) during the Imminent Control Change Period; and |
| (ii) | will continue to be exercisable after the Termination Date to the extent provided in the applicable grant agreement or the LTIP, and thereafter such Stock Options shall not be exercisable during the Imminent Control Change Period. |
If the Imminent Control Change Period lapses without a Change Date, then such Participant’s Stock Options, to the extent vested on the Termination Date, may be exercised, in whole or in part, during the 30-day period following the lapse of the Imminent Control Change Period, or, if longer, the period during which such Participant’s vested Stock Options could otherwise be exercised under the terms of the applicable grant agreement or the LTIP (but in no case shall any Stock Options remain exercisable after the date on which such Stock Options would have expired if such Participant had remained an employee of the Company).
If the Imminent Control Change Period culminates in a Change Date, then effective upon the Change Date, such Participant’s Stock Options, to the extent vested on the Termination Date, may be exercised in whole or in part by such Participant at any time until (1) the option expiration date for such Stock Options granted prior to January 1, 2002 or (2) the earlier of the fifth anniversary of the Change Date or the option expiration date for such Stock Options granted on or after January 1, 2002.
| (c) | Unvested Stock Options. Such Participant’s Stock Options that are not vested on the Termination Date: |
| (i) | will not expire (unless such Stock Options would have expired had such Participant remained an employee of the Company) during the Imminent Control Change Period; and |
| (ii) | will not continue to vest and will not be exercisable during the Imminent Control Change Period. |
If the Imminent Control Change lapses without a Change Date, such unvested Stock Options will thereupon expire.
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If the Imminent Control Change culminates in a Change Date, then immediately prior to the Change Date, such unvested Stock Options shall become fully vested, and may thereupon be exercised in whole or in part by such Participant at any time until (1) the option expiration date for such Stock Options granted prior to January 1, 2002 or (2) the earlier of the fifth anniversary of the Change Date, or the option expiration date for such Stock Options granted on or after January 1, 2002.
| (d) | Performance Shares. Such Participant’s Performance Shares granted under the Exelon Performance Share Program under the LTIP will not be forfeited during the Imminent Control Change Period, and will not continue to vest during the Imminent Control Change Period. If the Imminent Control Change lapses without a Change Date, such Performance Shares shall be governed according to the terms of Section 4. If the Imminent Control Change Period culminates in a Change Date: |
| (i) | All Performance Shares granted to such Participant under the Exelon Performance Share Program under the LTIP, which, as of the Termination Date, have been earned by and awarded to such Participant, shall become fully vested at the actual earned level on the Change Date, and |
| (ii) | All of the Performance Shares granted to such Participant under the Exelon Performance Share Program under the LTIP which, as of the Termination Date, have not been earned by and awarded to such Participant shall become fully vested on the Change Date at the LTIP Target Level. |
| (e) | Restricted Stock. Such Participant’s unvested Restricted Stock will: |
| (i) | not be forfeited during the Imminent Control Change Period; and |
| (ii) | not continue to vest during the Imminent Control Change Period. |
If the Imminent Control Change Period lapses without a Change Date, such unvested Restricted Stock shall thereupon be forfeited.
If the Imminent Control Change Period culminates in a Change Date, then immediately prior to the Change Date, such Participant’s Restricted Stock shall (except as expressly provided to the contrary in the award) become fully vested, and within ten business days after the Change Date, the Company shall deliver to such Participant all of such shares theretofore held by or on behalf of the Company, which will be subject to the same terms which other stockholders of the Company receive in the transaction.
| (f) | Continuation of Welfare Benefits. The Company shall continue to provide (or cause to be provided) to such Participant and such Participant’s dependents welfare benefits (other than any severance pay that may be |
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| considered a welfare benefit) that covered the Participant or such Participant’s dependents prior to such Participant’s Termination of Employment, during the Imminent Control Change Period, to the same extent as if such Participant had remained employed during such period, subject to the following: |
| (i) | in determining benefits applicable under such Welfare Plans, such Participant’s annual compensation attributable to base salary and incentives for any plan year or calendar year, as applicable, shall be deemed to be not less than such Participant’s Base Salary and annual incentive for the year in which the Termination Date occurs; |
| (ii) | the cost of such welfare benefits to such Participant and dependents under this Section 5.2(f) shall not exceed the cost of such benefits to peer executives who are actively employed by the Company during the Imminent Control Change Period; and |
| (iii) | such Participant’s rights under this Section 5.2(f) shall be in addition to and not in lieu of any post-termination continuation coverage or conversion rights such Participant may have pursuant to applicable law, including, without limitation, continuation coverage required by COBRA. |
If the Imminent Control Change Period lapses without a Change Date, welfare benefit plan coverage under this Section 5.2(f) shall thereupon cease, subject to such Participant’s rights, if any, to continued coverage under a Welfare Plan, Section 4, or applicable law. If the Imminent Control Change Period culminates in a Change Date, then for the remainder of the Severance Period, the Company shall continue to provide such Participant and such Participant’s dependents welfare benefits as described in, and subject to the limitations of Section 5.1(e).
Notwithstanding the foregoing, if such Participant obtains a specific type of coverage under welfare plan(s) sponsored by another employer of such Participant (e.g. medical, prescription, vision, dental, disability, individual life insurance benefits, group life insurance benefits, but excluding for the purposes of this sentence retiree benefits if such Participant is so eligible), then the Company shall not be obligated to provide any such specific type of coverage. The Participant shall immediately notify the Plan Administrator of any such coverage.
| (g) | Indemnification. Such Participant shall be indemnified and held harmless by the Company to the same extent as provided in Section 5.1(g), but only during the Imminent Control Change Period (or greater period provided under the Company’s by-laws) if the Imminent Control Change Period lapses without a Change Date. |
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| (h) | Termination During an Imminent Control Change Period: Directors’ and Officers’ Liability Insurance. The Company shall provide the same level of directors’ and officers’ liability insurance for such Participant as provided in Section 5.1(h), but only during the Imminent Control Change Period (or greater period provided under the Company’s by-laws) if the Imminent Control Change Period lapses without a Change Date. |
| 5.3. | Timing of Severance Payments. Unless otherwise specified herein, the amounts described in Sections 5.1(a)(i), (ii), and, subject to any applicable payment deferral election in effect as of the Termination Date with respect to such Participant under the applicable deferred compensation plan, (iii), shall be paid within 30 business days of the Termination Date (or eight days after the date on which the Participant executes and returns a Waiver and Release, if later). The amounts described in Sections 5.1(a)(iv) and (v) shall be paid following the Severance Period in accordance with the Participant’s distribution election in effect under the SERP as of the Termination Date (or, if no affirmative election is in effect as of such date, the default election as of such date). The severance payments described in Section 5.1(a)(vi) shall be paid beginning no later than the second paydate which occurs after the Termination Date (or eight days after the date on which the Participant executes and returns a Waiver and Release, if later), in periodic payments to a Participant according to the Company’s normal payroll practices at a monthly rate equal to 1/12 of the sum of (i) such Participant’s Base Salary in effect as of the Termination Date plus (ii) the Severance Incentive. |
| 5.4. | Other Terminations of Employment by the Company or a Participant. |
| (a) | Obligations. If, during a Post-Change Period or an Imminent Control Change Period, (i) the Company terminates an eligible Executive’s employment for Cause (or causes a Participant to be terminated for Cause) (“Cause Termination”) or disability (as determined by the Plan Administrator in good faith), (ii) an Executive elects to retire or otherwise terminate employment other than for Good Reason, disability or death, or (iii) an eligible Executive’s employment terminates on account of death, the Company shall have no obligations to such Executive under Section 5. The remaining applicable provisions of this Plan (including the Restrictive Covenants) shall continue to apply. |
| (b) | Procedural Requirements. The Company shall strictly observe or cause to be strictly observed each of the following procedures in connection with any Cause Termination during a Post-Change Period or an Imminent Control Change Period: an eligible Executive’s termination of employment shall not be deemed to be for Cause under this Section 5.4 unless and until there shall have been delivered to such Executive a written notice of the determination of the Chief Executive Officer of the Executive’s employer (“CEO”) (after reasonable written notice of such consideration by the CEO of acts or omissions alleged to constitute Cause is provided to such Executive and such Executive is given an opportunity to present a written response to the CEO regarding such allegations), |
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| finding that, in his or her good faith opinion, such Executive’s acts, or failure to act, constitutes Cause and specifying the particulars thereof in detail. |
| 5.5. | Sole and Exclusive Obligations. The obligations of the Company under this Plan with respect to any Termination of Employment occurring during a Post-Change Period or Imminent Control Change Period shall supersede any severance obligations of the Company in any other plan of the Company or agreement between such Participant and the Company, including, without limitation, Section 4, any offer of employment or employment contract of the Company which provides for severance benefits, except as explicitly provided in Section 5.2 or to the extent such Participant is ineligible for such benefits or such benefits are waived pursuant to Section 2.1. |
| 5.6. | Payment Capped. If at any time or from time to time, it shall be determined by the Company’s independent auditors that any payment or other benefit to a Participant pursuant to Section 5 of this Plan or otherwise (“Potential Parachute Payment”) is or will become subject to the excise tax imposed by Section 4999 of the Code or any similar tax payable under any United States federal, state, local, foreign or other law (“Excise Taxes”), then the Potential Parachute Payments payable to such Participant shall be reduced to the largest amount which would both (a) not cause any Excise Tax to be payable by such Participant and (b) not cause any Potential Parachute Payments to become nondeductible by the Company by reason of Section 280G of the Code (or any successor provision). |
| 6. | TERMINATION OF PARTICIPATION; CESSATION OF BENEFITS |
A Participant’s benefits under Section 4 of the Plan shall terminate on the last day of the Participant’s Salary Continuation Period; provided that a Participant’s right to benefits shall terminate immediately on such date as the Company discovers that the Participant has breached any of the Restrictive Covenants or the Waiver and Release, or if at any time the Company determines that in the course of his employment the Executive engaged in conduct described in Section 7.9(b), (c) or (d), in which case the Company may require the repayment of amounts paid pursuant to Section 4.1 prior to such breach or other conduct, and shall discontinue the payment of any additional amounts under Section 4 of the Plan.
A Participant’s benefits under Section 5 of the Plan shall terminate on the later of the last day of the Participant’s Severance Period or the date all benefits to which the Participant is entitled to have been paid from the Plan; provided that a Participant’s right to benefits shall terminate immediately on the date the Company discovers that the Participant has breached any of the Restrictive Covenants or the Waiver and Release, or if at any time the Company determines, in accordance with the procedural requirements set forth in Section 5.4(b) that in the course of his employment the Executive engaged in conduct described in Section 7.9(b), (c) or (d), in which case the Company may require the repayment of amounts paid pursuant to Section 5 prior to such breach or other conduct, and shall discontinue the payment of any additional amounts under Section 5 of the Plan.
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| 7. | DEFINITIONS |
In addition to terms previously defined, when used in the Plan, the following capitalized terms shall have the following meanings unless the context clearly indicates otherwise:
| 7.1. | “Accrued Annual Incentive” means the amount of any annual incentive earned but not yet paid with respect to the Company’s latest fiscal year ended prior to the Termination Date. |
| 7.2. | “Accrued Base Salary” means the amount of a Participant’s Base Salary that is accrued but not yet paid as of the Termination Date. |
| 7.3. | “Accrued LTIP Award” means the amount of any LTIP award earned and vested, but either deferred or not yet paid as of the Termination Date. |
| 7.4. | “Accrued Obligations” means, as of any date, the sum of a Participant’s Accrued Base Salary, Accrued Annual Incentive, Accrued LTIP Award, and any accrued but unpaid paid time off. |
| 7.5. | “Applicable Trigger Date” means |
| (a) | the Change Date, with respect to a Post-Change Period; or |
| (b) | the date of an Imminent Control Change, with respect to the Imminent Control Change Period. |
| 7.6. | “Base Salary” for purposes of Section 5, means not less than 12 times the highest monthly base salary paid or payable to a Participant by the Company in respect of the 12-month period immediately before the Applicable Trigger Date. |
| 7.7. | “Beneficial Owner” means such term as defined in Rule 13d-3 of the SEC under the Exchange Act. |
| 7.8. | “Board” means the Board of Directors of Exelon or, from and after the effective date of a Corporate Transaction (as defined in the definition of Change in Control), the Board of Directors of the corporation resulting from a Corporate Transaction or, if securities representing at least 50% of the aggregate voting power of such resulting corporation are directly or indirectly owned by another corporation, such other corporation. |
| 7.9. | “Cause” means, with respect to any Executive: |
| (a) | the refusal to perform or habitual neglect in the performance of the Executive’s duties or responsibilities, or of specific directives of the officer or other executive of Exelon or any of its affiliates to whom the Executive reports which are not materially inconsistent with the scope and nature of the Executive’s employment duties and responsibilities; |
| (b) | an Executive’s willful or reckless commission of act(s) or omission(s) which have resulted in or are likely to result in, a material loss to, or |
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| material damage to the reputation of, Exelon or any of its affiliates, or that compromise the safety of any employee or other person; |
| (c) | the Executive’s commission of a felony or any crime involving dishonesty or moral turpitude; |
| (d) | an Executive’s material violation of Exelon’s or any of its affiliate’s Code of Business Conduct (including the corporate policies referenced therein) which would constitute grounds for immediate termination of employment, or of any statutory or common law duty of loyalty to Exelon or any of its affiliates; or |
| (e) | any breach by the Executive of any one or more of the Restrictive Covenants. |
| 7.10. | “Change Date” means each date on which a Change in Control occurs after the Effective Date. |
| 7.11. | “Change in Control” means: |
| (a) | any SEC Person becomes the Beneficial Owner of 20% or more of the then outstanding common stock of Exelon or of Voting Securities representing 20% or more of the combined voting power of all the then outstanding Voting Securities of Exelon (such an SEC Person, a “20% Owner”); provided, however, that for purposes of this subsection (a), the following acquisitions shall not constitute a Change in Control: (1) any acquisition directly from Exelon (excluding any acquisition resulting from the exercise of an exercise, conversion or exchange privilege unless the security being so exercised, converted or exchanged was acquired directly from Exelon), (2) any acquisition by Exelon, (3) any acquisition by an employee benefit plan (or related trust) sponsored or maintained by Exelon or any corporation controlled by Exelon (a “Company Plan”), or (4) any acquisition by any corporation pursuant to a transaction which complies with clauses (i), (ii) and (iii) of subsection (c) of this definition; provided further, that for purposes of clause (2), if any 20% Owner of Exelon other than Exelon or any Company Plan becomes a 20% Owner by reason of an acquisition by Exelon, and such 20% Owner of Exelon shall, after such acquisition by Exelon, become the beneficial owner of any additional outstanding common shares of Exelon or any additional outstanding Voting Securities of Exelon (other than pursuant to any dividend reinvestment plan or arrangement maintained by Exelon) and such beneficial ownership is publicly announced, such additional beneficial ownership shall constitute a Change in Control; or |
| (b) | Individuals who, as of the date hereof, constitute the Board (the “Incumbent Board”) cease for any reason to constitute at least a majority of the Incumbent Board; provided, however, that any individual becoming a director subsequent to the date hereof whose election, or nomination for election by Exelon’s shareholders, was approved by a vote of at least a |
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| majority of the directors then comprising the Incumbent Board shall be considered as though such individual were a member of the Incumbent Board, but excluding, for this purpose, any such individual whose initial assumption of office occurs as a result of an actual or threatened election contest (as such terms are used in Rule 14a-11 promulgated under the Exchange Act) or other actual or threatened solicitation of proxies or consents by or on behalf of a Person other than the Board; or |
| (c) | Consummation of a reorganization, merger or consolidation (“Merger”), or the sale or other disposition of more than 50% of the operating assets of Exelon (determined on a consolidated basis), other than in connection with a sale-leaseback or other arrangement resulting in the continued utilization of such assets (or the operating products of such assets) by Exelon (such reorganization, merger, consolidation, sale or other disposition, a “Corporate Transaction”); excluding, however, a Corporate Transaction pursuant to which: |
| (i) | all or substantially all of the individuals and entities who are the Beneficial Owners, respectively, of the outstanding common stock of Exelon and outstanding Voting Securities of Exelon immediately prior to such Corporate Transaction beneficially own, directly or indirectly, more than 60% of, respectively, the then-outstanding shares of common stock and the combined voting power of the then-outstanding voting securities entitled to vote generally in the election of directors, as the case may be, of the corporation resulting from such Corporate Transaction (including, without limitation, a corporation which, as a result of such transaction, owns Exelon or all or substantially all of the assets of Exelon either directly or through one or more subsidiaries) in substantially the same proportions as their ownership immediately prior to such Corporate Transaction of the outstanding common stock of Company and outstanding Voting Securities of Exelon, as the case may be; |
| (ii) | no SEC Person (other than the corporation resulting from such Corporate Transaction, and any Person which beneficially owned, immediately prior to such corporate Transaction, directly or indirectly, 20% or more of the outstanding common stock of Exelon or the outstanding Voting Securities of Exelon, as the case may be) becomes a 20% Owner, directly or indirectly, of the then-outstanding common stock of the corporation resulting from such Corporate Transaction or the combined voting power of the outstanding voting securities of such corporation; and |
| (iii) | individuals who were members of the Incumbent Board will constitute at least a majority of the members of the board of directors of the corporation resulting from such Corporate Transaction; or |
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| (d) | Approval by Exelon’s shareholders of a plan of complete liquidation or dissolution of Exelon, other than a plan of liquidation or dissolution which results in the acquisition of all or substantially all of the assets of Exelon by an affiliated company. |
Notwithstanding the occurrence of any of the foregoing events, a Change in Control shall not occur with respect to a Participant if, in advance of such event, such Participant agrees in writing that such event shall not constitute a Change in Control.
| 7.12. | “Code” means the Internal Revenue Code of 1986, as amended |
| 7.13. | “ERISA” means the Employee Retirement Income Security Act of 1974, as amended. |
| 7.14. | “Exchange Act” means the Securities Exchange Act of 1934, as amended. |
| 7.15. | “Good Reason” means |
| (a) | for purposes of Section 4 hereof, |
| (i) | a material reduction of an Executive’s salary, incentive compensation opportunity or aggregate benefits unless such reduction is part of a policy, program or arrangement applicable to peer executives of the Company or of the business unit that employs the Executive; or |
| (ii) | with respect to an Executive whose title with respect to a Company is Senior Vice President or above, a material adverse reduction in the Executive’s position or duties that is not applicable to peer executives of the Company or of the business unit that employs the Executive, but excluding any change (A) resulting from a reorganization or realignment of all or a significant portion of the business, operations or senior management of the Company or of the business unit that employs the Executive or (B) that generally places the Executive in substantially the same level of responsibility. Notwithstanding the foregoing, no change in the position or level of officer to whom an Executive reports shall constitute grounds for Good Reason. |
| (b) | for purposes of Section 5 hereof, the occurrence of any one or more of the following actions or omissions that occurs during a Post-Change Period or an Imminent Control Change Period: |
| (i) | a material reduction of an Executive’s salary, incentive compensation opportunity or aggregate benefits unless such reduction is part of a policy, program or arrangement applicable to peer executives (including peer executives of any successor to Exelon); |
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| (ii) | a material adverse reduction in the Executive’s position, duties or responsibilities (excluding a change in the position or level of officer to whom the Executive reports), unless such reduction is part of a policy, program or arrangement applicable to peer executives (including peer executives of any successor to Exelon); |
| (iii) | the failure of any successor to Exelon to assume this Plan; |
| (iv) | a relocation by more than 50 miles of (A) the Executive’s primary workplace, or (B) the principal offices of Exelon or its successor (if such offices are such Executive’s workplace), in each case without the Executive’s consent; provided, however, in both cases of (A) and (B) of this subsection (b)(iv), such new location is farther from the Executive’s residence than the prior location; or |
| (v) | a material breach of this Plan by Exelon or its successor. |
| (c) | Application of “Good Reason” Definition During the Imminent Control Change Period. During the Imminent Control Change Period, “Good Reason” shall not include the events or conditions described in subsection (b)(i), (b)(ii) or (b)(iv) above unless the Imminent Control Change Period culminates in a Change Date. |
| (d) | Limitations on Good Reason. Notwithstanding the foregoing provisions of this Section, no act or omission shall constitute a material breach of this Plan by Exelon, nor grounds for “Good Reason”: |
| (i) | unless the Executive gives the Company a Notice of Termination at least 30 days prior to the Executive’s Termination Date, and the Company fails to cure such act or omission within the 30-day period; |
| (ii) | if the Executive first acquired knowledge of such act or omission more than 180 days before such Participant gives the Company such Notice or Termination; or |
| (iii) | if the Executive has consented in writing to such act or omission. |
| 7.16. | “Imminent Control Change” means, as of any date on or after the Effective Date and prior to the Change Date, the occurrence of any one or more of the following: |
| (a) | Exelon enters into an agreement the consummation of which would constitute a Change in Control; |
| (b) | Any SEC Person commences a “tender offer” (as such term is used in Section 14(d) of the Exchange Act) or exchange offer, which, if consummated, would result in a Change in Control; or |
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| (c) | Any SEC Person files with the SEC a preliminary or definitive proxy solicitation or election contest to elect or remove one or more members of the Board, which, if consummated or effected, would result in a Change in Control; |
provided, however, that an Imminent Control Change will lapse and cease to qualify as an Imminent Control Change:
| (i) | With respect to an Imminent Control Change described in clause (a) of this definition, the date such agreement is terminated, cancelled or expires without a Change Date occurring; |
| (ii) | With respect to an Imminent Control Change described in clause (b) of this definition, the date such tender offer or exchange offer is withdrawn or terminates without a Change Date occurring; |
| (iii) | With respect to an Imminent Control Change described in clause (c) of this definition, (1) the date the validity of such proxy solicitation or election contest expires under relevant state corporate law, or (2) the date such proxy solicitation or election contest culminates in a shareholder vote, in either case without a Change Date occurring; or |
| (iv) | The date a majority of the members of the Incumbent Board make a good faith determination that any event or condition described in clause (a), (b), or (c) of this definition no longer constitutes an Imminent Control Change, provided that such determination may not be made prior to the first anniversary of the occurrence of such event. |
| 7.17. | “Imminent Control Change Period” means the period commencing on the date of an Imminent Control Change, and ending on the first to occur thereafter of |
| (a) | a Change Date, provided |
| (i) | such date occurs no later than the first anniversary of the Termination Date, and |
| (ii) | either the Imminent Control Change has not lapsed, or the Imminent Control Change in effect upon such Change Date is the last Imminent Control Change in a series of Imminent Control Changes unbroken by any period of time between the lapse of an Imminent Control Change and the occurrence of a new Imminent Control Change; |
| (b) | the date an Imminent Control Changes lapses without the prior or concurrent occurrence of a new Imminent Control Change; or |
| (c) | the first anniversary of the Termination Date. |
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| 7.18. | “Incentive Plan” means the Exelon Corporation Annual Incentive Award Plan, or such other annual cash incentive award arrangement of the Company in which the Executive is a participant in lieu of such program. |
| 7.19. | “including” means including without limitation. |
| 7.20. | “Incumbent Board” - see definition of Change in Control. |
| 7.21. | “LTIP” means the Exelon Corporation Long-Term Incentive Plan, as amended from time to time, or any successor thereto, and including any Stock Options or Restricted Stock granted thereunder to replace stock options or restricted stock initially granted under the Unicom Corporation Long-Term Incentive Plan. |
| 7.22. | “LTIP Performance Period” means the one-year performance period applicable to an LTIP award, as designated in accordance with the LTIP. |
| 7.23. | “LTIP Target Level” means, in respect of any grant of Performance Shares under the Exelon Performance Share Program under the LTIP, the number of Performance Shares which a Participant would have been awarded (prior to the Termination Date) for the LTIP Performance Period corresponding to such grant if the business and personal performance goals related to such grant were achieved at the 100% (target) level as of the end of the LTIP Performance Period. |
| 7.24. | “Merger” - see definition of Change in Control. |
| 7.25. | “Notice of Termination” means a written notice given by an Executive in accordance with Sections 7.15(d)(i) and 13.9 which sets forth in reasonable detail the specific facts and circumstances claimed to provide a basis for a Termination of Employment for Good Reason. |
| 7.26. | “Performance Shares” - see Section 5.1(c). |
| 7.27. | “Person” means any individual, sole proprietorship, partnership, joint venture, limited liability company, trust, unincorporated organization, association, corporation, institution, public benefit corporation, entity or government instrumentality, division, agency, body or department. |
| 7.28. | “Plan Administrator” - See Section 9. |
| 7.29. | “Post-Change Period” means the period commencing on a Change Date and ending on the earlier of (a) the Termination Date or (b) the second anniversary of such Change Date; provided that no duplicate benefits shall be paid with respect to simultaneous or overlapping Post-Change Periods. |
| 7.30. | “Restricted Stock” - see Section 5.1(d). |
| 7.31. | “Salary Continuation Period” means the applicable period designated in Section 4.1 during which severance is payable. |
| 7.32. | “SEC” means the United States Securities and Exchange Commission. |
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| 7.33. | “SEC Person” means any person (as such term is used in Rule 13d-5 of the SEC under the Exchange Act) or group (as such term is defined in Sections 3(a)(9) and 13(d)(3) of the Exchange Act), other than (a) Exelon or any Person that directly or indirectly controls, is controlled by, or is under common control with, Exelon (an “Affiliate”). For purposes of this definition the term “control” with respect to any Person means the power to direct or cause the direction of management or policies of such Person, directly or indirectly, whether through the ownership of Voting Securities, by contract or otherwise, or (b) any employee benefit plan (or any related trust) of Exelon or any of its Affiliates. |
| 7.34. | “Section” means, unless the context otherwise requires, a section of this Plan. |
| 7.35. | “Senior Executive Management” means (a) an Executive whose title with respect to Exelon is Senior Vice President or above, or (b) an Executive whose title with respect to a Company other than Exelon is Senior Vice President or above and who either held such a title or was a member of Exelon’s management committee as of the Effective Date. |
| 7.36. | “SERP” means the PECO Energy Company Supplemental Retirement Plan or the Exelon Corporation Supplemental Executive Retirement Plan, whichever is applicable to a Participant, or any successor to either or both. |
| 7.37. | “Severance Incentive” means the Target Incentive for the performance period in which the Termination Date occurs; provided, however, that for purposes of Section 5, “Severance Incentive” shall mean the greater of (a) the Target Incentive for the performance period in which the Termination Date occurs, or (b) the average of the actual annual incentives paid (or payable, to the extent not previously paid) to a Participant under the Incentive Plan for each of the two calendar years preceding the calendar year in which the Termination Date occurs. |
| 7.38. | “Severance Period” means the period beginning on a Participant’s Termination Date, provided such Participant’s Termination of Employment entitles such Participant to benefits under Section 5.1 or 5.2, and ending on the second anniversary thereof. |
| 7.39. | “Stock Options” - see Section 5.1(b). |
| 7.40. | “Target Incentive” as of a certain date means an amount equal to the product of Base Salary determined as of such date multiplied by the percentage of such Base Salary to which a Participant would have been entitled immediately prior to such date under the Exelon Corporation Annual Incentive Award Plan for the applicable performance period if the performance goals established pursuant to such plan were achieved at the 100% (target) level as of the end of the applicable performance period; provided, however, that any reduction in a Participant’s Base Salary or annual incentive that would qualify as Good Reason shall be disregarded for purposes of this definition. |
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| 7.41. | “Taxes” means the incremental federal, state, local and foreign income, employment, excise and other taxes payable by a Participant with respect to any applicable item of income. |
| 7.42. | “Termination Date” means the effective date of an eligible Executive’s termination of employment with the Company for any or no reason, which shall be the last day on which such Executive is employed by the Company; provided, however, that if the Executive terminates his or her employment for Good Reason, the Termination Date shall not be earlier than the thirtieth day following the Company’s receipt of such Executive’s Notice of Termination, unless the Exelon consents in writing to an earlier Termination Date. |
| 7.43. | “Termination of Employment” means: |
| (a) | a termination of an eligible Executive’s employment by the Company for reasons other than for Cause; or |
| (b) | a resignation by an eligible Executive for Good Reason. |
The following shall not constitute a Termination of Employment for purposes of the Plan: (i) a termination of employment for Cause, (ii) an Executive’s resignation for any reason other than for Good Reason, (iii) the cessation of an Executive’s employment with the Company or any Affiliate due to death or disability (as determined by the Plan Administrator in good faith), or (iv) the cessation of an Executive’s employment with the Company or any subsidiary thereof as the result of the sale, spin-off or other divestiture of a plant, division, business unit or subsidiary or a merger or other business combination followed by employment or reemployment with the purchaser or successor in interest to the Executive’s employer with regard to such plant, division, business unit or subsidiary, or an offer of employment by such purchaser or successor in interest on terms and conditions no less favorable in the aggregate (as determined by the Plan Administrator) than the terms and conditions of the Executive’s employment with the Company or its subsidiary immediately prior to such transaction.
| 7.44. | “20% Owner” - see paragraph (a) of the definition of “Change in Control.” |
| 7.45. | “Voting Securities” means with respect to a corporation, securities of such corporation that are entitled to vote generally in the election of directors of such corporation. |
| 8. | FUNDING |
The Plan is an unfunded employee welfare benefit plan maintained for the purpose of providing severance benefits to a select group of management or highly compensated employees. Nothing in the Plan shall be interpreted as requiring the Company to set aside any of its assets for the purpose of funding its obligations under the Plan. No person entitled to benefits under the Plan shall have any right, title or claim in or to any specific assets of the Company, but shall have the right only as a general creditor to receive benefits from the Company on the terms and conditions provided in the Plan.
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| 9. | ADMINISTRATION OF THE PLAN |
The Plan shall be administered on a day-to-day basis by the Vice President, Corporate Compensation of Exelon (the “Plan Administrator”). The Plan Administrator has the sole and absolute power and authority to interpret and apply the provisions of this Plan to a particular circumstance, make all factual and legal determinations, construe uncertain or disputed terms and make eligibility and benefit determinations in such manner and to such extent as the Plan Administrator, in his or her sole discretion may determine. Benefits under the Plan will be paid only if the Plan Administrator, in his or her discretion, determines that an individual is entitled to them; provided, however, that any dispute after the claims procedure under Section 10 has been exhausted regarding whether an Executive’s termination of employment for purposes of Section 5 is based on either Good Reason or Cause may, at the election of the Executive, be submitted to binding arbitration pursuant to Section 11.
The Plan Administrator may promulgate any rules and regulations it deems necessary to carry out the purposes of the Plan or to interpret the terms and conditions of the Plan; provided, however, that no rule, regulation or interpretation shall be contrary to the provisions of the Plan. The rules, regulations and interpretations made by the Plan Administrator shall, where appropriate, be applied on a consistent basis with respect to similarly situated Executives, and shall be final and binding on any Executive or former Executive and any successor in interest.
The Plan Administrator may delegate any administrative duties, including, without limitation, duties with respect to the processing, review, investigation, approval and payment of severance pay and provision of severance benefits, to designated individuals or committees.
| 10. | CLAIMS PROCEDURE |
The Plan Administrator shall determine the status of an individual as an Executive and the eligibility and rights of any Executive or former Executive as a Participant to any severance pay or benefits hereunder. Any Executive or former Executive who believes that he or she is entitled to receive severance pay or benefits under the Plan, including severance pay or benefits other than those initially determined by the Plan Administrator, may file a claim in writing with the Plan Administrator. Within 90 days after the receipt of the claim the Plan Administrator shall either allow or deny the claim in writing, unless special circumstances require an extension of time for processing, in which case a decision shall be rendered as soon as practicable, but not later than 180 days after receipt of a request for review.
A claimant whose claim is denied (or his or her duly authorized representative) may, within 60 days after receipt of the denial of his or her claim, request a review upon written application to Exelon’s Chief Human Resources Officer or other officer designated by Exelon and specified in the claim denial; review (without charge) relevant documents; and submit written comments, documents, records and other information relating to the claim.
The Chief Human Resources Officer or other designated officer shall notify the claimant of his or her decision on review within 60 days after receipt of a request for review unless special circumstances require an extension of time for processing, in which case a decision shall be rendered as soon as possible, but not later than 120 days after receipt of a request for review.
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Notice of the decision on review shall be in writing. The officer’s decision on review shall be final and binding on any claimant or any successor in interest.
In reviewing a claim or an appeal of a claim denial, the Plan Administrator and the Chief Human Resources Officer or other designated by Exelon shall have all of the powers and authority granted to the Plan Administrator pursuant to Section 9.
| 11. | ARBITRATION |
Any dispute, controversy or claim between the parties hereto concerning whether an Executive’s termination of employment for purposes of Section 5 is based on either Good Reason or Cause may, after the claims procedure under Section 10 has been exhausted and at the election of the Executive, be settled by binding arbitration in Chicago, Illinois, before an impartial arbitrator pursuant to the rules and regulations of the American Arbitration Association (“AAA”) pertaining to the arbitration of employee benefit plan disputes. The costs and fees of the arbitrator shall be borne equally by the parties, regardless of the result of the arbitration. No arbitration shall be commenced after the date when institution of legal or equitable proceedings based upon such subject matter would be barred by the applicable statutes of limitations. Notwithstanding anything to the contrary contained in this Section or elsewhere in this Plan, any party may seek relief in the form of specific performance, injunctive or other equitable relief in order to enforce the decision of the arbitrator, and the Company may seek injunctive relief to enforce the above-referenced statutes of limitations.
| 12. | AMENDMENT OR TERMINATION OF PLAN |
Exelon’s Chief Human Resources Officer or another designated officer of the Company may amend, modify or terminate the Plan at any time by written instrument; provided, however, that no amendment, modification or termination shall deprive any Participant of any payment or benefit that the Plan Administrator previously has determined is payable under the Plan. Notwithstanding the foregoing, no amendment or termination that materially adversely affects any Participant’s benefits under Section 5 shall become effective as to such Participant during: (a) the 24-month period following a Change Date or (b) during an Imminent Control Change Period (unless such Participant consents to such termination or amendment). Any purported Plan termination or amendment in violation of this Section 12 shall be void and of no effect.
| 13. | MISCELLANEOUS |
| 13.1. | Limitation on Rights. Participation in the Plan is limited to the individuals described in Sections 2 and 3, and the benefits under the Plan shall not be payable with respect to any voluntary or involuntary termination of employment that is not a Termination of Employment. |
| 13.2. | No Set-off by Company. This Section shall apply solely with respect to a Termination of Employment during a Post-Change Period or an Imminent Control Change Period that culminates in a Change Date. Except as provided in Section 6, a Participant’s right to receive when due the payments and other benefits provided for under Section 5 of this Plan is absolute, unconditional and subject to no setoff, counterclaim or legal or equitable defense. |
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| 13.3. | No Mitigation. A Participant shall not have any duty to mitigate the amounts payable by the Company under this Plan by seeking new employment following termination. Except as specifically otherwise provided in this Plan, all amounts payable pursuant to this Plan shall be paid without reduction regardless of any amounts of salary, compensation or other amounts which may be paid or payable to the Executive as the result of the Executive’s employment by another, unaffiliated employer. |
| 13.4. | Headings. Headings of sections in this document are for convenience only, and do not constitute any part of the Plan. |
| 13.5. | Severability. If any one or more Sections, subsections or other portions of this Plan are declared by any court or governmental authority to be unlawful or invalid, such unlawfulness or invalidity shall not serve to invalidate any Section, subsection or other portion not so declared to be unlawful or invalid. Any Section, subsection or other portion so declared to be unlawful or invalid shall be construed so as to effectuate the terms of such Section, subsection or other portion to the fullest extent possible while remaining lawful and valid. Notwithstanding the foregoing, in the event a determination is made that the Restrictive Covenants are invalid or unenforceable in whole or in part, then the Severance Agreement with respect to the Participant subject to such determination shall be void and the Company shall have no obligation to provide benefits under this Plan to such Participant. |
| 13.6. | Governing Law. The Plan shall be construed and enforced in accordance with ERISA. |
| 13.7. | No Right to Continued Employment. Nothing in this Plan shall guarantee the right of a Participant to continue in employment, and the Company retains the right to terminate a Participant’s employment at any time for any reason or for no reason. |
| 13.8. | Successors and Assigns. This Plan shall be binding upon and inure to the benefit of Exelon Corporation and its successors and assigns and shall be binding upon and inure to the benefit of a Participant and his or her legal representatives, heirs and legatees. |
No rights, obligations or liabilities of a Participant hereunder shall be assignable without the prior written consent of Exelon Corporation. In the event of the death of a Participant prior to receipt of severance pay or benefits to which he or she is entitled hereunder (and, with respect to benefits under Section 4 or Section 5, after he or she has signed the Waiver and Release), the severance pay described in Sections 4.1, 5.1, or 5.2, as applicable, shall be paid to his or her estate, and the Participant’s dependents who are covered under any health care plans maintained by the Company shall be entitled to continued rights under Section 4.5 or Section 5.1(e) or Section 5.2(f), as applicable; provided that the estate or other successor of the Participant has not revoked such Waiver and Release.
| 13.9. | Notices. All notices and other communications under this Plan shall be in writing and delivered by hand, by nationally-recognized delivery service that promises |
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| overnight delivery, or by first-class registered or certified mail, return receipt requested, postage prepaid, addressed as follows: |
If to a Participant, to such Participant at his most recent home address on file with the Company.
If to the Company: to the Plan Administrator.
or to such other address as either party shall have furnished to the other in writing. Notice and communications shall be effective when actually received by the addressee.
| 13.10. | Number and Gender. Wherever appropriate, the singular shall include the plural, the plural shall include the singular, and the masculine shall include the feminine. |
| 13.11. | Tax Withholding. The Company may withhold from any amounts payable under this Plan or otherwise payable to a Participant or beneficiary any Taxes the Company determines to be appropriate under applicable law and may report all such amounts payable to such authority in accordance with any applicable law or regulation. In addition, the Company may adjust the timing of any payment under this Plan consistent with the tax treatment of such payment. |
EXHIBIT I
EXELON CORPORATION
RESTRICTIVE COVENANTS
This agreement and covenant (the “Agreement”), made as of the day of , , is made by and among Exelon Corporation, incorporated under the laws of the Commonwealth of Pennsylvania (together with successors thereto, “Exelon”), , a corporation (together with successors thereto, the “Employer”), and (“you”).
WHEREAS, Exelon maintains the Exelon Corporation Senior Management Severance Plan (the “Severance Plan”), effective as of July 1, 2003, and as thereafter amended, modified and supplemented;
WHEREAS, you may be eligible to become a Participant (as defined in the Severance Plan) in the Severance Plan as an employee of the Employer;
WHEREAS, in order to be a Participant in and be eligible for benefits under the Severance Plan, you must execute this covenant and return it to the Company within 90 days after the date you became an Executive, within the meaning of the Severance Plan, or were provided this document;
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NOW THEREFORE, in consideration for becoming eligible to participate in the Severance Plan and your commencement of employment with the Employer, you covenant the following:
Confidential Information.
| (a) | Obligation to Keep Confidential Information Confidential. You acknowledge that in the course of performing services for Exelon and its affiliates (together, the “Company”), you may create (alone or with others), learn of, have access to and receive Confidential Information. Confidential Information (as defined below) shall not include: (i) information that is or becomes generally known through no fault of yours; (ii) information received from a third party outside of the Company that was disclosed without a breach of any confidentiality obligation; or (iii) information approved for release by written authorization of the Company. You recognize that all such Confidential Information is the sole and exclusive property of the Company or of third parties which the Company is obligated to keep confidential, that it is the Company’s policy to keep all such Confidential Information confidential, and that disclosure of Confidential Information would cause damage to the Company. You agree that, except as required by your duties of employment with the Company or any of its affiliates, and except in connection with enforcing your rights under the Severance Plan or if compelled by a court or governmental agency, in each case provided that prior written notice is given to Exelon, you will not, without the written consent of Exelon, willfully disseminate or otherwise disclose, directly or indirectly, any Confidential Information obtained during your employment with the Company, and will take all necessary precautions to prevent disclosure, to any unauthorized individual or entity inside or outside the Company, and will not use the Confidential Information or permit its use for your personal benefit or any other person or entity other than the Company. These obligations shall continue during and after the termination of your employment (whether or not after a Change in Control or Imminent Control Change, as such terms are defined in the Severance Plan). |
| (b) | Definition of Confidential Information. “Confidential Information” shall mean any information, ideas, processes, methods, designs, devices, inventions, data, techniques, models and other information developed or used by the Company and not generally known in the relevant trade or industry relating to the Company’s products, services, businesses, operations, employees, customers or suppliers, whether in tangible or intangible form, which gives the Company a competitive advantage in the harnessing, production, transmission, distribution, marketing or sale of energy or the transmission or distribution thereof through wire or cable or similar medium or in the energy services industry and other businesses in which the Company is engaged, or of third parties which the Company is obligated to keep confidential, or which was learned, discovered, developed, conceived, originated or prepared during or as a result of your performance of any services on behalf of the Company and which falls within any of the following general categories: |
| (i) | information relating to trade secrets of the Company or any customer or supplier of the Company; |
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| (ii) | information relating to existing or contemplated products, services, technology, designs, processes, formulae, algorithms, research or product developments of the Company or any customer or supplier of the Company; |
| (iii) | information relating to business plans or strategies, sales or marketing methods, methods of doing business, customer lists, customer usages and/or requirements, supplier information of the Company or any customer or supplier of the Company; |
| (iv) | information subject to protection under the Uniform Trade Secrets Act, as adopted by the Commonwealth of Pennsylvania, or to any comparable protection afforded by applicable law; or |
| (v) | any other confidential information which either the Company or any customer or supplier of the Company may reasonably have the right to protect by patent, copyright or by keeping it secret and confidential. |
Non-Competition.
During the period beginning on the date of execution of this Agreement and ending on the second anniversary of the Termination Date (as such term is defined in the Severance Plan), whether or not after a Change in Control or Imminent Control Change, you hereby agree that without the written consent of Exelon you shall not at any time, directly or indirectly, in any capacity:
| (c) | engage or participate in, become employed by, serve as a director of, or render advisory or consulting or other services in connection with, any Competitive Business (as defined below); provided, however, that after the Termination Date this Section 2 shall not preclude you from being an employee of, or consultant to, any business unit of a Competitive Business if (i) such business unit does not qualify as a Competitive Business in its own right and (ii) you do not have any direct or indirect involvement in, or responsibility for, any operations of such Competitive Business that cause it to qualify as a Competitive Business. |
| (d) | make or retain any financial investment, whether in the form of equity or debt, or own any interest, in any Competitive Business. Nothing in this subsection shall, however, restrict you from making an investment in any Competitive Business if such investment does not (i) represent more than 1% of the aggregate market value of the outstanding capital stock or debt (as applicable) of such Competitive Business, (ii) give you any right or ability, directly or indirectly, to control or influence the policy decisions or management of such Competitive Business, and (iii) create a conflict of |
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| interest between your employment duties and your interest in such investment. |
| (e) | Definition of Competitive Business. “Competitive Business” means, as of any date, any utility business and any individual or entity (and any branch, office, or operation thereof) which engages in, or proposes to engage in (with your assistance) (i) the harnessing, production, transmission, distribution, marketing or sale of energy or the transmission or distribution thereof through wire or cable or similar medium, (ii) any other business engaged in by the Company prior to your Termination Date which represents for any calendar year or is projected by the Company (as reflected in a business plan adopted by any Company before your Termination Date) to yield during any year during the first three-fiscal year period commencing on or after your Termination Date, more than 5% of the gross revenue of any individual Company, and, in either case, which is located (x) anywhere in the United States, or (y) anywhere outside of the United States where Company is then engaged in, or proposes as of the Termination Date to engage in, to your knowledge, any of such activities. |
Non-Solicitation.
During the period beginning on the date of execution of this Agreement and ending on the second anniversary of any Termination Date, whether or not after a Change in Control or Imminent Control Change, you shall not, directly or indirectly:
| (a) | other than in connection with the good-faith performance of your duties as an officer of the Company cause or attempt to cause any employee or agent of the Company to terminate his or her relationship with the Company; |
| (b) | employ, engage as a consultant or adviser, or solicit the employment or engagement as a consultant or adviser, of any employee or agent of the Company (other than by the Company), or cause or attempt to cause any Person to do any of the foregoing; |
| (c) | establish (or take preliminary steps to establish) a business with, or cause or attempt to cause others to establish (or take preliminary steps to establish) a business with, any employee or agent of the Company, if such business is or will be a Competitive Business; or |
| (d) | interfere with the relationship of the Company with, or endeavor to entice away from the Company, any Person who or which at any time during the period commencing one year prior to the Termination Date was or is, to your knowledge, a material customer or material supplier of, or maintained a material business relationship with, the Company. |
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Intellectual Property.
During the period of your employment with the Company, and thereafter upon the Company’s request, whether or not after a Change in Control or Imminent Control Change, you shall disclose immediately to the Company all ideas, inventions and business plans that he makes, conceives, discovers or develops alone or with others during the course of your employment with the Company or during the one year period following your Termination Date, including any inventions, modifications, discoveries, developments, improvements, computer programs, processes, products or procedures (whether or not protectable upon application by copyright, patent, trademark, trade secret or other proprietary rights) (“Work Product”) that: (i) relate to the business of the Company or any customer or supplier to the Company or any of the products or services being developed, manufactured, sold or otherwise provided by the Company or that may be used in relation therewith; or (ii) result from tasks assigned to you by the Company; or (iii) result from the use of the premises or personal property (whether tangible or intangible) owned, leased or contracted for by the Company. You agree that any Work Product shall be the property of the Company and, if subject to copyright, shall be considered a “work made for hire” within the meaning of the Copyright Act of 1976, as amended (the “Act”). If and to the extent that any such Work Product is not a “work made for hire” within the meaning of the Act, you hereby assign to the Company all right, title and interest in and to the Work Product, and all copies thereof, and the copyright, patent, trademark, trade secret and all proprietary rights in the Work Product, without further consideration, free from any claim, lien for balance due or rights of retention thereto on your part.
| (a) | The Company hereby notifies you that the preceding paragraph does not apply to any inventions for which no equipment, supplies, facility, or trade secret information of the Company was used and which was developed entirely on your own time, unless: (i) the invention relates (a) to the Company’s business, or (b) to the Company’s actual or demonstrably anticipated research or development, or (ii) the invention results from any work performed by you for the Company. |
| (b) | You agree that upon disclosure of Work Product to the Company, you will, during your employment and at any time thereafter, at the request and cost of the Company, execute all such documents and perform all such acts as the Company or its duly authorized agents may reasonably require: (i) to apply for, obtain and vest in the name of the Company alone (unless the Company otherwise directs) letters patent, copyrights or other analogous protection in any country throughout the world, and when so obtained or vested to renew and restore the same; and (ii) to prosecute or defend any opposition proceedings in respect of such applications and any opposition proceedings or petitions or applications for revocation of such letters patent, copyright or other analogous protection, or otherwise in respect of the Work Product. |
| (c) | In the event that the Company is unable, after reasonable effort, to secure your execution as provided in subsection (b) above, whether because of your physical or mental incapacity or for any other reason whatsoever, you hereby irrevocably designate and appoint the Company and its duly authorized officers and agents as your agent and attorney-in-fact, to act for and on your behalf to execute and file any such application or applications |
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| and to do all other lawfully permitted acts to further the prosecution, issuance and protection of letters patent, copyright and other intellectual property protection with the same legal force and effect as if personally executed by you. |
Reasonableness of Restrictive Covenants.
| (a) | You acknowledge that the covenants contained in Sections 2, 3, and 4 are reasonable in the scope of the activities restricted, the geographic area covered by the restrictions, and the duration of the restrictions, and that such covenants are reasonably necessary to protect the Company’s legitimate interests in its Confidential Information and in its relationships with its employees, customers and suppliers. |
| (b) | The Company and you have all consulted with their respective legal counsel and have been advised concerning the reasonableness and propriety of such covenants. You acknowledge that your observance of the covenants contained in Sections 2, 3, and 4 will not deprive you of the ability to earn a livelihood or to support your dependents. |
| (c) | All of the provisions of this Restrictive Covenant shall survive any termination of employment without regard to (i) the reasons for such termination or (ii) the expiration of any participation in the Severance Plan. |
| (d) | The Company shall have no further obligation to pay or provide severance or benefits under the Plan if you breach any covenant in this Restrictive Covenant, and the Company may require you to repay any benefits previously provided under the Plan. |
Counterparts.
This Agreement may be executed in several counterparts, each of which shall be deemed to be an original, but all of which together will constitute one and the same instrument.
Headings.
The Headings of this Agreement are not part of the provisions hereof and shall not have any force or effect.
Applicable Law.
The provisions of this Agreement shall be interpreted and construed in accordance with the Employee Retirement Income Security Act of 1974, as amended, and to the extent federal law is not applicable, the laws of the State of Illinois, without regard to its choice of law principles.
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IN WITNESS WHEREOF, the parties have executed this Agreement as of the dates specified below.
| EXECUTIVE | ||
| EXELON CORPORATION | ||
| By: | ||
| Title: |
||
| (Employer, if different from Exelon) | ||
| By: | ||
| Title: |
||
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Exhibit 10.49
EXELON CORPORATION
ANNUAL INCENTIVE PLAN
FOR SENIOR EXECUTIVES
(Effective January 1, 2004)
EXELON CORPORATION
ANNUAL INCENTIVE PLAN
FOR SENIOR EXECUTIVES
(Effective January 1, 2004)
| I. | Establishment. The Exelon Corporation Annual Incentive Plan for Senior Executives (the “Plan”) was established by Exelon Corporation (the “Company”) effective January 1, 2004, subject to the approval by an affirmative vote of a majority of the shares of common stock of the Company present in person or represented by proxy at the 2004 annual meeting of stockholders, and shall terminate as of December 31, 2008, unless terminated earlier by the Board of Directors of the Company |
| II. | Purpose. The purpose of the Plan is to reward achievement of key annual goals, to enhance the Company’s ability to attract, motivate, reward and retain certain officers and key executive employees, to strengthen their commitment to the success of the Company, to promote the near-term objectives of the Company, and to ensure annual incentive compensation payable to the Company’s Section 162(m) Executives can be eligible to be tax-deductible by the Company. |
| III. | Definitions. |
| A. | Award means the annual incentive award payable to a Participant hereunder with respect to a Plan Year. |
| B. | Committee means the members of the Compensation Committee of the Board of Directors of the Company who qualify as “outside directors” within the meaning of Section 162(m) of the Internal Revenue Code; provided that if there are not at least two such members, then the Committee shall be a committee of at least two “outside directors” as so defined, appointed by the Board of Directors of the Company and which satisfies any other applicable requirements of the principal stock exchange on which the common stock of the Company is then traded to constitute a compensation committee. |
| C. | Company means Exelon Corporation and any successor thereto. |
| D. | Disability means a physical or mental condition on account of which benefits under the long-term disability plan of the Company or Subsidiary, whichever covers the Participant, have commenced. |
| E. | Eligible Executive means an Employee who is a member of the Company’s strategy and policy committee (or any successor committee) or whose level is senior vice president (or any equivalent successor level) or higher. |
| F. | Employee means an employee of the Company or a Subsidiary employed in an executive or officer level position. |
| G. | Incentive Pool means an amount, expressed either as a dollar value or pursuant to an objective formula or performance measure, that is designated by the Committee as available to fund Awards for a Plan Year pursuant to Section VI.A. |
| H. | Internal Revenue Code means the Internal Revenue Code of 1986, as amended, and all applicable regulations and rulings thereunder as in effect from time to time. |
| I. | Participant means an Eligible Executive who has been selected by the Committee to participate in the Plan for a particular Plan Year. Unless the context requires otherwise, the term “Participant” shall include “Part-Year Participants” as defined in Section IV.B. |
| J. | Performance Goals means the objective performance goal(s) designated by the Committee pursuant to Section VI.B. with respect to an Incentive Pool. |
| K. | Plan means this Exelon Corporation Annual Incentive Plan for Senior Executives as set forth herein and as amended from time to time. |
| L. | Plan Year means the Company’s fiscal year which, as of the effective date of the Plan, is the calendar year. |
| M. | Pro-ration Fraction means with respect to a Plan Year the number of days a Part-Year Participant was an Eligible Executive during the Plan Year, divided by 365 (or in the case of a Plan Year of more or less than 365 days, the number of days in the Plan Year). |
| N. | Required Period means at a time (1) when the outcome of the performance goals established pursuant to Article VI is substantially uncertain and (2) either (a) before the commencement of the Plan Year or, (b) (i) in the case of a 12-month Plan Year, not later than 90 days after the commencement of such Plan Year, (ii) in the case of a Plan Year shorter than 12 months, after no more than 25% of such Plan Year has elapsed, and (iii) in the case of a Participant who became an Eligible Executive after the first day of the Plan Year, after no more than 25% of the remainder of such Plan Year has elapsed after the Participant became an Eligible Executive. Any action required to be taken within the Required Period may be taken at a later date to the extent permissible under Section 162(m) of the Internal Revenue Code. |
| O. | Retirement means a Participant’s termination of employment other than for “cause” (as defined in the Exelon Corporation Senior Management Severance Plan as in effect from time to time, or such other employment or severance plan or agreement governing the terms of the Participant’s termination of employment) after attaining age 50 with 10 years of service under the Company’s applicable defined benefit pension plan (including for this purpose any deemed pension service granted to the Participant under an employment or change in control agreement to the extent any |
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| applicable vesting or other conditions to such deemed service have been satisfied upon such termination of employment). |
| P. | Section 162(m) Executive means an Eligible Executive who is a “covered employee” as defined in Section 162(m) of the Internal Revenue Code. |
| Q. | Subsidiary means a business which is affiliated through common ownership with the Company, and which is designated by the Committee as an employer whose employees may be eligible to participate in the Plan, but only with respect to such period of affiliation. |
| IV. | Participation. |
| A. | Generally. Within the Required Period at the beginning of each Plan Year, the Committee shall designate the Participants (if any) for such Plan Year. Any individual who is an Eligible Executive as of the first day of the Plan Year may be designated as a Participant. |
| B. | Individuals Who Become Eligible Executives During a Plan Year. An individual who becomes an Eligible Executive after the first day of a Plan Year may be designated as a Participant for the remainder of the Plan Year (a “Part-Year Participant”) at any time within the Required Period after becoming an Eligible Executive. |
| V. | Administration. |
| A. | The Committee shall administer the Plan. |
| B. | The Committee shall have full and complete authority to establish any rules and regulations it deems necessary or appropriate relating to the Plan, to interpret and construe the Plan and those rules and regulations, to correct defects and supply omissions, to determine the who shall become Participants for any Plan Year, to determine the performance goals and other terms and conditions applicable to each Award (including the extent to which any payment shall be made under an Award in the event of a change in control of the Company), to certify the achievement of performance goals and approve all Awards (subject to Section VII.B.), to determine whether and to what extent Awards may be paid on a deferred basis, to make all factual and other determinations arising under the Plan, and to take all other actions the Committee deems necessary or appropriate for the proper administration of the Plan. |
| C. | Notwithstanding the foregoing, the Committee shall not be authorized to increase the amount of the Award payable to a Section 162(m) Executive that would otherwise be payable under the terms of the Plan or an Award. |
| D. | The Committee may from time to time delegate the performance of its ministerial duties under the Plan to the Company’s Vice President of Corporate Compensation or |
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| such other person or persons as the Committee may select; except that the power or authority of the Committee shall not be delegated to the extent such delegation would cause any Award payable to a Section 162(m) Executive to fail to be tax-deductible under Section 162(m) of the Code, including but not limited to the responsibility to certify the extent to which performance goals have been attained. |
| E. | Subject to Section VII.B., the Committee’s administration of the Plan, including all such rules and regulations, interpretations and construals, selections, factual and other determinations, approvals, decisions, delegations, amendments, terminations and other actions, as the Committee shall see fit shall be final and binding on the Company and its Subsidiaries, stockholders and all employees, including Participants and their beneficiaries. Any decision made by the Committee in good faith in connection with its administration of or responsibilities under the Plan shall be conclusive on all persons. |
| F. | The Committee may, subject to the limitations described in paragraph D. above, engage and rely on the advice of such advisors, consultants or data as it considers necessary or desirable in selecting eligible key employees, in designating applicable Performance Goals, and in determining attainment of performance goals and the amount of incentive awards under the Plan, and in performing its other duties under the Plan. |
| G. | The Company and/or its participating Subsidiaries shall pay the costs of Plan administration. |
| VI. | Performance Goals. |
| A. | Establishment of Incentive Pool(s). Within the Required Period for each Plan Year, the Committee shall establish in writing one or more Incentive Pools from which Awards (if any) will be paid for such Plan Year, and shall designate the Participants eligible to share in each such Incentive Pool (subject to the Committee’s right to add new Participants during the Plan Year in accordance with Section IV.B. above). The amount available under each Incentive Pool (or portion thereof) shall be based on the attainment of one or more specified Performance Goals, weighted in such manner as the Committee determines, and may, but need not be based on or contingent upon the level of achievement of threshold or target or maximum performance (as set by the Committee) of the stated Performance Goals. As soon as reasonably practicable after the end of each Plan Year the Committee shall certify in writing the level of attainment of each Performance Goal applicable to each Incentive Pool (or portion thereof) and the amount, if any, of each such Incentive Pool. The Committee shall certify the amount of each Participant’s maximum Award for each Plan Year within a reasonable time after the end of such year. If the Company or a Subsidiary or other business unit fails to meet a threshold or other minimum applicable Performance Goal, if any, established for it for a Plan Year, the applicable Incentive Pool shall not be funded to that extent and no related payment shall be made with respect to Awards to Participants employed by the Company or such Subsidiary or business unit for such |
4
| year, as the case may be and, to the extent other (e.g., target or maximum) performance goals are established with respect to an Incentive Pool, the funding of such Incentive Pool shall not exceed the maximum amount that could be paid based on the extent to which the Committee determines that such goals in excess of threshold or other minimum goals are actually achieved. |
| B. | Performance Goals. The Performance Goals for each Plan Year may be based upon the performance of the Company or any Subsidiary, division, business unit or individual for the Plan Year, using one or more of the following measures as selected by the Committee: (1) cumulative shareholder value added, (2) customer satisfaction, (3) revenue, (4) primary or fully-diluted earnings per share, (5) net income, (6) total shareholder return, (7) earnings before interest, taxes, depreciation and amortization (or any combination thereof), (8) cash flow(s), including operating cash flows, free cash flow, discounted cash flow return on investment and cash flow in excess of cost of capital (or any combination thereof), (9) economic value added, (10) return on equity, (11) return on capital, (12) return on assets, (13) net operating profits after taxes, (14) stock price increase, (15) return on sales, (16) debt to equity ratio, (17) payout ratio, (18) asset turnover, (19) ratio of share price to book value of shares, (20) price/earnings ratio, (21) employee satisfaction, (22) diversity, (23) market share, (24) operating income, (25) pre-tax income, (26) safety, (27) diversification of business opportunities, (28) expense ratios, (29) total expenditures, (30) completion of key projects, (31) dividend payout as percentage of net income, (32) direct margin, (33) expense reduction, or (34) any individual performance objective which is measured solely in terms of quantitative targets related to the Company, any Subsidiary or the Company’s or Subsidiary’s business. Such individual performance measures related to the Company, any Subsidiary or the Company’s or Subsidiary’s business may include: (a) production-related factors such as generating capacity factor, performance against the INPO index, generating equivalent availability, heat rates and production cost, (b) transmission and distribution-related factors such as customer satisfaction, reliability (based on outage frequency and duration), and cost, (c) customer service-related factors such as customer satisfaction, service levels and responsiveness and bad debt collections or losses, and (d) relative performance against other similar companies in targeted areas. Each Performance Goal may be expressed on an absolute or relative basis and may include comparisons based on current internal targets, the past performance of the Company, its Subsidiaries or business units or the past or current performance of other companies (including industry or general market indices), or a combination of any of the foregoing, and may be applied at various organizational levels. |
| C. | Impact of Extraordinary Items or Changes in Accounting. The measures used in establishing Performance Goals for a Plan Year shall be determined in accordance with generally accepted accounting principles (“GAAP”) and in a manner consistent with the methods used in the Company’s audited consolidated financial statements (in each case, to the extent applicable), without regard to (i) non-cash impairments, gains or losses on the sale or other disposition of assets or businesses, or severance charges or (ii) changes in accounting, unless, in each case, the Committee decides otherwise |
5
| within the Required Period for the Plan Year or as otherwise required or permitted under Section 162(m) of the Internal Revenue Code. |
| VII. | Determination of Award Amounts for Any Plan Year. |
| A. | Maximum Awards. The maximum Award payable to any Participant with respect to a Plan Year shall be the lesser of five million dollars ($5,000,000.00) or a portion of the Incentive Pool(s) applicable to such Participant determined as follows: |
| 1. | If the Chief Executive Officer is a Participant, the Chief Executive Officer’s maximum Award shall be an amount equal to not more than 25% of the amount of each Incentive Pool in which he or she participates for the Plan Year. |
| 2. | The portion of each Incentive Pool not allocated to the Chief Executive Officer (e.g., the remaining 75% of an Incentive Pool in which the Chief Executive Officer participates and 100% of any other Incentive Pool) shall be divided into shares. There shall be one share for each Participant who is initially designated by the Committee for the Plan Year plus, for each Part-Year Participant, one share multiplied by such Part-Year Participant’s Pro-ration Fraction. The number of shares shall not be reduced in the event a Participant for any reason fails to receive an Award. Thus the number of shares may be increased (thereby reducing the value of each share) but not decreased during the Plan Year. The maximum Award for a Participant shall be one share, and the maximum Award for each Part-Year Participant shall be one share times such part-Year Participant’s Pro-ration Fraction. |
| B. | Committee Discretion to Determine Amount of Award. The Committee shall have absolute discretion to reduce the amount of the Award payable to any Participant for any Plan Year below the maximum Award determined under Section VII.A., and the Committee may decide not to pay any Award to a Participant for the Plan Year, based on such criteria, factors and measures as the Committee in its sole discretion may determine, including but not limited to individual performance or impact and financial and other performance or financial criteria of the Company, a Subsidiary or other business unit in addition to those listed in Section VI.B. The reduction of the Award payable to any Participant (or the decision of the Committee not to pay an Award to a Participant for a Plan Year) shall not affect the maximum Award payable to any other Participant for such Plan Year. Notwithstanding the foregoing, the Committee’s determination of the Award for officers at the level of Executive Vice President and above shall be subject to ratification by the Company’s Board of Directors. The Committee shall certify the amount of the Award to be paid to each Participant. |
| C. | Effect of Termination of Employment. |
| 1. | Except in the case of a Participant who has a termination of employment during a Plan Year on account of Retirement, death or Disability, a Participant must be an |
6
| Employee at the end of a Plan Year to be eligible to receive an Award for that Plan Year. A Participant will become entitled to an Award with respect to a Plan Year on the later to occur of the end of the Plan Year for which the Award is determined and the date the Committee certifies the amount of the Award to which the Participant is entitled for such year by written communication to the Participant, which will normally be within approximately two and one-half months after the end of the Plan Year. No portion of an Award shall be treated as earned by a Participant prior to such date. |
| 2. | A Participant who has a termination of employment prior to the last day of a Plan Year on account of Retirement, death or Disability shall be eligible to receive an Award for such Plan Year, the amount of which shall be determined by the Committee in its sole discretion but which shall not exceed the maximum amount determined under Section VII.A. |
| 3. | Notwithstanding the foregoing, if a Participant is employed pursuant to an employment agreement between the Participant and the Company or a Subsidiary which has been approved by the Compensation Committee of the Company’s Board of Directors, (an “Employment Agreement”) or is subject to another separation or change in control plan or policy of the Company, and such Employment Agreement, plan or policy provides other applicable rules or procedures for the determination of the Participant’s incentive award and entitlement thereto in the event of termination of employment, the provisions of such Employment Agreement, plan or policy shall be controlling with respect to the determination of the amount of, and the Participant’s entitlement to, any Award under the Plan with respect to the Participant. |
| D. | Source, Time and Manner of Payment, Interest. Each Participant’s Award for a Plan Year shall be paid in cash, solely from the general assets of the Company or its Subsidiaries, without interest, as soon as reasonably practicable after the Committee certifies the amount of the Award. Any Awards payable to Participants who have had a termination of employment during the Plan Year on account of Retirement, death or disability shall be payable at the same time other Participants receive Awards under the Plan. |
| E. | Designation of Beneficiaries. Each Participant from time to time may name any person or persons (who may be named concurrently, contingently or successively) to whom the Participant’s Award under the Plan is to be paid if the Participant dies before receipt of the Award. Each such beneficiary designation will revoke all prior designations by the Participant, shall not require the consent of any previously named beneficiary, shall be in a form prescribed or permitted by the Company’s Vice President of Corporate Compensation, and will be effective only when filed with the Company’s Vice President of Corporate Compensation during the Participant’s lifetime. If a Participant fails to so designate a beneficiary before death, or if the beneficiary so designated predeceases the Participant, any Award payable after the Participant’s death shall be paid to the Participant’s estate. |
7
| VIII. | No Assignment of Rights. No Participant or other person shall have any right, title or interest in any Award under this Plan prior to the payment thereof to such person. The rights or interests of Participants under this Plan shall not be subject in any manner to anticipation, alienation, sale, transfer, assignment pledge, encumbrance, charge, garnishment, execution or levy of any kind, either voluntarily or involuntarily, and any attempt to anticipate, alienate, sell, transfer, assign, pledge, encumber, charge, garnish, execute on, levy or otherwise dispose of any right to an Award or any payment hereunder shall be void. |
| IX. | No Greater Employment Rights. The establishment or continuance of this Plan shall not affect or enlarge the employment rights of any Participant or constitute a contract of employment with any Participant, and nothing herein shall be construed as conferring upon a Participant any greater rights to employment than the Participant would otherwise have in the absence of the adoption of this Plan. |
| X. | No Right to Ongoing Participation. The selection of an individual as a Participant in the Plan for any Plan Year shall not require the selection of such individual as a Participant for any subsequent Plan Year, or, if such individual is subsequently so selected, shall not require that the same opportunity for incentive award provided the Participant under the Plan for an earlier Plan Year be provided such Participant for the subsequent Plan Year. |
| XI. | No Personal Liability. Neither the Company, it’s Subsidiaries nor any Committee member or its delegate shall be personally liable for any act done or omitted to be done in good faith in the administration of the Plan. |
| XII. | Unfunded Plan. No Participant or other person shall have any right, title or interest in any property of the Company or its Subsidiaries, and nothing herein shall require the Company or any Subsidiaries to segregate or set aside any funds or other property for the purpose of making any payment under the Plan. |
| XIII. | Facility of Payment. When a person entitled to an incentive award under the Plan is under legal disability, or, in the Committee’s opinion, is in any way incapacitated so as to be unable to manage such person’s affairs, the Committee may direct the payment of an incentive award directly to or for the benefit such person, to such person’s legal representative or guardian, or to a relative or friend of such person. Any payment made in accordance with the preceding sentence shall be a full and complete discharge of any liability for such payment under the Plan, and neither the Committee nor the Company or any Subsidiary shall be under any duty to see to the proper application of such payment. |
| XIV. | Withholding for Taxes and Benefits. The Company and its Subsidiaries, as applicable, may withhold from any payment to be made by it under the Plan all appropriate deductions for employee benefits, if applicable, and such amount or amounts as may be required for purposes of complying with the tax withholding obligations under federal, state and local income and employment tax laws. |
| XV. | Amendment and Termination. The Board of Directors of the Company may amend the Plan at any time and from time to time, in whole or in part, and may terminate the Plan at |
8
| any time, which amendment or termination may include the modification, reduction or cancellation of any prospective Award hereunder which has not been earned and vested pursuant to the terms of the Plan prior to the time of any such amendment or termination, provided that no such amendment or termination shall change the terms and conditions of payment of any Award the final amount of which the Committee has certified to a Participant. Notwithstanding the foregoing, any amendment to the Plan that changes the class of Employees eligible to participate, changes the Performance Goals, or increases the maximum dollar amount that may be paid to a Participant for a Plan Year shall not be effective with respect to Section 162(m) Executives unless such amendment is approved by the holders of the Company’s common stock. |
| XVI. | Section 162(m) Conditions. The Company intends for this Plan and any Awards to satisfy, and to be interpreted in such manner as to satisfy the provisions of Section 162(m) of the Internal Revenue Code with respect to all Section 162(m) Executives. Any provision, application or interpretation of the Plan that is inconsistent with such intent shall be disregarded. |
| XVII. | Applicable Law. The Plan shall be construed under the laws of the State of Illinois, other than its laws with respect to choice of laws. |
9
Exhibit 10.50
FORM OF
EXELON CORPORATION
CHANGE IN CONTROL EMPLOYMENT AGREEMENT
NEWLY ELIGIBLE OR PROMOTED AFTER 01/01/04 SENIOR EXECUTIVE
Table of Contents
| ARTICLE I. DEFINITIONS |
1 | |||
| 1.1 |
“ACCRUED ANNUAL INCENTIVE” |
1 | ||
| 1.2 |
“ACCRUED BASE SALARY” |
1 | ||
| 1.3 |
“ACCRUED LTIP AWARD” |
1 | ||
| 1.4 |
“ACCRUED OBLIGATIONS” |
1 | ||
| 1.5 |
“AFFILIATE” |
1 | ||
| 1.6 |
“AGREEMENT DATE” |
2 | ||
| 1.7 |
“AGREEMENT TERM” |
2 | ||
| 1.8 |
“ANNUAL INCENTIVE” |
2 | ||
| 1.9 |
“APPLICABLE TRIGGER DATE” |
2 | ||
| 1.10 |
“ARTICLE” |
2 | ||
| 1.11 |
“BASE SALARY” |
2 | ||
| 1.12 |
“BENEFICIAL OWNER” |
2 | ||
| 1.13 |
“BENEFICIARY” |
2 | ||
| 1.14 |
“BOARD” |
3 | ||
| 1.15 |
“CAUSE” |
3 | ||
| 1.16 |
“CHANGE DATE” |
3 | ||
| 1.17 |
“CHANGE IN CONTROL” |
3 | ||
| 1.18 |
“CODE” |
4 | ||
| 1.19 |
“COMPANY” |
4 | ||
| 1.20 |
“COMPETITIVE BUSINESS” |
5 | ||
| 1.21 |
“CONFIDENTIAL INFORMATION” |
5 | ||
| 1.22 |
“DISABILITY” |
5 | ||
| 1.23 |
“DISAGGREGATED ENTITY” |
6 | ||
| 1.24 |
“DISAGGREGATION” |
6 | ||
| 1.25 |
“EMPLOYER” |
6 | ||
| 1.26 |
“EXCHANGE ACT” |
6 | ||
| 1.27 |
“GOOD REASON” |
6 | ||
| 1.28 |
“IMMINENT CONTROL CHANGE” |
6 | ||
| 1.29 |
“IMMINENT CONTROL CHANGE PERIOD” |
7 | ||
| 1.30 |
“INCENTIVE PLAN” |
7 | ||
| 1.31 |
“INCLUDING” |
7 | ||
| 1.32 |
“INCUMBENT BOARD” |
7 | ||
| 1.33 |
“IRS” |
7 | ||
| 1.34 |
“LTIP” |
7 | ||
| 1.35 |
“LTIP PERFORMANCE PERIOD” |
7 | ||
| 1.36 |
“LTIP TARGET LEVEL” |
8 | ||
| 1.37 |
“MERGER” |
8 | ||
| 1.38 |
“NOTICE OF TERMINATION” |
8 | ||
| 1.39 |
“PERFORMANCE SHARES” |
8 | ||
| 1.40 |
“PERSON” |
8 | ||
| 1.41 |
“PLANS” |
8 | ||
| 1.42 |
“POST-CHANGE PERIOD” |
8 | ||
| 1.43 |
“POST-DISAGGREGATION PERIOD” |
8 | ||
| 1.44 |
“POST-SIGNIFICANT ACQUISITION PERIOD” |
8 | ||
| 1.45 |
“RESTRICTED STOCK” |
8 | ||
| 1.46 |
“SEC” |
9 | ||
| 1.47 |
“SEC PERSON” |
9 | ||
| 1.48 |
“SECTION” |
9 | ||
| 1.49 |
“SERP” |
9 | ||
| 1.50 |
“SEVERANCE INCENTIVE” |
9 | ||
| 1.51 |
“SEVERANCE PERIOD” |
9 | ||
| 1.52 |
“SIGNIFICANT ACQUISITION” |
9 | ||
i
| 1.53 |
“STOCK OPTIONS” |
10 | ||
| 1.54 |
“TARGET INCENTIVE” |
10 | ||
| 1.55 |
“TAXES” |
10 | ||
| 1.56 |
“TERMINATION DATE” |
10 | ||
| 1.57 |
“TERMINATION OF EMPLOYMENT” |
10 | ||
| 1.58 |
“20% OWNER” |
10 | ||
| 1.59 |
“VOTING SECURITIES” |
10 | ||
| 1.60 |
“WELFARE PLANS” |
10 | ||
| ARTICLE II. TERMS OF EMPLOYMENT |
11 | |||
| 2.1 |
POSITION AND DUTIES DURING A POST-CHANGE PERIOD |
11 | ||
| 2.2 |
POSITION AND DUTIES DURING AN IMMINENT CONTROL CHANGE PERIOD |
11 | ||
| 2.3 |
POSITION AND DUTIES DURING A POST-SIGNIFICANT ACQUISITION PERIOD |
11 | ||
| 2.4 |
POSITION AND DUTIES DURING A POST-DISAGGREGATION PERIOD |
11 | ||
| 2.5 |
EXECUTIVE’S OBLIGATIONS |
11 | ||
| 2.6 |
BASE SALARY DURING THE POST-CHANGE PERIOD |
12 | ||
| 2.7 |
ANNUAL INCENTIVE |
12 | ||
| 2.8 |
OTHER COMPENSATION AND BENEFITS |
13 | ||
| ARTICLE III. TERMINATION OF EMPLOYMENT |
16 | |||
| 3.1 |
DISABILITY |
16 | ||
| 3.2 |
DEATH |
16 | ||
| 3.3 |
TERMINATION BY THE COMPANY FOR CAUSE |
16 | ||
| 3.4 |
TERMINATION BY THE EXECUTIVE FOR GOOD REASON |
18 | ||
| ARTICLE IV. COMPANY’S OBLIGATIONS UPON CERTAIN TERMINATIONS OF EMPLOYMENT |
20 | |||
| 4.1 |
TERMINATION DURING THE POST-CHANGE PERIOD OR POST-SIGNIFICANT ACQUISITION PERIOD |
20 | ||
| 4.2 |
TERMINATION DURING AN IMMINENT CONTROL CHANGE PERIOD |
24 | ||
| 4.3 |
TERMINATION DURING A POST-DISAGGREGATION PERIOD |
27 | ||
| 4.4 |
TIMING OF SEVERANCE PAYMENTS |
28 | ||
| 4.5 |
WAIVER AND RELEASE |
29 | ||
| 4.6 |
BREACH OF COVENANTS |
29 | ||
| 4.7 |
TERMINATION BY THE COMPANY FOR CAUSE |
29 | ||
| 4.8 |
TERMINATION BY EXECUTIVE OTHER THAN FOR GOOD REASON |
29 | ||
| 4.9 |
TERMINATION BY THE COMPANY FOR DISABILITY |
29 | ||
| 4.10 |
UPON DEATH |
30 | ||
| 4.11 |
SOLE AND EXCLUSIVE OBLIGATIONS |
30 | ||
| ARTICLE V. CERTAIN ADDITIONAL PAYMENTS BY THE COMPANY |
31 | |||
| 5.1 |
GROSS-UP PAYMENT |
31 | ||
| 5.2 |
LIMITATION ON GROSS-UP PAYMENTS |
31 | ||
| 5.3 |
ADDITIONAL GROSS-UP AMOUNTS |
32 | ||
| 5.4 |
AMOUNT INCREASED OR CONTESTED |
32 | ||
| 5.5 |
REFUNDS |
34 | ||
| ARTICLE VI. EXPENSES, INTEREST AND DISPUTE RESOLUTION |
35 | |||
| 6.1 |
ENFORCEMENT AND LATE PAYMENTS |
35 | ||
| 6.2 |
INTEREST |
35 | ||
| 6.3 |
ARBITRATION |
35 | ||
| ARTICLE VII. NO SET-OFF OR MITIGATION |
36 | |||
| 7.1 |
NO SET-OFF BY COMPANY |
36 | ||
| 7.2 |
NO MITIGATION |
36 | ||
| ARTICLE VIII. RESTRICTIVE COVENANTS |
37 | |||
| 8.1 |
CONFIDENTIAL INFORMATION |
37 | ||
ii
| 8.2 |
NON-COMPETITION |
37 | ||
| 8.3 |
NON-SOLICITATION |
38 | ||
| 8.4 |
INTELLECTUAL PROPERTY |
38 | ||
| 8.5 |
REASONABLENESS OF RESTRICTIVE COVENANTS |
39 | ||
| 8.6 |
RIGHT TO INJUNCTION; SURVIVAL OF UNDERTAKINGS |
40 | ||
| ARTICLE IX. NON-EXCLUSIVITY OF RIGHTS |
40 | |||
| 9.1 |
OTHER RIGHTS |
40 | ||
| 9.2 |
NO RIGHT TO CONTINUED EMPLOYMENT |
41 | ||
| ARTICLE X. MISCELLANEOUS |
41 | |||
| 10.1 |
NO ASSIGNABILITY |
41 | ||
| 10.2 |
SUCCESSORS |
41 | ||
| 10.3 |
AFFILIATES |
41 | ||
| 10.4 |
PAYMENTS TO BENEFICIARY |
41 | ||
| 10.5 |
NON-ALIENATION OF BENEFITS |
41 | ||
| 10.6 |
SEVERABILITY |
41 | ||
| 10.7 |
AMENDMENTS |
42 | ||
| 10.8 |
NOTICES |
42 | ||
| 10.9 |
JOINT AND SEVERAL LIABILITY |
42 | ||
| 10.10 |
COUNTERPARTS |
42 | ||
| 10.11 |
GOVERNING LAW |
42 | ||
| 10.12 |
CAPTIONS |
43 | ||
| 10.13 |
NUMBER AND GENDER |
43 | ||
| 10.14 |
TAX WITHHOLDING |
43 | ||
| 10.15 |
NO WAIVER |
43 | ||
| 10.16 |
ENTIRE AGREEMENT |
43 | ||
iii
EXELON CORPORATION
CHANGE-IN-CONTROL EMPLOYMENT AGREEMENT
THIS AGREEMENT dated , 200 (the “Agreement Date”), is made by and among Exelon Corporation, incorporated under the laws of the Commonwealth of Pennsylvania (together with successors thereto, the “Company”), on behalf of itself and , a corporation (together with successors thereto, the “Subsidiary”), and (“Executive”).
RECITALS
The Board of Directors of the Company (the “Board”) has determined that it is in the best interests of the Company and its shareholders to assure that the Company will have the continued services of the Executive, despite the possibility or occurrence of a Change in Control of the Company. The Board believes it is imperative to reduce the distraction of the Executive that would result from the personal uncertainties caused by a pending or threatened Change in Control or a Significant Acquisition, to encourage the Executive’s full attention and dedication to the Company, and to provide the Executive with compensation and benefits arrangements upon a Change in Control which are competitive with those of similarly-situated corporations. This Agreement is intended to accomplish these objectives.
Article I.
Definitions
As used in this Agreement, the terms specified below shall have the following meanings:
1.1 “Accrued Annual Incentive” means the amount of any Annual Incentive earned but not yet paid with respect to the Company’s latest fiscal year ended prior to the Termination Date.
1.2 “Accrued Base Salary” means the amount of Executive’s Base Salary that is accrued but not yet paid as of the Termination Date.
1.3 “Accrued LTIP Award” means the amount of any LTIP Award earned and vested, but either deferred or not yet paid as of the Termination Date.
1.4 “Accrued Obligations” means, as of any date, the sum of Executive’s Accrued Base Salary, Accrued Annual Incentive, Accrued LTIP Award, any accrued but unpaid paid time off, and any other amounts and benefits which are then due to be paid or provided to Executive by the Company, but have not yet been paid or provided (as applicable).
1.5 “Affiliate” means any Person (including the Subsidiary) that directly or indirectly controls, is controlled by, or is under common control with, the Company. For purposes of this definition the term “control” with respect to any Person means the power to direct or cause the
direction of management or policies of such Person, directly or indirectly, whether through the ownership of Voting Securities, by contract or otherwise.
1.6 “Agreement Date” — see the introductory paragraph of this Agreement.
1.7 “Agreement Term” means the period commencing on the Agreement Date and ending on the second anniversary of the Agreement Date or, if later, such later date to which the Agreement Term is extended under the following sentence, unless earlier terminated as provided herein. Commencing on the first anniversary of the Agreement Date, the Agreement Term shall automatically be extended each day by one day to create a new two-year term until, at any time after the first anniversary of the Agreement Date, the Company delivers written notice (an “Expiration Notice”) to Executive that the Agreement shall expire on a date specified in the Expiration Notice (the “Expiration Date”) that is not less than 12 months after the date the Expiration Notice is delivered to Executive; provided, however, that if a Change Date, Imminent Control Change, Disaggregation or Significant Acquisition occurs before the Expiration Date specified in the Expiration Notice, then such Expiration Notice shall be void and of no further effect. If such Imminent Control Change or Disaggregation does not culminate in a Change Date, then such Expiration Notice shall be reinstated and the Agreement shall expire on the date originally specified as the Expiration Date, or if later, the date the Imminent Control Change lapses or the end of the sixtieth day after the Disaggregation. Notwithstanding anything herein to the contrary, the Agreement Term shall end at the end of the Severance Period if applicable, or if there is no Severance Period, the earliest of the following: (a) the second anniversary of the Change Date, (b) eighteen (18) months after the Significant Acquisition, provided there has been no Change Date, (c) the end of the sixtieth day after the Disaggregation if there has been no Change Date after the Disaggregation, or (d) the Termination Date.
1.8 “Annual Incentive” — see Section 2.7.
1.9 “Applicable Trigger Date” means
(a) the Change Date with respect to the Post-Change Period;
(b) the date of an Imminent Control Change with respect to the Imminent Control Change Period;
(c) the date of a Significant Acquisition with respect to a Post-Significant Acquisition Period; and
(d) the date of a Disaggregation with respect to a Post-Disaggregation Period.
1.10 “Article” means an article of this Agreement.
1.11 “Base Salary” — see Section 2.6.
1.12 “Beneficial Owner” means such term as defined in Rule 13d-3 of the SEC under the Exchange Act.
1.13 “Beneficiary” — see Section 10.4.
2
1.14 “Board” means the Board of Directors of Company or, from and after the effective date of a Corporate Transaction (as defined in Section 1.17), the Board of Directors of the corporation resulting from a Corporate Transaction or, if securities representing at least 50% of the aggregate voting power of such resulting corporation are directly or indirectly owned by another corporation, such other corporation.
1.15 “Cause” — see Section 3.3.
1.16 “Change Date” means the date on which a Change in Control first occurs during the Agreement Term.
1.17 “Change in Control” means, except as otherwise provided below, the first to occur of any of the following during the Agreement Term:
(a) any SEC Person becomes the Beneficial Owner of 20% or more of the then outstanding common stock of the Company or of Voting Securities representing 20% or more of the combined voting power of all the then outstanding Voting Securities of Company (such an SEC Person, a “20% Owner”); provided, however, that for purposes of this subsection (a), the following acquisitions shall not constitute a Change in Control: (1) any acquisition directly from the Company (excluding any acquisition resulting from the exercise of an exercise, conversion or exchange privilege unless the security being so exercised, converted or exchanged was acquired directly from the Company), (2) any acquisition by the Company, (3) any acquisition by an employee benefit plan (or related trust) sponsored or maintained by the Company or any corporation controlled by the Company (a “Company Plan”), or (4) any acquisition by any corporation pursuant to a transaction which complies with clauses (i), (ii) and (iii) of subsection (c) of this definition; provided further, that for purposes of clause (2), if any 20% Owner of the Company other than the Company or any Company Plan becomes a 20% Owner by reason of an acquisition by the Company, and such 20% Owner of the Company shall, after such acquisition by the Company, become the beneficial owner of any additional outstanding common shares of the Company or any additional outstanding Voting Securities of the Company (other than pursuant to any dividend reinvestment plan or arrangement maintained by the Company) and such beneficial ownership is publicly announced, such additional beneficial ownership shall constitute a Change in Control; or
(b) Individuals who, as of the date hereof, constitute the Board (the “Incumbent Board”) cease for any reason to constitute at least a majority of the Incumbent Board; provided, however, that any individual becoming a director subsequent to the date hereof whose election, or nomination for election by the Company’s shareholders, was approved by a vote of at least a majority of the directors then comprising the Incumbent Board shall be considered as though such individual were a member of the Incumbent Board, but excluding, for this purpose, any such individual whose initial assumption of office occurs as a result of an actual or threatened election contest (as such terms are used in Rule 14a-11 promulgated under the Exchange Act) or other actual or threatened solicitation of proxies or consents by or on behalf of a Person other than the Board; or
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(c) Consummation of a reorganization, merger or consolidation (“Merger”), or the sale or other disposition of more than 50% of the operating assets of the Company (determined on a consolidated basis), other than in connection with a sale-leaseback or other arrangement resulting in the continued utilization of such assets (or the operating products of such assets) by the Company (such reorganization, merger, consolidation, sale or other disposition, a “Corporate Transaction”); excluding, however, a Corporate Transaction pursuant to which:
(i) all or substantially all of the individuals and entities who are the Beneficial Owners, respectively, of the outstanding common stock of Company and outstanding Voting Securities of the Company immediately prior to such Corporate Transaction beneficially own, directly or indirectly, more than 60% of, respectively, the then-outstanding shares of common stock and the combined voting power of the then-outstanding voting securities entitled to vote generally in the election of directors, as the case may be, of the corporation resulting from such Corporate Transaction (including, without limitation, a corporation which, as a result of such transaction, owns the Company or all or substantially all of the assets of the Company either directly or through one or more subsidiaries) in substantially the same proportions as their ownership immediately prior to such Corporate Transaction of the outstanding common stock of Company and outstanding Voting Securities of the Company, as the case may be;
(ii) no SEC Person (other than the corporation resulting from such Corporate Transaction, and any Person which beneficially owned, immediately prior to such corporate Transaction, directly or indirectly, 20% or more of the outstanding common stock of the Company or the outstanding Voting Securities of the Company, as the case may be) becomes a 20% Owner, directly or indirectly, of the then-outstanding common stock of the corporation resulting from such Corporate Transaction or the combined voting power of the outstanding voting securities of such corporation; and
(iii) individuals who were members of the Incumbent Board will constitute at least a majority of the members of the board of directors of the corporation resulting from such Corporate Transaction; or
(d) Approval by the Company’s shareholders of a plan of complete liquidation or dissolution of the Company, other than a plan of liquidation or dissolution which results in the acquisition of all or substantially all of the assets of the Company by an affiliated company.
Notwithstanding the occurrence of any of the foregoing events, a Change in Control shall not occur with respect to Executive if, in advance of such event, Executive agrees in writing that such event shall not constitute a Change in Control.
1.18 “Code” means the Internal Revenue Code of 1986, as amended.
1.19 “Company” – see the introductory paragraph to this Agreement.
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1.20 “Competitive Business” means, as of any date, any utility business and any individual or entity (and any branch, office, or operation thereof) which engages in, or proposes to engage in (with Executive’s assistance) (i) the harnessing, production, transmission, distribution, marketing or sale of energy or the transmission or distribution thereof through wire or cable or similar medium, (ii) any other business engaged in by the Company prior to Executive’s Termination Date which represents for any calendar year or is projected by the Company (as reflected in a business plan adopted by the Company before Executive’s Termination Date) to yield during any year during the first three-fiscal year period commencing on or after Executive’s Termination Date, more than 5% of the gross revenue of Company, and, in either case, which is located (x) anywhere in the United States, or (y) anywhere outside of the United States where Company is then engaged in, or proposes as of the Termination Date to engage in to the knowledge of the Executive, any of such activities.
1.21 “Confidential Information” shall mean any information, ideas, processes, methods, designs, devices, inventions, data, techniques, models and other information developed or used by the Company or any Affiliate and not generally known in the relevant trade or industry relating to the Company’s or its Affiliates’ products, services, businesses, operations, employees, customers or suppliers, whether in tangible or intangible form, which gives the Company and its Affiliates a competitive advantage in the harnessing, production, transmission, distribution, marketing or sale of energy or the transmission or distribution thereof through wire or cable or similar medium or in the energy services industry and other businesses in which the Company or an Affiliate is engaged, or of third parties which the Company or Affiliate is obligated to keep confidential, or which was learned, discovered, developed, conceived, originated or prepared during or as a result of Executive’s performance of any services on behalf of the Company and which falls within any of the following general categories:
(a) information relating to trade secrets of the Company or Affiliate or any customer or supplier of the Company or Affiliate;
(b) information relating to existing or contemplated products, services, technology, designs, processes, formulae, algorithms, research or product developments of the Company or Affiliate or any customer or supplier of the Company or Affiliate;
(c) information relating to business plans or strategies, sales or marketing methods, methods of doing business, customer lists, customer usages and/or requirements, supplier information of the Company or Affiliate or any customer or supplier of the Company or Affiliate;
(d) information subject to protection under the Uniform Trade Secrets Act, as adopted by the State of Illinois, or to any comparable protection afforded by applicable law; or
(e) any other confidential information which either the Company or Affiliate or any customer or supplier of the Company or Affiliate may reasonably have the right to protect by patent, copyright or by keeping it secret and confidential.
1.22 “Disability” – see Section 3.1(b).
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1.23 “Disaggregated Entity” means the Disaggregated Unit or any other Person (other than the Company or an Affiliate) that controls or is under common control with the Disaggregated Unit.
1.24 “Disaggregation” means the consummation, in contemplation of a Change in Control, of a sale, spin-off or other disaggregation by the Company or the Affiliate or business unit of the Company (“Disaggregated Unit”) which employed Executive immediately prior to the sale, spin-off or other disaggregation.
1.25 “Employer” means, collectively or severally, the Company and the Subsidiary (or other Affiliate employing Executive).
1.26 “Exchange Act” means the Securities Exchange Act of 1934, as amended.
1.27 “Good Reason” — see Section 3.4.
1.28 “Imminent Control Change” means, as of any date on or after the Agreement Date and prior to the Change Date, the occurrence of any one or more of the following:
(a) the Company enters into an agreement the consummation of which would constitute a Change in Control;
(b) Any SEC Person commences a “tender offer” (as such term is used in Section 14(d) of the Exchange Act) or exchange offer, which, if consummated, would result in a Change in Control; or
(c) Any SEC Person files with the SEC a preliminary or definitive proxy solicitation or election contest to elect or remove one or more members of the Board, which, if consummated or effected, would result in a Change in Control;
provided, however, that an Imminent Control Change will lapse and cease to qualify as an Imminent Control Change:
(i) With respect to an Imminent Control Change described in clause (a) of this definition, the date such agreement is terminated, cancelled or expires without a Change Date occurring;
(ii) With respect to an Imminent Control Change described in clause (b) of this definition, the date such tender offer or exchange offer is withdrawn or terminates without a Change Date occurring;
(iii) With respect to an Imminent Control Change described in clause (c) of this definition, (1) the date the validity of such proxy solicitation or election contest expires under relevant state corporate law, or (2) the date such proxy solicitation or election contest culminates in a shareholder vote, in either case without a Change Date occurring; or
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(iv) The date a majority of the members of the Incumbent Board make a good faith determination that any event or condition described in clause (a), (b), or (c) of this definition no longer constitutes an Imminent Control Change, provided that such determination may not be made prior to the twelve (12) month anniversary of the occurrence of such event.
1.29 “Imminent Control Change Period” means the period commencing on the date of an Imminent Control Change, and ending on the first to occur thereafter of
(a) a Change Date, provided
(i) such date occurs no later than the one-year anniversary of the Termination Date, and
(ii) either the Imminent Control Change has not lapsed, or the Imminent Control Change in effect upon such Change Date is the last Imminent Control Change in a series of Imminent Control Changes unbroken by any period of time between the lapse of an Imminent Control Change and the occurrence of a new Imminent Control Change;
(b) if Executive’s business unit undergoes Disaggregation and Executive retains substantially the same position with the Disaggregated Entity as immediately prior to such Disaggregation (determined without regard to reporting obligations) the earlier to occur after such Disaggregation of a Change Date or the end of the 60th day following such Disaggregation without the occurrence of a Change Date,
(c) the date an Imminent Control Changes lapses without the prior or concurrent occurrence of a new Imminent Control Change; or
(d) the twelve-month anniversary of the Termination Date.
1.30 “Incentive Plan” means the Exelon Corporation Annual Incentive Plan for Senior Executives or such other annual incentive award arrangement of the Company in which the Executive is a participant in lieu of such program.
1.31 “Including” means including without limitation.
1.32 “Incumbent Board”—see definition of Change in Control.
1.33 “IRS” means the Internal Revenue Service of the United States of America.
1.34 “LTIP” means the Exelon Corporation Long-Term Incentive Plan, as amended from time to time, or any successor thereto, and including any Stock Options or Restricted Stock granted thereunder to replace stock options or restricted stock initially granted under the Unicom Corporation Long-Term Incentive Plan.
1.35 “LTIP Performance Period” means the one-year performance period applicable to an LTIP award, as designated in accordance with the LTIP.
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1.36 “LTIP Target Level” means, in respect of any grant of Performance Shares under the Exelon Performance Share Program under the LTIP, the number of Performance Shares which Executive would have been awarded (prior to the Termination Date) for the LTIP Performance Period corresponding to such grant if the business and personal performance goals related to such grant were achieved at the 100% (target) level as of the end of the LTIP Performance Period.
1.37 “Merger”—see definition of Change in Control.
1.38 “Notice of Termination” means a written notice given in accordance with Section 10.8 which sets forth (i) the specific termination provision in this Agreement relied upon by the party giving such notice, (ii) in reasonable detail the specific facts and circumstances claimed to provide a basis for such Termination of Employment, and (iii) if the Termination Date is other than the date of receipt of such Notice of Termination, the Termination Date.
1.39 “Performance Shares”—see Section 4.1(c). After a Disaggregation, “Performance Shares” shall also refer to performance shares, performance units or similar stock incentive awards granted by a Disaggregated Entity (or an affiliate thereof) in replacement of performance shares, performance units or similar stock incentive awards granted under the Exelon Performance Share Program under the LTIP.
1.40 “Person” means any individual, sole proprietorship, partnership, joint venture, limited liability company, trust, unincorporated organization, association, corporation, institution, public benefit corporation, entity or government instrumentality, division, agency, body or department.
1.41 “Plans” means plans, practices, policies and programs of the Company (or, if applicable to Executive, the Disaggregated Entity or Affiliate).
1.42 “Post-Change Period” means the period commencing on the Change Date and ending on the earlier of the Termination Date or the second anniversary of the Change Date.
1.43 “Post-Disaggregation Period” means the period commencing on the first date during the Agreement Term on which a Change in Control occurs following a Disaggregation, provided such Change Date occurs no more than 60 days following such Disaggregation, and ending on the earlier of the Termination Date or the second anniversary of the Change Date. If no Change Date occurs within 60 days after the Disaggregation, there shall be no Post-Disaggregation Period.
1.44 “Post-Significant Acquisition Period” means the period commencing on the date of a Significant Acquisition that occurs during the Agreement Term prior to a Change Date, and ending on the first to occur of (a) the end of the 18-month period commencing on the date of the Significant Acquisition, (b) the Change Date, or (c) the Termination Date.
1.45 “Restricted Stock” — see Section 4.1(d). After a Disaggregation, “Restricted Stock” shall also refer to deferred stock units, restricted stock or restricted share units granted by a Disaggregated Entity (or an affiliate thereof) in replacement of deferred stock units, restricted
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stock or restricted share units granted by the Company other than under the Exelon Performance Share Program under the LTIP.
1.46 “SEC” means the United States Securities and Exchange Commission.
1.47 “SEC Person” means any person (as such term is used in Rule 13d-5 of the SEC under the Exchange Act) or group (as such term is defined in Sections 3(a)(9) and 13(d)(3) of the Exchange Act), other than (a) the Company or an Affiliate, or (b) any employee benefit plan (or any related trust) of the Company or any of its Affiliates.
1.48 “Section” means, unless the context otherwise requires, a section of this Agreement.
1.49 “SERP” means the PECO Energy Company Supplemental Retirement Plan or the Exelon Corporation Supplemental Management Retirement Plan, whichever is applicable to Executive, or any successor to either or both.
1.50 “Severance Incentive” means the greater of (a) the Target Incentive for the performance period in which the Termination Date occurs, or (b) the average (mean) of the actual Annual Incentives paid (or payable, to the extent not previously paid) to the Executive under the Incentive Plan for each of the two calendar years preceding the calendar year in which the Termination Date occurs.
1.51 “Severance Period” means the period beginning on the Executive’s Termination Date, provided Executive’s Termination of Employment entitles Executive to benefits under Section 4.1, 4.2 or 4.3, and ending on the third anniversary thereof. There shall be no Severance Period if Executive’s Termination of Employment is on account of death or Disability or if Executive’s employment is terminated by the Company for Cause or by Executive other than for Good Reason.
1.52 “Significant Acquisition” means a Corporate Transaction affecting the Executive’s business unit (or, if Executive is employed at the headquarters for the Company’s corporate business operations (“Corporate Center”), a Corporate Transaction that affects the Corporate Center) that is consummated after the Agreement Date and prior to the Change Date, which Corporate Transaction is not a Change in Control, provided that as a result of such Corporate Transaction, all or substantially all of the individuals and entities who are the Beneficial Owners, respectively, of the outstanding common stock of Company and outstanding Voting Securities of the Company immediately prior to such Corporate Transaction beneficially own, directly or indirectly, more than 60% but not more than 66-2/3% of, respectively, the then-outstanding shares of common stock and the combined voting power of the then-outstanding voting securities entitled to vote generally in the election of directors, as the case may be, of the corporation resulting from such Corporate Transaction (including, without limitation, a corporation which, as a result of such transaction, owns the Company or all or substantially all of the assets of the Company either directly or through one or more subsidiaries) in substantially the same proportions as their ownership immediately prior to such Corporate Transaction of the outstanding common stock of Company and outstanding Voting Securities of the Company, as the case may be.
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1.53 “Stock Options” — see Section 4.1(b). After a Disaggregation, “Stock Options” shall also refer to stock options, stock appreciation rights, or similar incentive awards granted by the Disaggregated Entity (or an affiliate thereof) in replacement of stock options, stock appreciation rights, or similar incentive awards granted under the LTIP.
1.54 “Target Incentive” as of a certain date means an amount equal to the product of Base Salary determined as of such date multiplied by the percentage of such Base Salary to which Executive would have been entitled immediately prior to such date under the Incentive Plan for the applicable performance period if the performance goals established pursuant to such Incentive Plan were achieved at the 100% (target) level as of the end of the applicable performance period (taking into account for this purpose any negative discretion exercised by the Compensation Committee of the Board in establishing such target); provided, however, that any reduction in Executive’s Base Salary or Annual Incentive that would qualify as Good Reason shall be disregarded for purposes of this definition.
1.55 “Taxes” means the incremental federal, state, local and foreign income, employment, excise and other taxes payable by Executive with respect to any applicable item of income.
1.56 “Termination Date” means the effective date of Executive’s Termination of Employment, which shall be the last day on which Executive is employed by the Company, an Affiliate or a Disaggregated Entity; provided, however, that (a) if the Company terminates the Executive’s employment other than for Cause or Disability or if the Executive terminates Executive’s employment for Good Reason, then the Termination Date shall be the date of receipt of the Notice of Termination by Executive (if such Notice is given by the Company, an Affiliate or a Disaggregated Entity) or by the Company, an Affiliate or a Disaggregated Entity (if such Notice is given by Executive), or such later date, not more than 15 days after the giving of such Notice, specified in such Notice as of which Executive’s employment shall be terminated; and (b) if Executive’s employment is terminated by reason of death or Disability, the Termination Date shall be the date of Executive’s death or the Disability Effective Date (as described in Section 3.1(a)).
1.57 “Termination of Employment” means any termination of Executive’s employment with the Company and its Affiliates, whether such termination is initiated by the Employer or by Executive; provided that if the Executive’s cessation of employment with the Company and its Affiliates is effected through a Disaggregation, and Executive is employed in substantially the same position (without regard to reporting obligations) by the Disaggregated Entity immediately following the Disaggregation, and a Change Date occurs no more than 60 days after such Disaggregation, then the Disaggregation shall not be deemed to effect a “Termination of Employment” for purposes of this Agreement, and after the Disaggregation, “Termination of Employment” means any termination of Executive’s employment with the Disaggregated Entity, whether such termination is initiated by the Disaggregated Entity or by Executive.
1.58 “20% Owner” — see paragraph (a) of the definition of “Change in Control.”
1.59 “Voting Securities” means with respect to a corporation, securities of such corporation that are entitled to vote generally in the election of directors of such corporation.
1.60 “Welfare Plans” - see Section 2.8(a)(ii).
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Article II.
Terms of Employment
2.1 Position and Duties During a Post-Change Period. During the Post-Change Period prior to the Termination Date, (i) Executive’s position, duties and responsibilities (other than the position or level of officer to whom the Executive reports or any change that is part of a policy, program or arrangement applicable to peer executives of the Company and any successor to the Company) shall be at least commensurate in all material respects with the most significant of those held, exercised and assigned at any time during the 90-day period immediately before the Change Date (or if the Change Date ended an Imminent Control Change Period, during the 90-day period immediately before the beginning of the Imminent Control Change Period) and (ii) Executive’s services shall be performed at the location where Executive was employed immediately before the Change Date (or if the Change Date ended an Imminent Control Change Period, before the beginning of such Imminent Control Change Period) or any other location no more than 50 miles from such location (unless such other location is closer to Executive’s residence than the prior location).
2.2 Position and Duties During an Imminent Control Change Period. During the portion of any Imminent Control Change Period that occurs before the Termination Date, the Company may in its discretion change the Executive’s position, authority and duties and may change the location where Executive’s services shall be performed.
2.3 Position and Duties During a Post-Significant Acquisition Period. During the portion of any Post-Significant Acquisition Period that occurs before the Termination Date, the Company may in its discretion change the Executive’s position, authority and duties, and may change the location where Executive’s services shall be performed.
2.4 Position and Duties During a Post-Disaggregation Period. During the Post-Disaggregation Period, (i) Executive’s position with the Disaggregated Entity shall be at least commensurate in all material respects with the most significant position held by Executive with the Disaggregated Entity immediately following the Disaggregation, and (ii) unless Executive otherwise consents, Executive’s services shall be performed at the location where Executive was employed immediately prior to the Change Date or any other location no more than 50 miles from such location (unless such other location is closer to Executive’s residence than the prior location); provided, however, that in determining whether the Executive’s Termination of Employment is for Cause, “Cause” shall be determined as though the provisions of Section 3.3(a) applied commencing with the first day of the Post-Disaggregation Period.
2.5 Executive’s Obligations. During the Executive’s employment (other than any periods of paid time off, sick leave or disability to which Executive is entitled), Executive agrees to devote Executive’s full attention and time to the business and affairs of the Company (or, in the case of a Disaggregation, the Disaggregated Entity) and to use Executive’s best efforts to perform such duties. Executive may (i) serve on corporate, civic or charitable boards or committees, (ii) deliver lectures, fulfill speaking engagements or teach at educational institutions
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and (iii) manage personal investments, so long as such activities are consistent with the Plans of the Employer (or in the case of a Disaggregation, the Disaggregated Entity) in effect from time to time, and do not significantly interfere with the performance of Executive’s duties under this Agreement.
2.6 Base Salary During the Post-Change Period.
(a) Base Salary During Post-Change Period. Prior to the Termination Date during the Post-Change Period, the Company shall pay or cause to be paid to Executive an annual base salary in cash, which shall be paid in a manner consistent with the Employer’s payroll practices in effect immediately before the Applicable Trigger Date at an annual rate not less than 12 times the highest monthly base salary paid or payable to Executive by the Employer in respect of the 12-month period immediately before the Applicable Trigger Date (such annual rate salary, the “Base Salary”). During the Post-Change Period, the Base Salary shall be reviewed no more than 12 months after the last salary increase awarded to Executive prior to the Applicable Trigger Date and thereafter shall be reviewed and shall be increased at any time and from time to time as shall be substantially consistent with increases in base salary awarded to peer executives of the Company generally. Base Salary shall not be reduced unless such reduction is part of a policy, program or arrangement applicable to peer executives of the Company (including peer executives of any successor to the Company), and the term Base Salary as used in this Agreement shall refer to Base Salary as so increased. Any increase in Base Salary shall not limit or reduce any other obligation of the Company to the Executive under this Agreement.
(b) Base Salary During the Imminent Control Change Period, Post-Significant Acquisition Period and Post-Disaggregation Period. Section 2.6(a) shall not apply during the Imminent Control Change Period, Post-Significant Acquisition Period or Post-Disaggregation Period.
2.7 Annual Incentive.
(a) Annual Incentive During the Post-Change Period. In addition to Base Salary, the Company shall provide or cause to be provided to Executive the opportunity to receive payment of an annual incentive (the “Annual Incentive”) with an award opportunity no less, including target performance goals not materially more difficult to achieve, than that in effect immediately prior to the Applicable Trigger Date for each applicable performance period which commences prior to the Termination Date and ends during the Post-Change Period. The amount of the Executive’s award opportunity in effect for any relevant period shall be determined taking into account any negative discretion exercised by the Compensation Committee of the Board in establishing such opportunity.
(b) Annual Incentive during the Imminent Control Change Period, Post-Significant Acquisition Period or Post-Disaggregation Period. Section 2.7(a) shall not apply during the Imminent Control Change Period, Post-Significant Acquisition Period or Post-Disaggregation Period.
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2.8 Other Compensation and Benefits.
(a) Other Compensation and Benefits during the Post-Change Period. In addition to Base Salary and Annual Incentive, prior to the Termination Date the Company shall provide or cause to be provided, throughout the Post-Change Period, the following other compensation and benefits to Executive, provided that, in no event shall such additional compensation and benefits (including incentives, measured with respect to long term and special incentives, to the extent, if any, that such distinctions are applicable) be materially less favorable, in the aggregate, than those provided at any time after the Applicable Trigger Date to peer executives of the Company (including peer executives of any successor to the Company) generally:
(i) Incentive, Savings and Retirement Plans. Executive shall be entitled to participate in all incentive, savings and retirement Plans applicable to peer executives of the Company generally.
(ii) Welfare Benefit Plans. Executive and/or the Executive’s family, as the case may be, shall be eligible for participation in and shall receive all benefits under welfare benefit Plans (“Welfare Plans”) (including medical, prescription, dental, disability, employee life, group life, accidental death and travel accident insurance benefits, but excluding any severance pay) provided by the Employer from time to time to peer executives of the Company generally.
(iii) Other Employee Benefits. Executive shall be entitled to other employee benefits, perquisites and fringe benefits in accordance with the most favorable Plans applicable to peer executives of the Company generally.
(iv) Expenses. Executive shall be entitled to receive prompt reimbursement for all reasonable business expenses incurred by the Executive in accordance with the most favorable Plans applicable to peer executives of the Company generally.
(v) Office and Support Staff. Executive shall be entitled to an office or offices of a size and with furnishings and other appointments, and to secretarial and other assistance substantially equivalent to the office or offices, furnishings, appointments and assistance as in effect with respect to Executive on the Applicable Trigger Date.
(vi) Paid Time Off. Executive shall be entitled to paid time off in accordance with the Plans applicable to peer executives of the Company generally.
(vii) LTIP Awards. Awards under the LTIP shall be granted to Executive with aggregate target opportunities not less than those granted to peer executives of the Company.
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(b) Other Compensation and Benefits During the Imminent Control Change Period, Post-Significant Acquisition Period or Post-Disaggregation Period. Section 2.8(a) shall not apply during Imminent Control Change Period, Post-Significant Acquisition Period or Post-Disaggregation Period.
(c) Stock Options, Restricted Stock, and Performance Shares During the Post-Disaggregation Period.
(i) Stock Options.
(A) Extinguished or Converted at Disaggregation. If so provided in the documents and instruments (“Disaggregation Documents”) pursuant to which the Disaggregation is effected, then all of Executive’s Stock Options shall (I) be extinguished immediately prior to the Disaggregation for such consideration as is provided for in the Disaggregation Documents (but not less than the product of the number of Executive’s vested Stock Options multiplied by the difference between the fair market value of Exelon stock immediately prior to the Disaggregation and the option exercise price), or (II) be converted into options to acquire stock of the Disaggregated Entity or an affiliate thereof on a basis determined by the Company in good faith to preserve economic value.
(B) Extinguished or Converted at Merger. If the Change in Control following the Disaggregation is a Merger, and if so provided in the agreement pursuant to which the Merger is effected, then all of Executive’s Company Stock Options that were not extinguished or converted to options to acquire stock in the Disaggregated Entity or an affiliate shall (I) be extinguished immediately prior to the Change in Control for such consideration as is provided for Stock Options of peer executives employed by the Company or an Affiliate, or (II) be converted into options to acquire stock of the corporation resulting from the Merger (“Merger Survivor”) or an affiliate thereof, on the same basis as Stock Options of employees of the Company are converted.
(C) Stock Options after the Disaggregation. Executive’s unextinguished Stock Options, whether or not they are converted to options for stock of the Disaggregated Entity or Merger Survivor, shall continue to vest and, once vested, shall remain exercisable in accordance with their terms, subject to Section 4.3(b).
(ii) Performance Shares.
(A) Extinguished or Converted at Disaggregation. If so provided in the Disaggregation Documents, all of Executive’s Performance Shares shall (I) be extinguished immediately prior to the Disaggregation for such consideration as is provided under the Disaggregation Documents (but no less than the fair market value, immediately prior to the Disaggregation, of a number of Exelon shares
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equal to the sum of Executive’s earned and awarded Performance Shares and the target number of Executive’s Performance Shares that have not yet been earned and awarded), or (II) shall be converted into performance shares with respect to the Disaggregated Entity or an affiliate (on a basis determined by the Company in good faith to preserve economic value for the Executive).
(B) Extinguished or Converted at Merger. If the Change in Control following the Disaggregation is a Merger, and if so provided in the agreement pursuant to which the Merger is effected, then all of Executive’s Performance Shares that were not extinguished or converted to performance shares of the Disaggregated Entity or an affiliate shall (I) be extinguished immediately prior to the Change in Control for such consideration as is provided for Performance Shares of peer executives employed by the Company or an Affiliate, or (II) be converted into performance shares of the Merger Survivor or an affiliate thereof, on the same basis as Performance Shares of employees of the Company are converted.
(C) Performance Shares after the Disaggregation. Executive’s unextinguished Performance Shares, whether or not they are converted into performance shares of the Disaggregated Entity or Merger Survivor, will continue to vest during the Post-Disaggregation Period, subject to Section 4.3(c).
(iii) Restricted Stock.
(A) Extinguished or Converted at Disaggregation. If so provided in the Disaggregation Documents, all of Executive’s Restricted Stock shall (I) be extinguished immediately prior to the Disaggregation for an amount equal to the fair market value of an equal number of shares of Exelon common stock, or (II) shall be converted into restricted stock of the Disaggregated Entity or an affiliate (on a basis determined by the Company in good faith to preserve economic value for the Executive).
(B) Extinguished or Converted at Merger. If the Change in Control following the Disaggregation is a Merger, and if so provided in the agreement pursuant to which the Merger is effected, then all of Executive’s Restricted Stock that was not extinguished or converted to restricted stock of the Disaggregated Entity or an affiliate shall (I) be extinguished immediately prior to the Change in Control for such consideration as is provided for Restricted Stock of peer executives employed by the Company or an Affiliate, or (II) be converted into restricted stock of the Merger Survivor or an affiliate thereof, and such converted restricted stock will continue to vest during the Post-Disaggregation Period prior to the Termination Date.
(C) Restricted Stock after the Disaggregation. Executive’s unextinguished Restricted Stock, whether or not converted to restricted
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stock of the Disaggregated Entity or Merger Survivor, will continue to vest during the Post-Disaggregation Period, subject to Section 4.3(d).
Article III.
Termination of Employment
3.1 Disability.
(a) During the Agreement Term, the Employer (or, if applicable, the Disaggregated Entity) may terminate Executive’s employment at any time because of Executive’s Disability by giving Executive or his legal representative, as applicable, (i) written notice in accordance with Section 10.8 of the Company’s intention to terminate Executive’s employment pursuant to this Section and (ii) a certification of Executive’s Disability by a physician selected by the Employer or its insurers, subject to the reasonable consent of Executive or Executive’s legal representative, which consent shall not be unreasonably withheld or delayed. Executive’s employment shall terminate effective on the 30th day after Executive’s receipt of such notice (which such 30th day shall be deemed to be the “Disability Effective Date”) unless, before such 30th day, Executive shall have resumed the full-time performance of Executive’s duties.
(b) “Disability” means any medically determinable physical or mental impairment that has lasted for a continuous period of not less than six months and can be expected to be permanent or of indefinite duration, and that renders Executive unable to perform the duties required under this Agreement.
3.2 Death. Executive’s employment shall terminate automatically upon Executive’s death during the Agreement Term.
3.3 Termination by the Company for Cause. During the Post-Change Period, Post-Disaggregation Period, Imminent Control Change Period or Post-Significant Acquisition Period, the Company may terminate Executive’s employment (or cause Executive’s employment to be terminated) for Cause solely in accordance with all of the substantive and procedural provisions of this Section 3.3.
(a) Definition of Cause. “Cause” means any one or more of the following:
(i) the refusal to perform or habitual neglect in the performance of the Executive’s duties or responsibilities, or of specific directives of the officer or other executive of the Company or any of its affiliates to whom the Executive reports which are not materially inconsistent with the scope and nature of the Executive’s employment duties and responsibilities;
(ii) an Executive’s willful or reckless commission of act(s) or omission(s) which have resulted in or are likely to result in, a material loss to, or material damage to the reputation of, the Company or any of its affiliates, or that compromise the safety of any employee or other person;
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(iii) the Executive’s commission of a felony or any crime involving dishonesty or moral turpitude;
(iv) an Executive’s material violation of the Company’s or any of its affiliates’ Code of Business Conduct (including the corporate policies referenced therein) which would constitute grounds for immediate termination of employment, or of any statutory or common-law duty of loyalty to the Company or any of its affiliates; or
(v) any breach by the Executive of any one or more of the Restrictive Covenants.
For purposes of this Section, no act, or failure to act, on the part of the Executive shall be considered “willful” unless it is done, or omitted to be done, by the Executive in bad faith or without reasonable belief that the Executive’s action or omission was in the best interests of the Company. Any act, or failure to act, based upon authority given pursuant to a resolution duly adopted by the Board or upon the instructions of the chief executive officer or a senior officer of the Company other than Executive or based upon the advice of counsel for the Company shall be conclusively presumed to be done, or omitted to be done, by the Executive in good faith and in the best interests of the Company.
(b) Procedural Requirements for Termination for Cause During a Post-Change Period. The Executive’s Termination of Employment for which the Notice of Termination is given during a Post-Change Period shall not be deemed to be for Cause under this Section 3.3 unless and until there shall have been delivered to the Executive a copy of a resolution duly adopted by the affirmative vote of not less than 60% of the entire membership of the Board at a meeting of such Board called and held for such purpose (after reasonable written notice of such meeting is provided to the Executive and the Executive is given an opportunity, together with counsel, to be heard before the Board), finding that, in the good faith opinion of the Board, the Executive’s acts, or failure to act, constitutes Cause and specifying the particulars thereof in detail.
(c) Procedural Requirements for Termination for Cause During a Post-Disaggregation Period. In the event Executive’s Termination of Employment is from a Disaggregated Entity in a Post-Disaggregation Period, the procedural requirements for termination for Cause in this Section 3.3 shall be applied by substituting “Disaggregated Entity” for “Company,” “affiliate of the Disaggregated Entity” for “Affiliate,” and “Disaggregated Entity’s Board” for “Board.” Further, the Company shall have no obligation to provide payments or benefits under Section 4.3 if the Board determines that the Company could have terminated Executive’s employment for Cause if the Executive had been employed by the Company, such determination by the Board to be made as provided in Section 3.3(b) but applying the flush language at the end of Section 3.3(a) by substituting “Disaggregated Entity” for “Company” and “Disaggregated Entity’s Board” for “Board.”
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(d) Procedural Requirements for Termination for Cause During the Imminent Control Change Period or Post-Significant Acquisition Period. The Executive’s Termination of Employment for which the Notice of Termination is given during the Imminent Control Change Period or Post-Significant Acquisition Period shall not be deemed to be for Cause under this Section 3.3 unless and until there shall have been delivered to the Executive a copy of a resolution duly adopted by the affirmative vote of not less than a majority of the entire membership of the Board, finding that the Executive’s acts or failure to act, constitute Cause and specifying the particulars thereof in detail. Executive shall receive advance notice of such vote of the Board, but shall not have the right to appear in person or by counsel before the Board.
3.4 Termination by the Executive for Good Reason. During the Post-Change Period, an Imminent Control Change Period, a Post-Significant Acquisition Period or Post-Disaggregation Period, Executive may terminate his or her employment for Good Reason in accordance with the substantive and procedural provisions of this Section 3.4.
(a) Definition of Good Reason. For purposes of this Section 3.4, and subject to the provisions of subsections (b) through (e), “Good Reason” means the occurrence of any one or more of the following actions or omissions prior to the Termination Date during the Post-Change Period, the Imminent Control Change Period, the Post-Significant Acquisition Period or the Post-Disaggregation Period:
(i) a material reduction of the Executive’s salary, incentive compensation opportunity or aggregate benefits unless such reduction is part of a policy, program or arrangement applicable to peer executives (including peer executives of any successor to the Company);
(ii) a material adverse reduction in the Executive’s position, duties, or responsibilities, other than in a Post-Significant Acquisition period, and other than a change in the position or level of officer to whom the Executive reports or a change that is part of a policy, program or arrangement applicable to peer executives (including peer executives of any successor to the Company);
(iii) the failure of any successor to the Company to assume this Agreement;
(iv) a relocation (other than in a Post-Significant Acquisition Period), by more than 50 miles of (I) the Executive’s primary workplace, or (II) the principal offices of the Company or its successor (if such offices are the Executive’s workplace), in each case without Executive’s consent; provided, however, in both cases of (I) and (II) of this Section 3.4(a)(iv), such new location is farther from Executive’s residence then the prior location; or
(v) a material breach of this Agreement by the Company or its successor;
provided that the occurrence of a Disaggregation shall not be Good Reason if the Executive retains substantially the same position (determined without regard to
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reporting requirements) with the Disaggregated Entity, with substantially the same compensation and benefits in the aggregate, as immediately prior to such Disaggregation, notwithstanding Sections 3.4(a)(i), 3.4(a)(ii) and 3.4(a)(v).
(b) Application of “Good Reason” Definition During the Imminent Control Change Period. During the Imminent Control Change Period, “Good Reason” shall not include the events or conditions described in Section 3.4(a)(i), 3.4(a)(ii) or 3.4(a)(iv) unless the Imminent Control Change Period culminates in a Change Date. Further, if Executive’s Termination of Employment occurs during an Imminent Control Change Period that culminates in a Change Date, then, except as provided in Section 3.4(c), the definition of “Good Reason” shall be applied as though Sections 2.1, 2.6, 2.7, and 2.8 were applicable during the Imminent Control Change Period prior to the Executive’s Termination of Employment.
(c) Special Conditions Relating to Good Reason During the Post-Disaggregation Period. If Executive retains substantially the same position with the Disaggregated Entity as immediately prior to the Disaggregation (determined without regard to reporting requirements), then (1) Section 3.4(a)(ii) shall apply only with respect to the Executive’s position, duties or responsibilities as in effect at the Disaggregated Entity on the day following the Disaggregation, (2) subsection 3.4(a)(iv) shall apply only with respect to relocations required more than 60 days after the Disaggregation and shall be applied by substituting “Disaggregated Entity” for “any successor to the Company”, and (3) all references in Section 3.4 to the Company or its successor shall be to the Disaggregated Entity or its successor.
(d) Limitations on Good Reason. Notwithstanding the foregoing provisions of this Section 3.4, no act or omission shall constitute a material breach of this Agreement by the Company, nor grounds for “Good Reason”:
(i) unless the Executive gives the Company a Notice of Termination at least 30 days’ prior to the Termination Date and the Company fails to cure such act or omission within the 30-day period;
(ii) if the Executive first acquired knowledge of such act or omission more than 180 days before the Executive gives the Company and the Employer such Notice of Termination; or
(iii) if the Executive has consented in writing to such act or omission.
(e) Notice by Executive. In the event of any Termination of Employment by Executive for Good Reason, Executive shall as soon as practicable thereafter notify the Company and the Employer (and Disaggregated Entity, if applicable) of the events constituting such Good Reason by a Notice of Termination. Subject to the limitations in Section 3.4(d), a delay in the delivery of such Notice of Termination shall not waive any right of Executive under this Agreement.
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Article IV.
Company’s Obligations Upon Certain Terminations of Employment
4.1 Termination During the Post-Change Period or Post-Significant Acquisition Period. If, during the Post-Change Period or Post-Significant Acquisition Period (other than any portion of any of such periods that are also a Post-Disaggregation Period), the Employer terminates Executive’s employment other than for Cause or Disability, or Executive terminates employment for Good Reason, the Company’s sole obligations to Executive under Articles II and IV shall be as set forth in this Section 4.1.
(a) Termination during the Post-Change Period or Post-Significant Acquisition Period: Severance Payments. The Company shall pay or provide Executive, according to the payment terms set forth in Section 4.4 below, the following:
(i) Accrued Obligations. All Accrued Obligations;
(ii) Annual Incentive for Year of Termination and Special Payment. An amount equal to the Target Incentive applicable to the Executive under the Incentive Plan for the performance period in which the Termination Date occurs.
(iii) Deferred Compensation and Non-Qualified Defined Contribution Plans. All amounts previously deferred by, or accrued to the benefit of, Executive under the Exelon Corporation Deferred Compensation Plan, the Exelon Corporation Deferred Stock Plan, or any successor of either of them, or under any non-qualified defined contribution or deferred compensation plan of the Company or an Affiliate (unless Executive has made an irrevocable election in writing, filed with the Company as of such date as counsel to the Company may deem to be required to avoid constructive receipt of, or other adverse tax consequences with respect to, such amounts) to have such amounts paid under the terms of the Exelon Corporation Deferred Compensation Plan or the Exelon Corporation Deferred Stock Plan, as applicable, or any successor of either (including any elections in effect thereunder)) whether vested or unvested, together with any accrued earnings thereon, to the extent that such amounts and earnings have not been previously paid by the Employer and are not provided under the terms of either such non-qualified plan;
(iv) Pension Enhancements. An amount equal to the positive difference, if any, between
(1) the lump sum value of Executive’s benefit under the SERP, calculated as if Executive had
(A) become fully vested in all benefits,
(B) accrued a number of years of service (for purposes of determining the Executive’s benefit credits, but not investment credits) that is two years greater than the number of years of
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service actually accrued by Executive as of the Termination Date and that includes the number of years of service credited to Executive pursuant to any other written agreement between the Company and the Executive, and
(C) received two-thirds of the severance benefits specified in Sections 4.1(a)(ii) and 4.1(a)(vi) as covered compensation in equal annual installments during the first two years of the Severance Period,
minus
(2) the aggregate amounts paid or payable to Executive under the SERP.
(v) Unvested Benefits Under Defined Benefit Plan. To the extent not paid pursuant to clause (iii) or (iv) of this Section 4.1(a), an amount equal to the actuarial equivalent present value of any unvested portion of Executive’s accrued benefits or cash balance account (as applicable) under any tax-qualified (under Section 401(a) of the Code) defined benefit retirement plan maintained by the Employer as of the Termination Date and forfeited by Executive by reason of the Termination of Employment; and
(vi) Multiple of Salary and Severance Incentive. An amount equal to three (3.0) times the sum of (x) Base Salary plus (y) the Severance Incentive.
(b) Termination during the Post-Change Period or Post-Significant Acquisition Period: Stock Options. Each of the Executive’s stock options, stock appreciation rights or similar incentive awards granted under the LTIP (“Stock Options”) shall (i) become fully vested, and (ii) remain exercisable until (1) the option expiration date for any such Stock Options granted prior to January 1, 2002 or (2) the fifth anniversary of the Termination Date or, if earlier, the option expiration date for any such Stock Options granted on or after January 1, 2002.
(c) Termination during the Post-Change Period or Post-Significant Acquisition Period: LTIP Vesting. On the Termination Date all of the performance shares, performance units or similar stock incentive awards granted to the Executive under the Exelon Performance Share Program under the LTIP (“Performance Shares”) to the extent earned by and awarded to the Executive (i.e. as to which the applicable performance cycle has elapsed) as of the Termination Date, shall become fully vested at the actual level earned and awarded, and, to the extent not yet earned by and awarded to the Executive (i.e. as to which the current performance cycle has not elapsed) as of the Termination Date, shall become fully vested at the LTIP Target Level.
(d) Termination During the Post-Change Period or Post-Significant Acquisition Period: Other Restricted Stock. All forfeiture conditions that as of the Termination Date are applicable to any deferred stock unit, restricted stock or restricted share units awarded to the Executive by the Company other than under the Exelon
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Performance Share Program under the LTIP (“Restricted Stock”) shall (except as specifically provided to the contrary in the applicable awards) lapse immediately and all such awards will become fully vested, and within ten business days after the Termination Date, the Company shall deliver to Executive all of such shares theretofore held by or on behalf of the Company.
(e) Termination During the Post-Change Period or Post-Significant Acquisition Period: Continuation of Welfare Benefits. During the Severance Period (and continuing through such later date as any Welfare Plan may specify), the Company shall continue to provide (or shall cause the continued provision) to Executive and Executive’s family welfare benefits under the Welfare Plans to the same extent as if Executive had remained employed during the Severance Period. Such provision of welfare benefits shall be subject to the following:
(i) In determining benefits applicable under such Welfare Plans, the Executive’s annual compensation attributable to base salary and incentives for any plan year or calendar year, as applicable, shall be deemed to be not less than the Executive’s Base Salary and Annual Incentive.
(ii) The cost of such welfare benefits to Executive and family under this Section 4.1(e) shall not exceed the cost of such benefits to peer executives who are actively employed after the Termination Date.
(iii) The Executive’s rights under this Section 4.1(e) shall be in addition to and not in lieu of any post-termination continuation coverage or conversion rights the Executive may have pursuant to applicable law, including, without limitation, continuation coverage required by Section 4980B of the Code.
(iv) If the Executive has, as of the last day of the Severance Period, attained age 50 and completed at least 10 years of service (or any lesser age and service requirement then in effect under the Exelon Corporation Severance Benefit Plan or any successor plan), the Executive shall be entitled to the retiree benefits provided under any Welfare Plan of the Company; provided, however, that for purposes hereof, any years of credited services granted to the Executive in any other written plan or written agreement between Executive and the Company shall be taken into account. For purposes of determining eligibility for (but not the time of commencement of) such retiree benefits, the Executive shall also be considered (1) to have remained employed until the last day of the Severance Period and to have retired on the last day of such period, and (2) to have attained at least the age the Executive would have attained on the last day of the Severance Period.
Notwithstanding the foregoing, if the Executive obtains a specific type of coverage under welfare plan(s) sponsored by another employer of Executive (e.g. medical, prescription, vision, dental, disability, individual life insurance benefits, group life insurance benefits, but excluding for the purposes of this sentence retiree benefits if Executive is so eligible),
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then the Company shall not be obligated to provide any such specific type of coverage. The Executive shall promptly notify the Company of any such coverage.
(f) Termination during the Post-Change Period or Post-Significant Acquisition Period: Outplacement. To the extent actually incurred by Executive, the Company shall pay or cause to be paid on behalf of Executive, as incurred, all reasonable fees and costs charged by a nationally recognized outplacement firm selected by the Executive for outplacement services provided up to 12 months after the Termination Date. No cash shall be paid in lieu of such fees and costs.
(g) Termination during the Post-Change Period or Post-Significant Acquisition Period: Indemnification. The Executive shall be indemnified and held harmless by the Company to the greatest extent permitted under applicable law as the same now exists or may hereafter be amended (but, in the case of any such amendment, only to the extent that such amendment permits the Company to provide broader indemnification than was permitted prior to such amendment) and the Company’s by-laws as such exist on the Applicable Trigger Date if the Executive was, is, or is threatened to be, made a party to any pending, completed or threatened action, suit, arbitration, alternate dispute resolution mechanism, investigation, administrative hearing or any other proceeding brought by a third party (and not by or on behalf of the Company or its shareholders) whether civil, criminal, administrative or investigative, and whether formal or informal, by reason of the fact that the Executive is or was, or had agreed to become, a director, officer, employee, agent, or fiduciary of the Company or any other entity which the Executive is or was serving at the request of the Company (“Proceeding”), against all expenses (including all reasonable attorneys’ fees) and all claims, damages, liabilities and losses incurred or suffered by the Executive or to which the Executive may become subject for any reason; provided, that the Company shall not be required to indemnify the Executive in connection with any proceeding initiated by the Executive, including a counterclaim or cross claim, unless such proceeding was authorized by the Company. A Proceeding shall not include any proceeding to the extent it concerns or relates to a matter described in Section 6.1(a) (concerning reimbursement of certain costs and expenses). Upon receipt from Executive of (i) a written request for an advancement of expenses, which Executive reasonably believes will be subject to indemnification hereunder and (ii) a written undertaking by Executive to repay any such amounts if it shall ultimately be determined that Executive is not entitled to indemnification under this Agreement or otherwise, the Company shall, to the extent permitted by applicable law, advance such expenses to Executive or pay such expenses for Executive, all in advance of the final disposition of any such matter.
(h) Termination during the Post-Change Period or Post-Significant Acquisition Period: Directors’ and Officers’ Liability Insurance. For a period of six years after the Termination Date (or for any known longer applicable statute of limitations period), the Company shall provide Executive with coverage under a directors’ and officers’ liability insurance policy in an amount no less than, and on terms no less favorable than, those provided to senior executive officers and directors of the Company on the Applicable Trigger Date.
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4.2 Termination During an Imminent Control Change Period. If, during an Imminent Control Change Period, Executive has a Termination of Employment that would entitle Executive to benefits under Section 4 of the Exelon Corporation Senior Management Severance Plan or its successor, then the Company shall, prior to the occurrence of a Change Date, provide Executive any benefits to which Executive may be entitled under Section 4 of the Exelon Corporation Senior Management Severance Plan or its successor. If, during an Imminent Control Change Period, the Employer terminates Executive’s employment other than for Disability and other than for Cause, or if Executive terminates employment for Good Reason then subject to the preceding sentence, unless such Termination of Employment occurred during the Post-Significant Acquisition Period, the Company’s sole obligations to Executive under Articles II and IV shall be as set forth in this Section 4.2. The Company’s obligations to Executive under this Section 4.2 shall be reduced by any amounts or benefits paid or provided pursuant to the Exelon Corporation Senior Management Severance Plan (whether under Section 4 thereof or any other provision) or any successor thereto. If Executive’s Termination of Employment occurred during any portion of an Imminent Control Change Period that is also a Post-Significant Acquisition Period, the Company’s obligations to Executive, if any, shall be determined under Section 4.1.
(a) Termination During an Imminent Control Change Period: Cash Severance Payments. If the Imminent Control Change Period culminates in a Change Date, the Company shall pay (or cause to be paid) to Executive, a lump-sum cash amount, within thirty business days after the later of the Termination Date or the Change Date, equal to the sum of all amounts described in Section 4.1(a)(i) through (v). The amount described in Section 4.1(a)(vi) shall be paid to Executive as described in Section 4.4, provided that amounts that would have been paid prior to the Change Date shall be paid in a lump sum (without interest) within 30 business days after the Change Date.
(b) Termination During an Imminent Control Change Period: Vested Stock Options. Executive’s Stock Options, to the extent vested on the Termination Date,
(i) will not expire (unless such Stock Options would have expired had Executive remained an employee of the Company) during the Imminent Control Change Period; and
(ii) will continue to be exercisable after the Termination Date to the extent provided in the applicable grant agreement or Plan, and thereafter, such Stock Options shall not be exercisable during the Imminent Control Change Period.
If the Imminent Control Change Period lapses without a Change Date, then Executive’s Stock Options, to the extent vested on the Termination Date, may be exercised, in whole or in part, during the 30-day period following the lapse of the Imminent Control Change Period, or, if longer, the period during which Executive’s vested Stock Options could otherwise be exercised under the terms of the applicable grant agreement or Plan, (but in no case shall any Stock Options remain exercisable after the date on which such Stock Options would have expired if Executive had remained an employee of the Company).
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If the Imminent Control Change Period culminates in a Change Date, then effective upon the Change Date, Executive’s Stock Options, to the extent vested on the Termination Date, may be exercised in whole or in part by the Executive at any time until (1) the option expiration date for such Stock Options granted prior to January 1, 2002 or (2) the earlier of the fifth anniversary of the Change Date or the option expiration date for such Stock Options granted on or after January 1, 2002.
(c) Termination During an Imminent Control Change Period: Unvested Stock Options. Executive’s Stock Options that are not vested on the Termination Date
(i) will not expire (unless such Stock Options would have expired had Executive remained an employee of the Company) during the Imminent Control Change Period; and
(ii) will not continue to vest and will not be exercisable during the Imminent Control Change Period after the expiration of the period for post-termination exercise under the terms of the applicable Stock Option Agreement.
If the Imminent Control Change lapses without a Change Date, such unvested Stock Options will thereupon expire.
If the Imminent Control Change culminates in a Change Date, then immediately prior to the Change Date, such unvested Stock Options shall become fully vested, and may thereupon be exercised in whole or in part by the Executive at any time until (1) the option expiration date for such Stock Options granted prior to January 1, 2002 or (2) the earlier of the fifth anniversary of the Change Date, or the option expiration date for such Stock Options granted on or after January 1, 2002.
(d) Termination During an Imminent Control Change Period: Performance Shares. Executive’s Performance Shares granted under the Exelon Performance Share Program under the LTIP will not be forfeited during the Imminent Control Change Period, and will not continue to vest during the Imminent Control Change Period. If the Imminent Control Change lapses without a Change Date, such Performance Shares shall be governed according to the terms of Section 4 of the Exelon Corporation Senior Management Severance Plan. If the Imminent Control Change Period culminates in a Change Date:
(1) All Performance Shares granted to the Executive under the Exelon Performance Share Program under the LTIP, which, as of the Termination Date, have been earned by and awarded to the Executive, shall become fully vested at the actual earned level on the Change Date, and
(2) All of the Performance Shares granted to the Executive under the Exelon Performance Share Program under the LTIP which, as of the Termination Date, have not been earned by and awarded to the Executive shall become fully vested on the Change Date at the LTIP Target Level.
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(e) Termination During an Imminent Control Change Period: Restricted Stock. Executive’s unvested Restricted Stock will:
(i) not be forfeited during the Imminent Control Change Period; and
(ii) not continue to vest during the Imminent Control Change Period.
If the Imminent Control Change Period lapses without a Change Date, such unvested Restricted Stock shall thereupon be forfeited.
If the Imminent Control Change Period culminates in a Change Date, then immediately prior to the Change Date, Executive’s Restricted Stock shall (except as specifically provided to the contrary in the award) become fully vested, and within ten business days after the Change Date, the Company shall deliver to Executive all of such shares theretofore held by or on behalf of the Company, which will be subject to the same terms which other stockholders of the Company receive in the transaction.
(f) Termination During an Imminent Control Change Period: Continuation of Welfare Benefits. The Company shall continue to provide to Executive and Executive’s family welfare benefits (other than any severance pay that may be considered a welfare benefit) during the Imminent Change Period which are at least as favorable as welfare benefits under the most favorable Welfare Plans of the Company applicable with respect to peer executives who are actively employed after the Termination Date and their families; subject to the following:
(i) In determining benefits applicable under such Welfare Plans, the Executive’s annual compensation attributable to base salary and incentives for any plan year or calendar year, as applicable, shall be deemed to be not less than the Executive’s Base Salary and Annual Incentive;
(ii) The cost of such welfare benefits to Executive and family under this Section 4.2(f) shall not exceed the cost of such benefits to peer executives who are actively employed after the Termination Date.
(iii) Executive’s rights under this Section 4.2(f) shall be in addition to and not in lieu of any post-termination continuation coverage or conversion rights the Executive may have pursuant to applicable law, including, without limitation, continuation coverage required by Section 4980B of the Code.
If the Imminent Control Change Period lapses without a Change Date, welfare benefit plan coverage under this Section 4.2(f) shall thereupon cease, subject to Executive’s rights, if any, to continued coverage under a Welfare Plan, Section 4 of the Exelon Corporation Senior Management Severance Plan, or applicable law. If the Imminent Control Change Period culminates in a Change Date, then for the remainder of the Severance Period (and continuing through such later date as any Welfare Plan may specify), the Company shall continue to provide Executive and Executive’s family welfare benefits as described in, and subject to the limitations of Section 4.1(e).
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Notwithstanding the foregoing, if the Executive obtains a specific type of coverage under welfare plan(s) sponsored by another employer of Executive (e.g. medical, prescription, vision, dental, disability, individual life insurance benefits, group life insurance benefits, but excluding for the purposes of this sentence retiree benefits if Executive is so eligible), then the Company shall not be obligated to provide such any specific type of coverage. The Executive shall immediately notify the Company of any such coverage.
(g) Termination During an Imminent Control Change Period: Outplacement. To the extent actually incurred by Executive, the Company shall pay or cause to be paid on behalf of Executive, as incurred, all reasonable fees and costs charged by a nationally recognized outplacement firm selected by the Executive for outplacement services provided up to 12 months after the Termination Date. No cash shall be paid in lieu of such fees and costs.
(h) Termination During an Imminent Control Change Period: Indemnification. The Executive shall be indemnified and held harmless by the Company to the same extent as provided in Section 4.1(g), but only during the Imminent Control Change Period (or greater period provided under the Company’s by-laws) if the Imminent Control Change Period lapses without a Change Date.
(i) Termination During an Imminent Control Change Period: Directors’ and Officers’ Liability Insurance. The Company shall provide the same level of directors’ and officers’ liability insurance for Executive as provided in Section 4.1(h), but only during the Imminent Control Change Period (or greater period provided under the Company’s by-laws) if the Imminent Control Change Period lapses without a Change Date.
4.3 Termination During a Post-Disaggregation Period. If, during a Post-Disaggregation Period the Disaggregated Entity terminates Executive’s employment other than for Cause or Disability, or if Executive terminates employment for Good Reason, the Company’s sole obligations to Executive under Articles II and IV shall be as set forth in this Section 4.3, subject to Section 3.3(c), but only to the extent not provided by the Disaggregated Entity.
(a) Termination During a Post-Disaggregation Period: Cash Severance Payments. The Company shall pay Executive the amounts described in Section 4.1(a), as provided in Section 4.4.
(b) Termination During a Post-Disaggregation Period: Stock Options. All of Executive’s Stock Options granted prior to the Disaggregation that have not expired, whether or not converted to options or stock of the Disaggregated Entity or Merger Survivor, shall be fully vested, and may be exercised in whole or in part by the Executive at any time until (1) the remaining option expiration date for such Stock Options granted prior to January 1, 2002 and (2) the earlier of the fifth anniversary of the Termination Date or the option expiration date for such Stock Options granted on or after January 1, 2002.
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(c) Termination During a Post-Disaggregation Period: Performance Shares. Executive’s Performance Shares granted prior to the Disaggregation, whether or not earned by and awarded to the Executive as of the Disaggregation, and whether or not converted to performance shares of the Disaggregated Entity or the Merger Survivor, shall become fully vested (at the earned level for Performance Shares earned and awarded, and at the target level for any converted performance shares not yet earned and awarded) on the Termination Date.
(d) Termination During a Post-Disaggregation Period: Restricted Stock. Executive’s unvested Restricted Stock, whether or not converted to restricted stock of the Disaggregated Entity or Merger Survivor, shall become fully vested on the Termination Date.
(e) Termination During a Post-Disaggregation Period: Continuation of Welfare Benefits. Until the end of the Severance Period, the Company shall continue to provide to Executive and Executive’s family welfare benefits with the same rights in relation to continuation coverage, status in relation to other employer benefits, scope and cost as described in Section 4.1(e); provided that, to the extent Executive is eligible for post-termination continuation coverage under the plans of the Disaggregated Entity, whether pursuant to Section 4980B of the Code or otherwise, the continued coverage required hereunder shall be provided under the plans of the Disaggregated Entity (and the Company shall reimburse the cost to Executive of such coverage).
(f) Termination During a Post-Disaggregation Period: Outplacement. To the extent actually incurred by Executive, the Company shall pay or cause to be paid on behalf of Executive, as incurred, all reasonable fees and costs charged by a nationally recognized outplacement firm selected by the Executive for outplacement services provided up to 12 months after the Termination Date. No cash shall be paid in lieu of such fees and costs.
(g) Termination During a Post-Disaggregation Period: Indemnification. The Executive shall be indemnified and held harmless by the Company to the same extent as provided in Section 4.1(g).
(h) Termination During a Post-Disaggregation Period: Directors’ and Officers’ Liability Insurance. The Company shall provide Executive with directors’ and officers’ liability insurance to the same extent as provided in Section 4.1(h).
4.4 Timing of Severance Payments. Unless otherwise specified herein, the amounts described in Sections 4.1(a)(i), (ii), (iii), (iv) and (v) shall, to the extent permissible without penalty under applicable tax law (other than Excise Taxes described in Section 5.1), be paid within 30 business days of the Termination Date and, to the extent such amounts can not be paid without such a penalty, such amounts shall be paid at the relevant time or times payment becomes permissible under such law. The severance payments described in Section 4.1(a)(vi) shall be paid as follows:
(a) Beginning no later than the second paydate which occurs after the Termination Date, the Company shall make periodic payments to the Executive according to the Company’s normal payroll practices at a monthly rate equal to 1/12 of the sum of (i) the Executive’s Base Salary in effect as of the Termination Date plus (ii) the Severance Incentive; and
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(b) Within 30 business days of the second anniversary of the Termination Date, the Company shall pay Executive a cash lump sum equal to the difference between the total Severance Payment less the total amount paid pursuant to normal payroll practices under Section 4.4(a).
4.5 Waiver and Release. Notwithstanding anything herein to the contrary, the Company shall have no obligation to Executive under Article IV or Article V unless and until Executive executes a release and waiver of Company and its Affiliates, in substantially the same form as attached hereto as Exhibit A, or as otherwise mutually acceptable.
4.6 Breach of Covenants. If a court determines that Executive has breached any non-competition, non-solicitation, confidential information or intellectual property covenant entered into between Executive and Company, the Company shall not be obligated to pay or provide any severance or benefits under Articles IV or V, all unexercised Stock Options shall terminate as of the date of the breach, and all Restricted Stock shall be forfeited as of the date of the breach.
4.7 Termination by the Company for Cause. If the Company (or Affiliate or, if applicable, the Disaggregated Entity) terminates Executive’s employment for Cause during the Post-Change Period, the Imminent Control Change Period, the Post-Significant Acquisition Period, or the Post-Disaggregation Period, the Company’s sole obligation to Executive under Articles II, IV, and V shall be to pay Executive, pursuant to the Company’s then-effective Plans, a lump-sum cash amount equal to all Accrued Obligations determined as of the Termination Date. The remaining applicable provisions of this Agreement (including the restrictive covenants in Article VIII) shall continue to apply.
4.8 Termination by Executive Other Than for Good Reason. If Executive elects to retire or otherwise terminate employment during the Post-Change Period, the Imminent Control Change Period, the Post-Significant Acquisition Period, or the Post-Disaggregation Period, other than for Good Reason, Disability or death, the Company’s sole obligation to Executive under Articles II, IV, and V shall be to pay Executive, pursuant to the Company’s then-effective Plans, a lump-sum cash amount equal to all Accrued Obligations determined as of the Termination Date. The remaining provisions of this Agreement (including the restrictive covenants in Article VIII) shall continue to apply.
4.9 Termination by the Company for Disability. If the Company (or Disaggregated Entity, if applicable) terminates Executive’s employment by reason of Executive’s Disability during a Post-Change Period, Imminent Control Change Period that culminates in a Change Date, Post-Significant Acquisition Period or Post-Disaggregation Period, the Company’s sole obligation to Executive under Articles II, IV, and V shall be as follows, and such obligations shall be reduced by amounts paid or provided by the Disaggregated Entity:
(a) to pay Executive, a lump-sum cash amount equal to the sum of amounts specified in Section 4.1(a)(i), (ii) and (iii) determined as of the Termination Date, and
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(b) to provide Executive disability and other benefits after the Termination Date that are not less than the most favorable of such benefits then available under Plans of the Company to disabled peer executives of the Company in effect immediately before the Termination Date.
The remaining provisions of this Agreement (including the restrictive covenants in Article VIII) shall continue to apply.
4.10 Upon Death. If Executive’s employment is terminated by reason of Executive’s death during a Post-Change Period, Imminent Control Change Period that culminates in a Change Date, Post-Significant Acquisition Period or Post-Disaggregation Period, the Company’s sole obligations to Executive and Executive’s Beneficiary under Articles II, IV, and V shall be as follows, and such obligations shall be reduced by amounts paid or provided by the Disaggregated Entity:
(a) to pay Executive’s Beneficiary, pursuant to the Company’s then-effective Plans, a lump-sum cash amount equal to all Accrued Obligations; and
(b) to provide Executive’s Beneficiary survivor and other benefits that are not less than the most favorable of such benefits then available under Plans of the Company to surviving families of peer executives of the Company in effect immediately before the Executive’s death, including retiree health care coverage under any Welfare Plan of the Company that provides such coverage without regard to whether the Executive had satisfied the eligibility requirements for such coverage as of the date of his death.
4.11 Sole and Exclusive Obligations. The obligations of the Company under this Agreement with respect to any Termination of Employment of the Executive during the Post-Change Period, Imminent Control Change Period, Post-Significant Acquisition Period, or Post-Disaggregation Period shall, except as provided in Section 4.2, supersede any severance obligations of the Company in any other plan of the Company or agreement between Executive and the Company, including, without limitations, the Exelon Corporation Senior Management Severance Plan under Section 4 or any other provision thereof, or any other plan or agreement (including an offer of employment or employment contract) of the Company or any Affiliates which provides for severance benefits. In the event of any inconsistency, ambiguity or conflict between the terms of such other plan of the Company or agreement between Executive and the Company and this Agreement with respect to any severance obligations of the Company (other than obligations with respect to credited service under the SERP in any agreement other than a prior Change in Control Agreement entered into by and among Executive, Unicom Corporation, Commonwealth Edison Company or PECO Energy Company), this Agreement shall govern.
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Article V.
Certain Additional Payments by the Company
5.1 Gross-Up Payment. If at any time or from time to time, it shall be determined by the Company’s independent auditors that any payment or other benefit to Executive pursuant to Article II or Article IV of this Agreement or otherwise (“Potential Parachute Payment”) is or will become subject to the excise tax imposed by Section 4999 of the Code or any similar tax payable under any United States federal, state, local, foreign or other law (“Excise Taxes”), then the Company shall, subject to Section 5.2, pay or cause to be paid a tax gross-up payment (“Gross-Up Payment”) with respect to all such Excise Taxes and other Taxes on the Gross-Up Payment. The Gross-Up Payment shall be an amount equal to the product of
(a) The amount of the Excise Taxes (calculated at the effective marginal rates of all federal, state, local, foreign or other law),
multiplied by
(b) A fraction (the “Gross-Up Multiple”), the numerator or which is one (1.0), and the denominator of which is one (1.0) minus the lesser of (i) the sum, expressed as a decimal fraction, of the effective marginal rates of any Taxes and any Excise Taxes applicable to the Gross-Up Payment or (ii) .80, it being intended that the Gross-Up Multiple shall in no event exceed five (5.0). If different rates of tax are applicable to various portions of a Gross-Up Payment, the weighted average of such rates shall be used. For purposes of this Section, Executive shall be deemed to be subject to the highest effective marginal rate of Taxes.
The Gross-Up Payment is intended to compensate Executive for all such Excise Taxes and any other Taxes payable by Executive with respect to the Gross-Up Payment. The Company shall pay or cause to be paid the Gross–Up Payment to Executive within thirty (30) days of the calculation of such amount, but in no event after the Executive makes payment to the IRS of such Excise Taxes.
5.2 Limitation on Gross-Up Payments.
(a) To the extent possible, any payments or other benefits to Executive pursuant to Article II and Article IV of this Agreement shall be allocated as consideration for Executive’s entry into the covenants of Article VIII.
(b) Notwithstanding any other provision of this Article V, if the aggregate amount of the Potential Parachute Payments that, but for this Section 5.2, would be payable to Executive, does not exceed 110% of Floor Amount (as defined below), then no Gross-Up Payment shall be made to Executive and the aggregate amount of Potential Parachute Payments payable to Executive shall be reduced (but not below the Floor Amount) to the largest amount which would both (i) not cause any Excise Tax to be payable by Executive and (ii) not cause any Potential Parachute Payments to become
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nondeductible by the Company by reason of Section 280G of the Code (or any successor provision). For purposes of the preceding sentence, “Floor Amount” means the greatest pre-tax amount of Potential Parachute Payments that could be paid to Executive without causing Executive to become liable for any Excise Taxes in connection therewith.
5.3 Additional Gross-up Amounts. If, for any reason (whether pursuant to subsequently enacted provisions of the Code, final regulations or published rulings of the IRS, or a final judgment of a court of competent jurisdiction) the Company’s independent auditors later determine that the amount of Excise Taxes payable by Executive is greater than the amount initially determined pursuant to Section 5.1, then the Company shall, subject to Sections 5.2 and 5.4, pay Executive, within thirty (30) days of such determination, or pay to the IRS as required by applicable law, an amount (which shall also be deemed a Gross-Up Payment) equal to the product of:
(a) the sum of (i) such additional Excise Taxes and (ii) any interest, penalties, expenses or other costs incurred by Executive as a result of having taken a position in accordance with a determination made pursuant to Section 5.1 or 5.4,
multiplied by
(b) the Gross-Up Multiple.
5.4 Amount Increased or Contested.
(a) Executive shall notify the Company in writing (an “Executive’s Notice”) of any claim by the IRS or other taxing authority (an “IRS Claim”) that, if successful, would require the payment by Executive of Excise Taxes in respect of Potential Parachute Payments in an amount in excess of the amount of such Excise Taxes determined in accordance with Section 5.1. Executive’s Notice shall include the nature and amount of such IRS Claim, the date on which such IRS Claim is due to be paid (the “IRS Claim Deadline”), and a copy of all notices and other documents or correspondence received by Executive in respect of such IRS Claim. Executive shall give the Executive’s Notice as soon as practicable, but no later than the earlier of (i) 10 days after Executive first obtains actual knowledge of such IRS Claim or (ii) five days before the IRS Claim Deadline; provided, however, that any failure to give such Executive’s Notice shall affect the Company’s obligations under this Article only to the extent that the Company is actually prejudiced by such failure. If at least one business day before the IRS Claim Deadline the Company shall:
(i) deliver to Executive a written certificate from the Company’s independent auditors (“Company Certificate”) to the effect that, notwithstanding the IRS Claim, the amount of Excise Taxes, interest or penalties payable by Executive is either zero or an amount less than the amount specified in the IRS Claim,
(ii) pay to Executive, or to the IRS as required by applicable law, an amount (which shall also be deemed a Gross-Up Payment) equal to difference
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between the product of (A) amount of Excise Taxes, interest and penalties specified in the Company Certificate, if any, multiplied by (B) the Gross-Up Multiple, less the portion of such product, if any, previously paid to Executive by the Company, and
(iii) direct Executive pursuant to Section 5.4(d) to contest the balance of the IRS Claim,
then Executive shall pay only the amount, if any, of Excise Taxes, interest and penalties specified in the Company Certificate. In no event shall Executive pay an IRS Claim earlier than 30 business days after having given an Executive’s Notice to the Company (or, if sooner, the IRS Claim Deadline).
(b) At any time after the payment by Executive of any amount of Excise Taxes, other Taxes or related interest or penalties in respect of Potential Parachute Payments (including any such amount equal to or less than the amount of such Excise Taxes specified in any Company Certificate, or IRS Claim), the Company may in its discretion require Executive to pursue a claim for a refund (a “Refund Claim”) of all or any portion of such Excise Taxes, other Taxes, interest or penalties as may be specified by the Company in a written notice to Executive.
(c) If the Company notifies Executive in writing that the Company desires Executive to contest an IRS Claim or to pursue a Refund Claim, Executive shall:
(i) give the Company all information that it reasonably requests in writing from time to time relating to such IRS Claim or Refund Claim, as applicable,
(ii) take such action in connection with such IRS Claim or Refund Claim (as applicable) as the Company reasonably requests in writing from time to time, including accepting legal representation with respect thereto by an attorney selected by the Company, subject to the approval of Executive (which approval shall not be unreasonably withheld or delayed),
(iii) cooperate with the Company in good faith to contest such IRS Claim or pursue such Refund Claim, as applicable,
(iv) permit the Company to participate in any proceedings relating to such IRS Claim or Refund Claim, as applicable, and
(v) contest such IRS Claim or prosecute Refund Claim (as applicable) to a determination before any administrative tribunal, in a court of initial jurisdiction and in one or more appellate courts, as the Company may from time to time determine in its discretion.
The Company shall control all proceedings in connection with such IRS Claim or Refund Claim (as applicable) and in its discretion may cause Executive to pursue or forego any and all administrative appeals, proceedings, hearings and conferences with the Internal
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| Revenue Service or other taxing authority in respect of such IRS Claim or Refund Claim (as applicable); provided that (i) any extension of the statute of limitations relating to payment of taxes for the taxable year of Executive relating to the IRS Claim is limited solely to such IRS Claim, (ii) the Company’s control of the IRS Claim or Refund Claim (as applicable) shall be limited to issues with respect to which a Gross-Up Payment would be payable, and (iii) Executive shall be entitled to settle or contest, as the case may be, any other issue raised by the Internal Revenue Service or other taxing authority. |
(d) The Company may at any time in its discretion direct Executive to (i) contest the IRS Claim in any lawful manner or (ii) pay the amount specified in an IRS Claim and pursue a Refund Claim; provided, however, that if the Company directs Executive to pay an IRS Claim and pursue a Refund Claim, the Company shall advance the amount of such payment to Executive on an interest-free basis and shall indemnify Executive, on an after-tax basis, for any Excise Tax or income tax, including related interest or penalties, imposed with respect to such advance.
(e) The Company shall pay directly all legal, accounting and other costs and expenses (including additional interest and penalties) incurred by the Company or Executive in connection with any IRS Claim or Refund Claim, as applicable, and shall indemnify Executive, on an after-tax basis, for any Excise Tax or income tax, including related interest and penalties, imposed as a result of such payment of costs and expenses.
5.5 Refunds. If, after the receipt by Executive or the IRS of any payment or advance of Excise Taxes or other Taxes by the Company pursuant to this Article, Executive receives any refund with respect to such Excise Taxes, Executive shall (subject to the Company’s complying with any applicable requirements of Section 5.4) promptly pay the Company the amount of such refund (together with any interest paid or credited thereon after taxes applicable thereto). If, after the receipt by Executive of an amount advanced by the Company pursuant to Section 5.4 or receipt by the IRS of an amount paid by the Company on behalf of the Executive pursuant to Section 5.4, a determination is made that Executive shall not be entitled to any refund with respect to such claim and the Company does not notify Executive in writing of its intent to contest such determination within 30 days after the Company receives written notice of such determination, then such advance shall be forgiven and shall not be required to be repaid and the amount of such advance shall offset, to the extent thereof, the amount of Gross-Up Payment required to be paid. Any contest of a denial of refund shall be controlled by Section 5.4(d).
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Article VI.
Expenses, Interest and Dispute Resolution
6.1 Enforcement and Late Payments.
(a) If, after the Agreement Date, Executive incurs reasonable legal fees or other expenses (including arbitration costs and expenses under Section 6.3) in an effort to secure, preserve, or obtain benefits under this Agreement, the Company shall, regardless of the outcome of such effort, reimburse Executive (in accordance with Section 6.1(b)) for such fees and expenses.
(b) Reimbursement of legal fees and expenses and gross-up payments shall be made on a current basis, promptly after Executive’s written submission of a request for reimbursement together with evidence that such fees and expenses were incurred.
(c) If Executive does not prevail (after exhaustion of all available judicial remedies) in respect of a claim by Executive or by the Company hereunder, and the Company establishes before a court of competent jurisdiction by clear and convincing evidence that Executive had no reasonable basis for Executive’s claim hereunder, or for Executive’s response to the Company’s claim hereunder, or that Executive acted in bad faith, no further reimbursement for legal fees and expenses shall be due to Executive in respect of such claim and Executive shall refund any amounts previously reimbursed hereunder with respect to such claim.
6.2 Interest. If the Company does not pay any cash amount due to Executive under this Agreement within three business days after such amount first became due and owing, interest shall accrue on such amount from the date it became due and owing until the date of payment at an annual rate equal to 200 basis points above the base commercial lending rate published in The Wall Street Journal in effect from time to time during the period of such nonpayment; provided that the Executive shall not be entitled to interest on any Gross Up Payment.
6.3 Arbitration. Any dispute, controversy or claim between the parties hereto arising out of or in connection with or relating to this Agreement (other than disputes related to Article V or to an alleged breach of the covenant contained in Article VIII) or any breach or alleged breach thereof, or any benefit or alleged benefit hereunder, shall be settled by arbitration in Chicago, Illinois, before an impartial arbitrator pursuant to the rules and regulations of the American Arbitration Association (“AAA”) pertaining to the arbitration of labor disputes. Either party may invoke the right to arbitration. The arbitrator shall be selected by means of the parties striking alternatively from a panel of seven arbitrators supplied by the Chicago office of AAA. The arbitrator shall have the authority to interpret and apply the provisions of this Agreement, consistent with Section 10.11 below. The decision of the arbitrator shall be final and binding upon the parties and a judgment thereon may be entered in the highest court of a forum, state or federal, having jurisdiction. The expenses of the arbitration shall be borne according to Section 6.1.
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No arbitration shall be commenced after the date when institution of legal or equitable proceedings based upon such subject matter would be barred by the applicable statutes of limitations. Notwithstanding anything to the contrary contained in this Section 6.3 or elsewhere in this Agreement, either party may bring an action in the District Court of Cook County, or the United States District Court for the Northern District of Illinois, if jurisdiction there lies, in order to maintain the status quo ante of the parties. The “status quo ante” is defined as the last peaceable, uncontested status between the parties. However, neither the party bringing the action nor the party defending the action thereby waives its right to arbitration of any dispute, controversy or claim arising out of or in connection or relating to this Agreement. Notwithstanding anything to the contrary contained in this Section 6.3 or elsewhere in this Agreement, either party may seek relief in the form of specific performance, injunctive or other equitable relief in order to enforce the decision of the arbitrator. The parties agree that in any arbitration commenced pursuant to this Agreement, the parties shall be entitled to such discovery (including depositions, requests for the production of documents and interrogatories) as would be available in a federal district court pursuant to Rules 26 through 37 of the Federal Rules of Civil Procedure. In the event that either party fails to comply with its discovery obligations hereunder, the arbitrator shall have full power and authority to compel disclosure or impose sanctions to the full extent of Rule 37 of the Federal Rules of Civil Procedure.
Article VII.
No Set-off or Mitigation
7.1 No Set-off by Company. Executive’s right to receive when due the payments and other benefits provided for under this Agreement is absolute, unconditional and subject to no setoff, counterclaim or legal or equitable defense; provided, however that the Company shall have no further obligation to pay or provide severance benefits under Article II, Article IV or Article V if at any time it determines, in accordance with the procedural requirements in Section 3.3, that in the course of his employment the Executive engaged in conduct described in Section 3.3(a)(iii) or the last clause of Section 3.3(a)(iv). Time is of the essence in the performance by the Company of its obligations under this Agreement. Any claim which the Company may have against Executive, whether for a breach of this Agreement or otherwise, shall be brought in a separate action or proceeding and not as part of any action or proceeding brought by Executive to enforce any rights against the Company under this Agreement.
7.2 No Mitigation. Executive shall not have any duty to mitigate the amounts payable by the Company under this Agreement by seeking new employment or self-employment following termination. Except as specifically otherwise provided in this Agreement, all amounts payable pursuant to this Agreement shall be paid without reduction regardless of any amounts of salary, compensation or other amounts which may be paid or payable to Executive as the result of Executive’s employment by another unaffiliated employer or self-employment.
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Article VIII.
Restrictive Covenants
8.1 Confidential Information. The Executive acknowledges that in the course of performing services for the Companies and Affiliates, he may create (alone or with others), learn of, have access to and receive Confidential Information. Confidential Information shall not include: (i) information that is or becomes generally known through no fault of Executive; (ii) information received from a third party outside of the Company that was disclosed without a breach of any confidentiality obligation; or (iii) information approved for release by written authorization of the Company. The Executive recognizes that all such Confidential Information is the sole and exclusive property of the Company and its Affiliates or of third parties which the Company or Affiliate is obligated to keep confidential, that it is the Company’s policy to keep all such Confidential Information confidential, and that disclosure of Confidential Information would cause damage to the Company and its Affiliates. The Executive agrees that, except as required by the duties of Executive’s employment with the Company or any of its Affiliates and except in connection with enforcing the Executive’s rights under this Agreement or if compelled by a court or governmental agency, in each case provided that prior written notice is given to Company, Executive will not, without the written consent of Company, willfully disseminate or otherwise disclose, directly or indirectly, any Confidential Information obtained during his employment with the Company or its Affiliates, and will take all necessary precautions to prevent disclosure, to any unauthorized individual or entity inside or outside the Company, and will not use the Confidential Information or permit its use for the benefit of Executive or any other person or entity other than the Company or its Affiliates. These obligations shall continue during and after the termination of Executive’s employment (whether or not after a Change in Control, Imminent Control Change, Significant Acquisition or Disaggregation).
8.2 Non-Competition. During the period beginning on the Agreement Date and ending on the second anniversary of the Termination Date, whether or not after a Change in Control, Imminent Control Change, Significant Acquisition or Disaggregation, Executive hereby agrees that without the written consent of the Company Executive shall not at any time, directly or indirectly, in any capacity:
(a) engage or participate in, become employed by, serve as a director of, or render advisory or consulting or other services in connection with, any Competitive Business; provided, however, that after the Termination Date this Section 8.2 shall not preclude Executive from being an employee of, or consultant to, any business unit of a Competitive Business if (i) such business unit does not qualify as a Competitive Business in its own right and (ii) Executive does not have any direct or indirect involvement in, or responsibility for, any operations of such Competitive Business that cause it to qualify as a Competitive Business.
(b) make or retain any financial investment, whether in the form of equity or debt, or own any interest, in any Competitive Business. Nothing in this subsection shall, however, restrict Executive from making an investment in any Competitive Business if
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| such investment does not (i) represent more than 1% of the aggregate market value of the outstanding capital stock or debt (as applicable) of such Competitive Business, (ii) give Executive any right or ability, directly or indirectly, to control or influence the policy decisions or management of such Competitive Business, and (iii) create a conflict of interest between Executive’s duties under this Agreement and his interest in such investment. |
8.3 Non-Solicitation. During the period beginning on the Agreement Date and ending on the second anniversary of any Termination Date, whether or not after a Change in Control, Imminent Control Change, Significant Acquisition or Disaggregation, Executive shall not, directly or indirectly:
(a) other than in connection with the good-faith performance of his duties as an officer of the Company, cause or attempt to cause any employee or agent of the Company to terminate his or her relationship with the Company;
(b) employ, engage as a consultant or adviser, or solicit the employment or engagement as a consultant or adviser, of any employee or agent of the Company (other than by the Company or its Affiliates), or cause or attempt to cause any Person to do any of the foregoing;
(c) establish (or take preliminary steps to establish) a business with, or cause or attempt to cause others to establish (or take preliminary steps to establish) a business with, any employee or agent of the Company, if such business is or will be a Competitive Business; or
(d) interfere with the relationship of the Company with, or endeavor to entice away from the Company, any Person who or which at any time during the period commencing one year prior to the Termination Date was or is, to the Executive’s knowledge, a material customer or material supplier of, or maintained a material business relationship with, the Company.
8.4 Intellectual Property. During the period of Executive’s employment with the Company and any Affiliate, and thereafter upon the Company’s request, whether or not after a Change in Control, Imminent Control Change, Significant Acquisition or Disaggregation, Executive shall disclose immediately to the Company all ideas, inventions and business plans that he makes, conceives, discovers or develops alone or with others during the course of his employment with the Company or during the one year period following Executive’s Termination Date, including any inventions, modifications, discoveries, developments, improvements, computer programs, processes, products or procedures (whether or not protectable upon application by copyright, patent, trademark, trade secret or other proprietary rights) (“Work Product”) that: (i) relate to the business of the Company or any customer or supplier to the Company or any of the products or services being developed, manufactured, sold or otherwise provided by the Company or that may be used in relation therewith; or (ii) result from tasks assigned to Executive by the Company; or (iii) result from the use of the premises or personal property (whether tangible or intangible) owned, leased or contracted for by the Company. Executive agrees that any Work Product shall be the property of the Company and, if subject to
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copyright, shall be considered a “work made for hire” within the meaning of the Copyright Act of 1976, as amended (the “Act”). If and to the extent that any such Work Product is not a “work made for hire” within the meaning of the Act, Executive hereby assigns to the Company all right, title and interest in and to the Work Product, and all copies thereof, and the copyright, patent, trademark, trade secret and all proprietary rights in the Work Product, without further consideration, free from any claim, lien for balance due or rights of retention thereto on the part of Executive.
(a) The Company hereby notifies Executive that the preceding paragraph does not apply to any inventions for which no equipment, supplies, facility, or trade secret information of the Company was used and which was developed entirely on the Executive’s own time, unless: (i) the invention relates (a) to the Company’s business, or (b) to the Company’s actual or demonstrably anticipated research or development, or (ii) the invention results from any work performed by the Executive for the Company.
(b) Executive agrees that upon disclosure of Work Product to the Company, Executive will, during his employment and at any time thereafter, at the request and cost of the Company, execute all such documents and perform all such acts as the Company or its duly authorized agents may reasonably require: (i) to apply for, obtain and vest in the name of the Company alone (unless the Company otherwise directs) letters patent, copyrights or other analogous protection in any country throughout the world, and when so obtained or vested to renew and restore the same; and (ii) to prosecute or defend any opposition proceedings in respect of such applications and any opposition proceedings or petitions or applications for revocation of such letters patent, copyright or other analogous protection, or otherwise in respect of the Work Product.
(c) In the event that the Company is unable, after reasonable effort, to secure Executive’s execution as provided in subsection (b) above, whether because of Executive’s physical or mental incapacity or for any other reason whatsoever, Executive hereby irrevocably designates and appoints the Company and its duly authorized officers and agents as his agent and attorney-in-fact, to act for and on his behalf to execute and file any such application or applications and to do all other lawfully permitted acts to further the prosecution, issuance and protection of letters patent, copyright and other intellectual property protection with the same legal force and effect as if personally executed by Executive.
8.5 Reasonableness of Restrictive Covenants.
(a) Executive acknowledges that the covenants contained in Sections 8.1, 8.2, 8.3 and 8.4 are reasonable in the scope of the activities restricted, the geographic area covered by the restrictions, and the duration of the restrictions, and that such covenants are reasonably necessary to protect the Company’s legitimate interests in its Confidential Information and in its relationships with its employees, customers and suppliers. Executive further acknowledges such covenants are essential elements of this Agreement and that, but for such covenants, the Company would not have entered into this Agreement.
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(b) The Company and Executive have each consulted with their respective legal counsel and have been advised concerning the reasonableness and propriety of such covenants. Executive acknowledges that his observance of the covenants contained in Sections 8.1, 8.2, 8.3 and 8.4 will not deprive Executive of the ability to earn a livelihood or to support his dependents.
8.6 Right to Injunction; Survival of Undertakings.
(a) In recognition of the confidential nature of the Confidential Information, and in recognition of the necessity of the limited restrictions imposed by Sections 8.1, 8.2, 8.3 and 8.4 the parties agree that it would be impossible to measure solely in money the damages which the Company would suffer if Executive were to breach any of his obligations under such Sections. Executive acknowledges that any breach of any provision of such Sections would irreparably injure the Company. Accordingly, Executive agrees that if he breaches any of the provisions of such Sections, the Company shall be entitled, in addition to any other remedies to which the Company may be entitled under this Agreement or otherwise, to an injunction to be issued by a court of competent jurisdiction, to restrain any breach, or threatened breach, of such provisions, and Executive hereby waives any right to assert any claim or defense that the Company has an adequate remedy at law for any such breach.
(b) If a court determines that any of the covenants included in this Article VIII is unenforceable in whole or in part because of such covenant’s duration or geographical or other scope, such court shall have the power to modify the duration or scope of such provision, as the case may be, so as to cause such covenant as so modified to be enforceable.
(c) All of the provisions of this Article VIII shall survive any Termination of Employment without regard to (i) the reasons for such termination or (ii) the expiration of the Agreement Term.
(d) The Company shall have no further obligation to pay or provide severance or benefits under Article II, Article IV, or Article V if a court determines that the Executive has breached any covenant in this Article VIII.
Article IX.
Non-Exclusivity of Rights
9.1 Other Rights. Except as expressly provided in Section 4.11 or elsewhere in this Agreement, this Agreement shall not prevent or limit Executive’s continuing or future participation in any benefit, bonus, incentive or other Plans provided by the Company and for which Executive may qualify, nor shall this Agreement limit or otherwise affect such rights as Executive may have under any other agreements with the Company. Amounts which are vested benefits or which Executive is otherwise entitled to receive under any Plan and any other payment or benefit required by law at or after the Termination Date shall be payable in accordance with such Plan or applicable law except as expressly modified by this Agreement.
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9.2 No Right to Continued Employment. Nothing in this Agreement shall guarantee the right of Executive to continue in employment, and the Company retains the right to terminate the Executive’s employment at any time for any reason or for no reason.
Article X.
Miscellaneous
10.1 No Assignability. This Agreement is personal to Executive and without the prior written consent of the Company shall not be assignable by Executive otherwise than by will or the laws of descent and distribution. This Agreement shall inure to the benefit of and be enforceable by Executive’s legal representatives.
10.2 Successors. This Agreement shall inure to the benefit of and be binding upon the Company and its successors and assigns. The Company will require any successor (whether direct or indirect, by purchase, merger, consolidation or otherwise) to all or substantially all of the business or assets of the Company to assume expressly and agree to perform this Agreement in the same manner and to the same extent that the Company would be required to perform it if no such succession had taken place. Any successor to the business or assets of the Company which assumes or agrees to perform this Agreement by operation of law, contract, or otherwise shall be jointly and severally liable with the Company under this Agreement as if such successor were the Company.
10.3 Affiliates. To the extent that immediately prior to the Applicable Trigger Date, the Executive has been on the payroll of, and participated in the incentive or employee benefit plans of, an Affiliate of the Company, the references to the Company contained in Sections 2.8(a)(i) through (vii) and the other Sections of this Agreement referring to benefits to which the Executive may be entitled shall be read to refer to such Affiliate.
10.4 Payments to Beneficiary. If Executive dies before receiving amounts to which Executive is entitled under this Agreement, such amounts shall be paid in a lump sum to one or more beneficiaries designated in writing by Executive (each, a “Beneficiary”). If none is so designated, the Executive’s estate shall be his or her Beneficiary.
10.5 Non-Alienation of Benefits. Benefits payable under this Agreement shall not be subject in any manner to anticipation, alienation, sale, transfer, assignment, pledge, encumbrance, charge, garnishment, execution or levy of any kind, either voluntary or involuntary, before actually being received by Executive, and any such attempt to dispose of any right to benefits payable under this Agreement shall be void.
10.6 Severability. If any one or more Articles, Sections or other portions of this Agreement are declared by any court or governmental authority to be unlawful or invalid, such unlawfulness or invalidity shall not serve to invalidate any Article, Section or other portion not so declared to be unlawful or invalid. Any Article, Section or other portion so declared to be unlawful or invalid shall be construed so as to effectuate the terms of such Article, Section or other portion to the fullest extent possible while remaining lawful and valid.
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10.7 Amendments. This Agreement shall not be amended or modified except by written instrument executed by the Company and Executive; provided, that the Company may amend this Agreement to the extent counsel to the Company determines such amendment is necessary to comply with any regulations or other governmental guidance issued under the American Jobs Creation Act of 2004 relating to deferral of compensation.
10.8 Notices. All notices and other communications under this Agreement shall be in writing and delivered by hand, by nationally-recognized delivery service that promises overnight delivery, or by first-class registered or certified mail, return receipt requested, postage prepaid, addressed as follows:
If to Executive, to Executive at his most recent home address on file with the Company.
If to the Company:
Exelon Corporation
37th Floor
10 S. Dearborn Street
Chicago, Illinois 60603
Attention: S. Gary Snodgrass, Executive Vice President and Chief Human
Resources Officer
Facsimile No.: (312) 394-5440
With copy to:
Pamela Baker, Esq.
Sonnenschein Nath & Rosenthal
8000 Sears Tower
Chicago, Illinois 60606
Facsimile No.: (312) 876-7934
or to such other address as either party shall have furnished to the other in writing. Notice and communications shall be effective when actually received by the addressee.
10.9 Joint and Several Liability. The Company and the Subsidiary shall be jointly and severally liable for the obligations of the Company, the Subsidiary, or the Employer hereunder.
10.10 Counterparts. This Agreement may be executed in two or more counterparts, each of which shall be deemed an original, but all of which together constitute one and the same instrument.
10.11 Governing Law. This Agreement shall be interpreted and construed in accordance with the laws of the State of Illinois, without regard to its choice of law principles, and with the applicable provisions of the Code.
42
10.12 Captions. The captions of this Agreement are not a part of the provisions hereof and shall have no force or effect.
10.13 Number and Gender. Wherever appropriate, the singular shall include the plural, the plural shall include the singular, and the masculine shall include the feminine.
10.14 Tax Withholding. The Company may withhold from any amounts payable under this Agreement or otherwise payable to Executive any Taxes the Company determines to be appropriate under applicable law and may report all such amounts payable to such authority as is required by any applicable law or regulation.
10.15 No Waiver. Executive’s failure to insist upon strict compliance with any provision of this Agreement shall not be deemed a waiver of such provision or any other provision of this Agreement. A waiver of any provision of this Agreement shall not be deemed a waiver of any other provision, and any waiver of any default in any such provision shall not be deemed a waiver of any later default thereof or of any other provision.
10.16 Entire Agreement. This Agreement contains the entire understanding of Company and Executive with respect to its subject matter.
43
IN WITNESS WHEREOF, Executive and Exelon Corporation have executed this Change in Control Employment Agreement effective as of , 200 .
| EXECUTIVE | ||
| EXELON CORPORATION | ||
| By: | ||
| Title: |
||
44
Exhibit 10.51
FORM OF
EXELON CORPORATION
CHANGE IN CONTROL EMPLOYMENT AGREEMENT
AMENDED AND RESTATED AS OF MAY 1, 2004
Table of Contents
| ARTICLE I. DEFINITIONS |
1 | |||
| 1.1 |
“ACCRUED ANNUAL INCENTIVE” |
1 | ||
| 1.2 |
“ACCRUED BASE SALARY” |
1 | ||
| 1.3 |
“ACCRUED LTIP AWARD” |
1 | ||
| 1.4 |
“ACCRUED OBLIGATIONS” |
1 | ||
| 1.5 |
“AFFILIATE” |
1 | ||
| 1.6 |
“AGREEMENT DATE” |
2 | ||
| 1.7 |
“AGREEMENT TERM” |
2 | ||
| 1.8 |
“ANNUAL INCENTIVE” |
2 | ||
| 1.9 |
“APPLICABLE TRIGGER DATE” |
2 | ||
| 1.10 |
“ARTICLE” |
2 | ||
| 1.11 |
“BASE SALARY” |
2 | ||
| 1.12 |
“BENEFICIAL OWNER” |
2 | ||
| 1.13 |
“BENEFICIARY” |
2 | ||
| 1.14 |
“BOARD” |
3 | ||
| 1.15 |
“CAUSE” |
3 | ||
| 1.16 |
“CHANGE DATE” |
3 | ||
| 1.17 |
“CHANGE IN CONTROL” |
3 | ||
| 1.18 |
“CODE” |
4 | ||
| 1.19 |
“COMPANY” |
4 | ||
| 1.20 |
“COMPETITIVE BUSINESS” |
5 | ||
| 1.21 |
“CONFIDENTIAL INFORMATION” |
5 | ||
| 1.22 |
“DISABILITY” |
5 | ||
| 1.23 |
“DISAGGREGATED ENTITY” |
6 | ||
| 1.24 |
“DISAGGREGATION” |
6 | ||
| 1.25 |
“EMPLOYER” |
6 | ||
| 1.26 |
“EXCHANGE ACT” |
6 | ||
| 1.27 |
“GOOD REASON” |
6 | ||
| 1.28 |
“IMMINENT CONTROL CHANGE” |
6 | ||
| 1.29 |
“IMMINENT CONTROL CHANGE PERIOD” |
7 | ||
| 1.30 |
“INCENTIVE PLAN” |
7 | ||
| 1.31 |
“INCLUDING” |
7 | ||
| 1.32 |
“INCUMBENT BOARD” |
7 | ||
| 1.33 |
“IRS” |
7 | ||
| 1.34 |
“LTIP” |
7 | ||
| 1.35 |
“LTIP PERFORMANCE PERIOD” |
7 | ||
| 1.36 |
“LTIP TARGET LEVEL” |
8 | ||
| 1.37 |
“MERGER” |
8 | ||
| 1.38 |
“NOTICE OF TERMINATION” |
8 | ||
| 1.39 |
“PERFORMANCE SHARES” |
8 | ||
| 1.40 |
“PERSON” |
8 | ||
| 1.41 |
“PLANS” |
8 | ||
| 1.42 |
“POST-CHANGE PERIOD” |
8 | ||
| 1.43 |
“POST-DISAGGREGATION PERIOD” |
8 | ||
| 1.44 |
“POST-SIGNIFICANT ACQUISITION PERIOD” |
8 | ||
| 1.45 |
“RESTRICTED STOCK” |
8 | ||
| 1.46 |
“SEC” |
9 | ||
| 1.47 |
“SEC PERSON” |
9 | ||
| 1.48 |
“SECTION” |
9 | ||
| 1.49 |
“SERP” |
9 | ||
| 1.50 |
“SEVERANCE INCENTIVE” |
9 | ||
| 1.51 |
“SEVERANCE PERIOD” |
9 | ||
| 1.52 |
“SIGNIFICANT ACQUISITION” |
9 | ||
i
| 1.53 |
“STOCK OPTIONS” |
10 | ||
| 1.54 |
“TARGET INCENTIVE” |
10 | ||
| 1.55 |
“TAXES” |
10 | ||
| 1.56 |
“TERMINATION DATE” |
10 | ||
| 1.57 |
“TERMINATION OF EMPLOYMENT” |
10 | ||
| 1.58 |
“20% OWNER” |
10 | ||
| 1.59 |
“VOTING SECURITIES” |
10 | ||
| 1.60 |
“WELFARE PLANS” |
10 | ||
| ARTICLE II. TERMS OF EMPLOYMENT |
11 | |||
| 2.1 |
POSITION AND DUTIES DURING A POST-CHANGE PERIOD |
11 | ||
| 2.2 |
POSITION AND DUTIES DURING AN IMMINENT CONTROL CHANGE PERIOD |
11 | ||
| 2.3 |
POSITION AND DUTIES DURING A POST-SIGNIFICANT ACQUISITION PERIOD |
11 | ||
| 2.4 |
POSITION AND DUTIES DURING A POST-DISAGGREGATION PERIOD |
11 | ||
| 2.5 |
EXECUTIVE’S OBLIGATIONS |
11 | ||
| 2.6 |
BASE SALARY DURING THE POST-CHANGE PERIOD |
12 | ||
| 2.7 |
ANNUAL INCENTIVE |
12 | ||
| 2.8 |
OTHER COMPENSATION AND BENEFITS |
13 | ||
| ARTICLE III. TERMINATION OF EMPLOYMENT |
16 | |||
| 3.1 |
DISABILITY |
16 | ||
| 3.2 |
DEATH |
16 | ||
| 3.3 |
TERMINATION BY THE COMPANY FOR CAUSE |
16 | ||
| 3.4 |
TERMINATION BY THE EXECUTIVE FOR GOOD REASON |
18 | ||
| ARTICLE IV. COMPANY’S OBLIGATIONS UPON CERTAIN TERMINATIONS OF EMPLOYMENT |
20 | |||
| 4.1 |
TERMINATION DURING THE POST-CHANGE PERIOD OR POST-SIGNIFICANT ACQUISITION PERIOD |
20 | ||
| 4.2 |
TERMINATION DURING AN IMMINENT CONTROL CHANGE PERIOD |
24 | ||
| 4.3 |
TERMINATION DURING A POST-DISAGGREGATION PERIOD |
27 | ||
| 4.4 |
TIMING OF SEVERANCE PAYMENTS |
28 | ||
| 4.5 |
WAIVER AND RELEASE |
29 | ||
| 4.6 |
BREACH OF COVENANTS |
29 | ||
| 4.7 |
TERMINATION BY THE COMPANY FOR CAUSE |
29 | ||
| 4.8 |
TERMINATION BY EXECUTIVE OTHER THAN FOR GOOD REASON |
29 | ||
| 4.9 |
TERMINATION BY THE COMPANY FOR DISABILITY |
29 | ||
| 4.10 |
UPON DEATH |
30 | ||
| 4.11 |
SOLE AND EXCLUSIVE OBLIGATIONS |
30 | ||
| ARTICLE V. CERTAIN ADDITIONAL PAYMENTS BY THE COMPANY |
30 | |||
| 5.1 |
GROSS-UP PAYMENT |
30 | ||
| 5.2 |
LIMITATION ON GROSS-UP PAYMENTS |
31 | ||
| 5.3 |
ADDITIONAL GROSS-UP AMOUNTS |
31 | ||
| 5.4 |
AMOUNT INCREASED OR CONTESTED |
32 | ||
| 5.5 |
REFUNDS |
34 | ||
| ARTICLE VI. EXPENSES, INTEREST AND DISPUTE RESOLUTION |
35 | |||
| 6.1 |
ENFORCEMENT AND LATE PAYMENTS |
35 | ||
| 6.2 |
INTEREST |
35 | ||
| 6.3 |
ARBITRATION |
35 | ||
| ARTICLE VII. NO SET-OFF OR MITIGATION |
36 | |||
| 7.1 |
NO SET-OFF BY COMPANY |
36 | ||
| 7.2 |
NO MITIGATION |
36 | ||
| ARTICLE VIII. RESTRICTIVE COVENANTS |
37 | |||
| 8.1 |
CONFIDENTIAL INFORMATION |
37 | ||
ii
| 8.2 |
NON-COMPETITION |
37 | ||
| 8.3 |
NON-SOLICITATION |
38 | ||
| 8.4 |
INTELLECTUAL PROPERTY |
38 | ||
| 8.5 |
REASONABLENESS OF RESTRICTIVE COVENANTS |
39 | ||
| 8.6 |
RIGHT TO INJUNCTION; SURVIVAL OF UNDERTAKINGS |
40 | ||
| ARTICLE IX. NON-EXCLUSIVITY OF RIGHTS |
40 | |||
| 9.1 |
OTHER RIGHTS |
40 | ||
| 9.2 |
NO RIGHT TO CONTINUED EMPLOYMENT |
41 | ||
| ARTICLE X. MISCELLANEOUS |
41 | |||
| 10.1 |
NO ASSIGNABILITY |
41 | ||
| 10.2 |
SUCCESSORS |
41 | ||
| 10.3 |
AFFILIATES |
41 | ||
| 10.4 |
PAYMENTS TO BENEFICIARY |
41 | ||
| 10.5 |
NON-ALIENATION OF BENEFITS |
41 | ||
| 10.6 |
SEVERABILITY |
41 | ||
| 10.7 |
AMENDMENTS |
42 | ||
| 10.8 |
NOTICES |
42 | ||
| 10.9 |
JOINT AND SEVERAL LIABILITY |
42 | ||
| 10.10 |
COUNTERPARTS |
42 | ||
| 10.11 |
GOVERNING LAW |
42 | ||
| 10.12 |
CAPTIONS |
42 | ||
| 10.13 |
NUMBER AND GENDER |
42 | ||
| 10.14 |
TAX WITHHOLDING |
43 | ||
| 10.15 |
NO WAIVER |
43 | ||
| 10.16 |
ENTIRE AGREEMENT |
43 | ||
iii
EXELON CORPORATION
CHANGE-IN-CONTROL EMPLOYMENT AGREEMENT
THIS AGREEMENT, dated as of June 1, 2001 (the “Agreement Date”), is made by and among Exelon Corporation, incorporated under the laws of the Commonwealth of Pennsylvania (together with successors thereto, the “Company”), on behalf of itself and ________________________________, a Pennsylvania corporation (together with successors thereto, the “Subsidiary”), and _________________ (“Executive”). The Agreement has been amended and restated as of May 1, 2004.
RECITALS
The Board of Directors of the Company (the “Board”) has determined that it is in the best interests of the Company and its shareholders to assure that the Company will have the continued services of the Executive, despite the possibility or occurrence of a Change in Control of the Company. The Board believes it is imperative to reduce the distraction of the Executive that would result from the personal uncertainties caused by a pending or threatened Change in Control or a Significant Acquisition, to encourage the Executive’s full attention and dedication to the Company, and to provide the Executive with compensation and benefits arrangements upon a Change in Control which are competitive with those of similarly-situated corporations. This Agreement is intended to accomplish these objectives.
Article I.
Definitions
As used in this Agreement, the terms specified below shall have the following meanings:
1.1 “Accrued Annual Incentive” means the amount of any Annual Incentive earned but not yet paid with respect to the Company’s latest fiscal year ended prior to the Termination Date.
1.2 “Accrued Base Salary” means the amount of Executive’s Base Salary that is accrued but not yet paid as of the Termination Date.
1.3 “Accrued LTIP Award” means the amount of any LTIP Award earned and vested, but either deferred or not yet paid as of the Termination Date.
1.4 “Accrued Obligations” means, as of any date, the sum of Executive’s Accrued Base Salary, Accrued Annual Incentive, Accrued LTIP Award, any accrued but unpaid paid time off, and any other amounts and benefits which are then due to be paid or provided to Executive by the Company, but have not yet been paid or provided (as applicable).
1.5 “Affiliate” means any Person (including the Subsidiary) that directly or indirectly controls, is controlled by, or is under common control with, the Company. For purposes of this definition the term “control” with respect to any Person means the power to direct or cause the
direction of management or policies of such Person, directly or indirectly, whether through the ownership of Voting Securities, by contract or otherwise.
1.6 “Agreement Date” — see the introductory paragraph of this Agreement.
1.7 “Agreement Term” means the period commencing on the Agreement Date and ending on the second anniversary of the Agreement Date or, if later, such later date to which the Agreement Term is extended under the following sentence, unless earlier terminated as provided herein. Commencing on the first anniversary of the Agreement Date, the Agreement Term shall automatically be extended each day by one day to create a new two-year term until, at any time after the first anniversary of the Agreement Date, the Company delivers written notice (an “Expiration Notice”) to Executive that the Agreement shall expire on a date specified in the Expiration Notice (the “Expiration Date”) that is not less than 12 months after the date the Expiration Notice is delivered to Executive; provided, however, that if a Change Date, Imminent Control Change, Disaggregation or Significant Acquisition occurs before the Expiration Date specified in the Expiration Notice, then such Expiration Notice shall be void and of no further effect. If such Imminent Control Change or Disaggregation does not culminate in a Change Date, then such Expiration Notice shall be reinstated and the Agreement shall expire on the date originally specified as the Expiration Date, or if later, the date the Imminent Control Change lapses or the end of the sixtieth day after the Disaggregation. Notwithstanding anything herein to the contrary, the Agreement Term shall end at the end of the Severance Period if applicable, or if there is no Severance Period, the earliest of the following: (a) the second anniversary of the Change Date, (b) eighteen (18) months after the Significant Acquisition, provided there has been no Change Date, (c) the end of the sixtieth day after the Disaggregation if there has been no Change Date after the Disaggregation, or (d) the Termination Date.
1.8 “Annual Incentive” — see Section 2.7.
1.9 “Applicable Trigger Date” means
(a) the Change Date with respect to the Post-Change Period;
(b) the date of an Imminent Control Change with respect to the Imminent Control Change Period;
(c) the date of a Significant Acquisition with respect to a Post-Significant Acquisition Period; and
(d) the date of a Disaggregation with respect to a Post-Disaggregation Period.
1.10 “Article” means an article of this Agreement.
1.11 “Base Salary” — see Section 2.6.
1.12 “Beneficial Owner” means such term as defined in Rule 13d-3 of the SEC under the Exchange Act.
1.13 “Beneficiary” — see Section 10.4.
2
1.14 “Board” means the Board of Directors of Company or, from and after the effective date of a Corporate Transaction (as defined in Section 1.17), the Board of Directors of the corporation resulting from a Corporate Transaction or, if securities representing at least 50% of the aggregate voting power of such resulting corporation are directly or indirectly owned by another corporation, such other corporation.
1.15 “Cause” — see Section 3.3.
1.16 “Change Date” means the date on which a Change in Control first occurs during the Agreement Term.
1.17 “Change in Control” means, except as otherwise provided below, the first to occur of any of the following during the Agreement Term:
(a) any SEC Person becomes the Beneficial Owner of 20% or more of the then outstanding common stock of the Company or of Voting Securities representing 20% or more of the combined voting power of all the then outstanding Voting Securities of Company (such an SEC Person, a “20% Owner”); provided, however, that for purposes of this subsection (a), the following acquisitions shall not constitute a Change in Control: (1) any acquisition directly from the Company (excluding any acquisition resulting from the exercise of an exercise, conversion or exchange privilege unless the security being so exercised, converted or exchanged was acquired directly from the Company), (2) any acquisition by the Company, (3) any acquisition by an employee benefit plan (or related trust) sponsored or maintained by the Company or any corporation controlled by the Company (a “Company Plan”), or (4) any acquisition by any corporation pursuant to a transaction which complies with clauses (i), (ii) and (iii) of subsection (c) of this definition; provided further, that for purposes of clause (2), if any 20% Owner of the Company other than the Company or any Company Plan becomes a 20% Owner by reason of an acquisition by the Company, and such 20% Owner of the Company shall, after such acquisition by the Company, become the beneficial owner of any additional outstanding common shares of the Company or any additional outstanding Voting Securities of the Company (other than pursuant to any dividend reinvestment plan or arrangement maintained by the Company) and such beneficial ownership is publicly announced, such additional beneficial ownership shall constitute a Change in Control; or
(b) Individuals who, as of the date hereof, constitute the Board (the “Incumbent Board”) cease for any reason to constitute at least a majority of the Incumbent Board; provided, however, that any individual becoming a director subsequent to the date hereof whose election, or nomination for election by the Company’s shareholders, was approved by a vote of at least a majority of the directors then comprising the Incumbent Board shall be considered as though such individual were a member of the Incumbent Board, but excluding, for this purpose, any such individual whose initial assumption of office occurs as a result of an actual or threatened election contest (as such terms are used in Rule 14a-11 promulgated under the Exchange Act) or other actual or threatened solicitation of proxies or consents by or on behalf of a Person other than the Board; or
3
(c) Consummation of a reorganization, merger or consolidation (“Merger”), or the sale or other disposition of more than 50% of the operating assets of the Company (determined on a consolidated basis), other than in connection with a sale-leaseback or other arrangement resulting in the continued utilization of such assets (or the operating products of such assets) by the Company (such reorganization, merger, consolidation, sale or other disposition, a “Corporate Transaction”); excluding, however, a Corporate Transaction pursuant to which:
(i) all or substantially all of the individuals and entities who are the Beneficial Owners, respectively, of the outstanding common stock of Company and outstanding Voting Securities of the Company immediately prior to such Corporate Transaction beneficially own, directly or indirectly, more than 60% of, respectively, the then-outstanding shares of common stock and the combined voting power of the then-outstanding voting securities entitled to vote generally in the election of directors, as the case may be, of the corporation resulting from such Corporate Transaction (including, without limitation, a corporation which, as a result of such transaction, owns the Company or all or substantially all of the assets of the Company either directly or through one or more subsidiaries) in substantially the same proportions as their ownership immediately prior to such Corporate Transaction of the outstanding common stock of Company and outstanding Voting Securities of the Company, as the case may be;
(ii) no SEC Person (other than the corporation resulting from such Corporate Transaction, and any Person which beneficially owned, immediately prior to such corporate Transaction, directly or indirectly, 20% or more of the outstanding common stock of the Company or the outstanding Voting Securities of the Company, as the case may be) becomes a 20% Owner, directly or indirectly, of the then-outstanding common stock of the corporation resulting from such Corporate Transaction or the combined voting power of the outstanding voting securities of such corporation; and
(iii) individuals who were members of the Incumbent Board will constitute at least a majority of the members of the board of directors of the corporation resulting from such Corporate Transaction; or
(d) Approval by the Company’s shareholders of a plan of complete liquidation or dissolution of the Company, other than a plan of liquidation or dissolution which results in the acquisition of all or substantially all of the assets of the Company by an affiliated company.
Notwithstanding the occurrence of any of the foregoing events, a Change in Control shall not occur with respect to Executive if, in advance of such event, Executive agrees in writing that such event shall not constitute a Change in Control.
1.18 “Code” means the Internal Revenue Code of 1986, as amended.
1.19 “Company” – see the introductory paragraph to this Agreement.
4
1.20 “Competitive Business” means, as of any date, any utility business and any individual or entity (and any branch, office, or operation thereof) which engages in, or proposes to engage in (with Executive’s assistance) (i) the harnessing, production, transmission, distribution, marketing or sale of energy or the transmission or distribution thereof through wire or cable or similar medium, (ii) any other business engaged in by the Company prior to Executive’s Termination Date which represents for any calendar year or is projected by the Company (as reflected in a business plan adopted by the Company before Executive’s Termination Date) to yield during any year during the first three-fiscal year period commencing on or after Executive’s Termination Date, more than 5% of the gross revenue of Company, and, in either case, which is located (x) anywhere in the United States, or (y) anywhere outside of the United States where Company is then engaged in, or proposes as of the Termination Date to engage in to the knowledge of the Executive, any of such activities.
1.21 “Confidential Information” shall mean any information, ideas, processes, methods, designs, devices, inventions, data, techniques, models and other information developed or used by the Company or any Affiliate and not generally known in the relevant trade or industry relating to the Company’s or its Affiliates’ products, services, businesses, operations, employees, customers or suppliers, whether in tangible or intangible form, which gives the Company and its Affiliates a competitive advantage in the harnessing, production, transmission, distribution, marketing or sale of energy or the transmission or distribution thereof through wire or cable or similar medium or in the energy services industry and other businesses in which the Company or an Affiliate is engaged, or of third parties which the Company or Affiliate is obligated to keep confidential, or which was learned, discovered, developed, conceived, originated or prepared during or as a result of Executive’s performance of any services on behalf of the Company and which falls within any of the following general categories:
(a) information relating to trade secrets of the Company or Affiliate or any customer or supplier of the Company or Affiliate;
(b) information relating to existing or contemplated products, services, technology, designs, processes, formulae, algorithms, research or product developments of the Company or Affiliate or any customer or supplier of the Company or Affiliate;
(c) information relating to business plans or strategies, sales or marketing methods, methods of doing business, customer lists, customer usages and/or requirements, supplier information of the Company or Affiliate or any customer or supplier of the Company or Affiliate;
(d) information subject to protection under the Uniform Trade Secrets Act, as adopted by the State of Illinois, or to any comparable protection afforded by applicable law; or
(e) any other confidential information which either the Company or Affiliate or any customer or supplier of the Company or Affiliate may reasonably have the right to protect by patent, copyright or by keeping it secret and confidential.
1.22 “Disability” – see Section 3.1(b).
5
1.23 “Disaggregated Entity” means the Disaggregated Unit or any other Person (other than the Company or an Affiliate) that controls or is under common control with the Disaggregated Unit.
1.24 “Disaggregation” means the consummation, in contemplation of a Change in Control, of a sale, spin-off or other disaggregation by the Company or the Affiliate or business unit of the Company (“Disaggregated Unit”) which employed Executive immediately prior to the sale, spin-off or other disaggregation.
1.25 “Employer” means, collectively or severally, the Company and the Subsidiary (or other Affiliate employing Executive).
1.26 “Exchange Act” means the Securities Exchange Act of 1934, as amended.
1.27 “Good Reason” — see Section 3.4.
1.28 “Imminent Control Change” means, as of any date on or after the Agreement Date and prior to the Change Date, the occurrence of any one or more of the following:
(a) the Company enters into an agreement the consummation of which would constitute a Change in Control;
(b) Any SEC Person commences a “tender offer” (as such term is used in Section 14(d) of the Exchange Act) or exchange offer, which, if consummated, would result in a Change in Control; or
(c) Any SEC Person files with the SEC a preliminary or definitive proxy solicitation or election contest to elect or remove one or more members of the Board, which, if consummated or effected, would result in a Change in Control;
provided, however, that an Imminent Control Change will lapse and cease to qualify as an Imminent Control Change:
(i) With respect to an Imminent Control Change described in clause (a) of this definition, the date such agreement is terminated, cancelled or expires without a Change Date occurring;
(ii) With respect to an Imminent Control Change described in clause (b) of this definition, the date such tender offer or exchange offer is withdrawn or terminates without a Change Date occurring;
(iii) With respect to an Imminent Control Change described in clause (c) of this definition, (1) the date the validity of such proxy solicitation or election contest expires under relevant state corporate law, or (2) the date such proxy solicitation or election contest culminates in a shareholder vote, in either case without a Change Date occurring; or
6
(iv) The date a majority of the members of the Incumbent Board make a good faith determination that any event or condition described in clause (a), (b), or (c) of this definition no longer constitutes an Imminent Control Change, provided that such determination may not be made prior to the twelve (12) month anniversary of the occurrence of such event.
1.29 “Imminent Control Change Period” means the period commencing on the date of an Imminent Control Change, and ending on the first to occur thereafter of
(a) a Change Date, provided
(i) such date occurs no later than the one-year anniversary of the Termination Date, and
(ii) either the Imminent Control Change has not lapsed, or the Imminent Control Change in effect upon such Change Date is the last Imminent Control Change in a series of Imminent Control Changes unbroken by any period of time between the lapse of an Imminent Control Change and the occurrence of a new Imminent Control Change;
(b) if Executive’s business unit undergoes Disaggregation and Executive retains substantially the same position with the Disaggregated Entity as immediately prior to such Disaggregation (determined without regard to reporting obligations) the earlier to occur after such Disaggregation of a Change Date or the end of the 60th day following such Disaggregation without the occurrence of a Change Date,
(c) the date an Imminent Control Changes lapses without the prior or concurrent occurrence of a new Imminent Control Change; or
(d) the twelve-month anniversary of the Termination Date.
1.30 “Incentive Plan” means the Exelon Corporation Annual Incentive Plan for Senior Executives or such other annual incentive award arrangement of the Company in which the Executive is a participant in lieu of such program.
1.31 “Including” means including without limitation.
1.32 “Incumbent Board” - see definition of Change in Control.
1.33 “IRS” means the Internal Revenue Service of the United States of America.
1.34 “LTIP” means the Exelon Corporation Long-Term Incentive Plan, as amended from time to time, or any successor thereto, and including any Stock Options or Restricted Stock granted thereunder to replace stock options or restricted stock initially granted under the Unicom Corporation Long-Term Incentive Plan.
1.35 “LTIP Performance Period” means the one-year performance period applicable to an LTIP award, as designated in accordance with the LTIP.
7
1.36 “LTIP Target Level” means, in respect of any grant of Performance Shares under the Exelon Performance Share Program under the LTIP, the number of Performance Shares which Executive would have been awarded (prior to the Termination Date) for the LTIP Performance Period corresponding to such grant if the business and personal performance goals related to such grant were achieved at the 100% (target) level as of the end of the LTIP Performance Period.
1.37 “Merger” - see definition of Change in Control.
1.38 “Notice of Termination” means a written notice given in accordance with Section 10.8 which sets forth (i) the specific termination provision in this Agreement relied upon by the party giving such notice, (ii) in reasonable detail the specific facts and circumstances claimed to provide a basis for such Termination of Employment, and (iii) if the Termination Date is other than the date of receipt of such Notice of Termination, the Termination Date.
1.39 “Performance Shares” - see Section 4.1(c). After a Disaggregation, “Performance Shares” shall also refer to performance shares, performance units or similar stock incentive awards granted by a Disaggregated Entity (or an affiliate thereof) in replacement of performance shares, performance units or similar stock incentive awards granted under the Exelon Performance Share Program under the LTIP.
1.40 “Person” means any individual, sole proprietorship, partnership, joint venture, limited liability company, trust, unincorporated organization, association, corporation, institution, public benefit corporation, entity or government instrumentality, division, agency, body or department.
1.41 “Plans” means plans, practices, policies and programs of the Company (or, if applicable to Executive, the Disaggregated Entity or Affiliate).
1.42 “Post-Change Period” means the period commencing on the Change Date and ending on the earlier of the Termination Date or the second anniversary of the Change Date.
1.43 “Post-Disaggregation Period” means the period commencing on the first date during the Agreement Term on which a Change in Control occurs following a Disaggregation, provided such Change Date occurs no more than 60 days following such Disaggregation, and ending on the earlier of the Termination Date or the second anniversary of the Change Date. If no Change Date occurs within 60 days after the Disaggregation, there shall be no Post-Disaggregation Period.
1.44 “Post-Significant Acquisition Period” means the period commencing on the date of a Significant Acquisition that occurs during the Agreement Term prior to a Change Date, and ending on the first to occur of (a) the end of the 18-month period commencing on the date of the Significant Acquisition, (b) the Change Date, or (c) the Termination Date.
1.45 “Restricted Stock” — see Section 4.1(d). After a Disaggregation, “Restricted Stock” shall also refer to deferred stock units, restricted stock or restricted share units granted by a Disaggregated Entity (or an affiliate thereof) in replacement of deferred stock units, restricted
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stock or restricted share units granted by the Company other than under the Exelon Performance Share Program under the LTIP.
1.46 “SEC” means the United States Securities and Exchange Commission.
1.47 “SEC Person” means any person (as such term is used in Rule 13d-5 of the SEC under the Exchange Act) or group (as such term is defined in Sections 3(a)(9) and 13(d)(3) of the Exchange Act), other than (a) the Company or an Affiliate, or (b) any employee benefit plan (or any related trust) of the Company or any of its Affiliates.
1.48 “Section” means, unless the context otherwise requires, a section of this Agreement.
1.49 “SERP” means the PECO Energy Company Supplemental Retirement Plan or the Exelon Corporation Supplemental Management Retirement Plan, whichever is applicable to Executive, or any successor to either or both.
1.50 “Severance Incentive” means the greater of (a) the Target Incentive for the performance period in which the Termination Date occurs, or (b) the average (mean) of the actual Annual Incentives paid (or payable, to the extent not previously paid) to the Executive under the Incentive Plan for each of the two calendar years preceding the calendar year in which the Termination Date occurs.
1.51 “Severance Period” means the period beginning on the Executive’s Termination Date, provided Executive’s Termination of Employment entitles Executive to benefits under Section 4.1, 4.2 or 4.3, and ending on the third anniversary thereof. There shall be no Severance Period if Executive’s Termination of Employment is on account of death or Disability or if Executive’s employment is terminated by the Company for Cause or by Executive other than for Good Reason.
1.52 “Significant Acquisition” means a Corporate Transaction affecting the Executive’s business unit (or, if Executive is employed at the headquarters for the Company’s corporate business operations (“Corporate Center”), a Corporate Transaction that affects the Corporate Center) that is consummated after the Agreement Date and prior to the Change Date, which Corporate Transaction is not a Change in Control, provided that as a result of such Corporate Transaction, all or substantially all of the individuals and entities who are the Beneficial Owners, respectively, of the outstanding common stock of Company and outstanding Voting Securities of the Company immediately prior to such Corporate Transaction beneficially own, directly or indirectly, more than 60% but not more than 66-2/3% of, respectively, the then-outstanding shares of common stock and the combined voting power of the then-outstanding voting securities entitled to vote generally in the election of directors, as the case may be, of the corporation resulting from such Corporate Transaction (including, without limitation, a corporation which, as a result of such transaction, owns the Company or all or substantially all of the assets of the Company either directly or through one or more subsidiaries) in substantially the same proportions as their ownership immediately prior to such Corporate Transaction of the outstanding common stock of Company and outstanding Voting Securities of the Company, as the case may be.
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1.53 “Stock Options” — see Section 4.1(b). After a Disaggregation, “Stock Options” shall also refer to stock options, stock appreciation rights, or similar incentive awards granted by the Disaggregated Entity (or an affiliate thereof) in replacement of stock options, stock appreciation rights, or similar incentive awards granted under the LTIP.
1.54 “Target Incentive” as of a certain date means an amount equal to the product of Base Salary determined as of such date multiplied by the percentage of such Base Salary to which Executive would have been entitled immediately prior to such date under the Incentive Plan for the applicable performance period if the performance goals established pursuant to such Incentive Plan were achieved at the 100% (target) level as of the end of the applicable performance period (taking into account for this purpose any negative discretion exercised by the Compensation Committee of the Board in establishing such target); provided, however, that any reduction in Executive’s Base Salary or Annual Incentive that would qualify as Good Reason shall be disregarded for purposes of this definition.
1.55 “Taxes” means the incremental federal, state, local and foreign income, employment, excise and other taxes payable by Executive with respect to any applicable item of income.
1.56 “Termination Date” means the effective date of Executive’s Termination of Employment, which shall be the last day on which Executive is employed by the Company, an Affiliate or a Disaggregated Entity; provided, however, that (a) if the Company terminates the Executive’s employment other than for Cause or Disability or if the Executive terminates Executive’s employment for Good Reason, then the Termination Date shall be the date of receipt of the Notice of Termination by Executive (if such Notice is given by the Company, an Affiliate or a Disaggregated Entity) or by the Company, an Affiliate or a Disaggregated Entity (if such Notice is given by Executive), or such later date, not more than 15 days after the giving of such Notice, specified in such Notice as of which Executive’s employment shall be terminated; and (b) if Executive’s employment is terminated by reason of death or Disability, the Termination Date shall be the date of Executive’s death or the Disability Effective Date (as described in Section 3.1(a)).
1.57 “Termination of Employment” means any termination of Executive’s employment with the Company and its Affiliates, whether such termination is initiated by the Employer or by Executive; provided that if the Executive’s cessation of employment with the Company and its Affiliates is effected through a Disaggregation, and Executive is employed in substantially the same position (without regard to reporting obligations) by the Disaggregated Entity immediately following the Disaggregation, and a Change Date occurs no more than 60 days after such Disaggregation, then the Disaggregation shall not be deemed to effect a “Termination of Employment” for purposes of this Agreement, and after the Disaggregation, “Termination of Employment” means any termination of Executive’s employment with the Disaggregated Entity, whether such termination is initiated by the Disaggregated Entity or by Executive.
1.58 “20% Owner” — see paragraph (a) of the definition of “Change in Control.”
1.59 “Voting Securities” means with respect to a corporation, securities of such corporation that are entitled to vote generally in the election of directors of such corporation.
1.60 “Welfare Plans” - see Section 2.8(a)(ii).
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Article II.
Terms of Employment
2.1 Position and Duties During a Post-Change Period. During the Post-Change Period prior to the Termination Date, (i) Executive’s position, duties and responsibilities (other than the position or level of officer to whom the Executive reports or any change that is part of a policy, program or arrangement applicable to peer executives of the Company and any successor to the Company) shall be at least commensurate in all material respects with the most significant of those held, exercised and assigned at any time during the 90-day period immediately before the Change Date (or if the Change Date ended an Imminent Control Change Period, during the 90-day period immediately before the beginning of the Imminent Control Change Period) and (ii) Executive’s services shall be performed at the location where Executive was employed immediately before the Change Date (or if the Change Date ended an Imminent Control Change Period, before the beginning of such Imminent Control Change Period) or any other location no more than 50 miles from such location (unless such other location is closer to Executive’s residence than the prior location).
2.2 Position and Duties During an Imminent Control Change Period. During the portion of any Imminent Control Change Period that occurs before the Termination Date, the Company may in its discretion change the Executive’s position, authority and duties and may change the location where Executive’s services shall be performed.
2.3 Position and Duties During a Post-Significant Acquisition Period. During the portion of any Post-Significant Acquisition Period that occurs before the Termination Date, the Company may in its discretion change the Executive’s position, authority and duties, and may change the location where Executive’s services shall be performed.
2.4 Position and Duties During a Post-Disaggregation Period. During the Post-Disaggregation Period, (i) Executive’s position with the Disaggregated Entity shall be at least commensurate in all material respects with the most significant position held by Executive with the Disaggregated Entity immediately following the Disaggregation, and (ii) unless Executive otherwise consents, Executive’s services shall be performed at the location where Executive was employed immediately prior to the Change Date or any other location no more than 50 miles from such location (unless such other location is closer to Executive’s residence than the prior location); provided, however, that in determining whether the Executive’s Termination of Employment is for Cause, “Cause” shall be determined as though the provisions of Section 3.3(a) applied commencing with the first day of the Post-Disaggregation Period.
2.5 Executive’s Obligations. During the Executive’s employment (other than any periods of paid time off, sick leave or disability to which Executive is entitled), Executive agrees to devote Executive’s full attention and time to the business and affairs of the Company (or, in the case of a Disaggregation, the Disaggregated Entity) and to use Executive’s best efforts to perform such duties. Executive may (i) serve on corporate, civic or charitable boards or committees, (ii) deliver lectures, fulfill speaking engagements or teach at educational institutions
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and (iii) manage personal investments, so long as such activities are consistent with the Plans of the Employer (or in the case of a Disaggregation, the Disaggregated Entity) in effect from time to time, and do not significantly interfere with the performance of Executive’s duties under this Agreement.
2.6 Base Salary During the Post-Change Period.
(a) Base Salary During Post-Change Period. Prior to the Termination Date during the Post-Change Period, the Company shall pay or cause to be paid to Executive an annual base salary in cash, which shall be paid in a manner consistent with the Employer’s payroll practices in effect immediately before the Applicable Trigger Date at an annual rate not less than 12 times the highest monthly base salary paid or payable to Executive by the Employer in respect of the 12-month period immediately before the Applicable Trigger Date (such annual rate salary, the “Base Salary”). During the Post-Change Period, the Base Salary shall be reviewed no more than 12 months after the last salary increase awarded to Executive prior to the Applicable Trigger Date and thereafter shall be reviewed and shall be increased at any time and from time to time as shall be substantially consistent with increases in base salary awarded to peer executives of the Company generally. Base Salary shall not be reduced unless such reduction is part of a policy, program or arrangement applicable to peer executives of the Company (including peer executives of any successor to the Company), and the term Base Salary as used in this Agreement shall refer to Base Salary as so increased. Any increase in Base Salary shall not limit or reduce any other obligation of the Company to the Executive under this Agreement.
(b) Base Salary During the Imminent Control Change Period, Post-Significant Acquisition Period and Post-Disaggregation Period. Section 2.6(a) shall not apply during the Imminent Control Change Period, Post-Significant Acquisition Period or Post-Disaggregation Period.
2.7 Annual Incentive.
(a) Annual Incentive During the Post-Change Period. In addition to Base Salary, the Company shall provide or cause to be provided to Executive the opportunity to receive payment of an annual incentive (the “Annual Incentive”) with an award opportunity no less, including target performance goals not materially more difficult to achieve, than that in effect immediately prior to the Applicable Trigger Date for each applicable performance period which commences prior to the Termination Date and ends during the Post-Change Period. The amount of the Executive’s award opportunity in effect for any relevant period shall be determined taking into account any negative discretion exercised by the Compensation Committee of the Board in establishing such opportunity.
(b) Annual Incentive during the Imminent Control Change Period, Post-Significant Acquisition Period or Post-Disaggregation Period. Section 2.7(a) shall not apply during the Imminent Control Change Period, Post-Significant Acquisition Period or Post-Disaggregation Period.
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2.8 Other Compensation and Benefits.
(a) Other Compensation and Benefits during the Post-Change Period. In addition to Base Salary and Annual Incentive, prior to the Termination Date the Company shall provide or cause to be provided, throughout the Post-Change Period, the following other compensation and benefits to Executive, provided that, in no event shall such additional compensation and benefits (including incentives, measured with respect to long term and special incentives, to the extent, if any, that such distinctions are applicable) be materially less favorable, in the aggregate, than those provided at any time after the Applicable Trigger Date to peer executives of the Company (including peer executives of any successor to the Company) generally:
(i) Incentive, Savings and Retirement Plans. Executive shall be entitled to participate in all incentive, savings and retirement Plans applicable to peer executives of the Company generally.
(ii) Welfare Benefit Plans. Executive and/or the Executive’s family, as the case may be, shall be eligible for participation in and shall receive all benefits under welfare benefit Plans (“Welfare Plans”) (including medical, prescription, dental, disability, employee life, group life, accidental death and travel accident insurance benefits, but excluding any severance pay) provided by the Employer from time to time to peer executives of the Company generally.
(iii) Other Employee Benefits. Executive shall be entitled to other employee benefits, perquisites and fringe benefits in accordance with the most favorable Plans applicable to peer executives of the Company generally.
(iv) Expenses. Executive shall be entitled to receive prompt reimbursement for all reasonable business expenses incurred by the Executive in accordance with the most favorable Plans applicable to peer executives of the Company generally.
(v) Office and Support Staff. Executive shall be entitled to an office or offices of a size and with furnishings and other appointments, and to secretarial and other assistance substantially equivalent to the office or offices, furnishings, appointments and assistance as in effect with respect to Executive on the Applicable Trigger Date.
(vi) Paid Time Off. Executive shall be entitled to paid time off in accordance with the Plans applicable to peer executives of the Company generally.
(vii) LTIP Awards. Awards under the LTIP shall be granted to Executive with aggregate target opportunities not less than those granted to peer executives of the Company.
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(b) Other Compensation and Benefits During the Imminent Control Change Period, Post-Significant Acquisition Period or Post-Disaggregation Period. Section 2.8(a) shall not apply during Imminent Control Change Period, Post-Significant Acquisition Period or Post-Disaggregation Period.
(c) Stock Options, Restricted Stock, and Performance Shares During the Post-Disaggregation Period.
(i) Stock Options.
(A) Extinguished or Converted at Disaggregation. If so provided in the documents and instruments (“Disaggregation Documents”) pursuant to which the Disaggregation is effected, then all of Executive’s Stock Options shall (I) be extinguished immediately prior to the Disaggregation for such consideration as is provided for in the Disaggregation Documents (but not less than the product of the number of Executive’s vested Stock Options multiplied by the difference between the fair market value of Exelon stock immediately prior to the Disaggregation and the option exercise price), or (II) be converted into options to acquire stock of the Disaggregated Entity or an affiliate thereof on a basis determined by the Company in good faith to preserve economic value.
(B) Extinguished or Converted at Merger. If the Change in Control following the Disaggregation is a Merger, and if so provided in the agreement pursuant to which the Merger is effected, then all of Executive’s Company Stock Options that were not extinguished or converted to options to acquire stock in the Disaggregated Entity or an affiliate shall (I) be extinguished immediately prior to the Change in Control for such consideration as is provided for Stock Options of peer executives employed by the Company or an Affiliate, or (II) be converted into options to acquire stock of the corporation resulting from the Merger (“Merger Survivor”) or an affiliate thereof, on the same basis as Stock Options of employees of the Company are converted.
(C) Stock Options after the Disaggregation. Executive’s unextinguished Stock Options, whether or not they are converted to options for stock of the Disaggregated Entity or Merger Survivor, shall continue to vest and, once vested, shall remain exercisable in accordance with their terms, subject to Section 4.3(b).
(ii) Performance Shares.
(A) Extinguished or Converted at Disaggregation. If so provided in the Disaggregation Documents, all of Executive’s Performance Shares shall (I) be extinguished immediately prior to the Disaggregation for such consideration as is provided under the Disaggregation Documents (but no less than the fair market value, immediately prior to the Disaggregation, of a number of Exelon shares
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equal to the sum of Executive’s earned and awarded Performance Shares and the target number of Executive’s Performance Shares that have not yet been earned and awarded), or (II) shall be converted into performance shares with respect to the Disaggregated Entity or an affiliate (on a basis determined by the Company in good faith to preserve economic value for the Executive).
(B) Extinguished or Converted at Merger. If the Change in Control following the Disaggregation is a Merger, and if so provided in the agreement pursuant to which the Merger is effected, then all of Executive’s Performance Shares that were not extinguished or converted to performance shares of the Disaggregated Entity or an affiliate shall (I) be extinguished immediately prior to the Change in Control for such consideration as is provided for Performance Shares of peer executives employed by the Company or an Affiliate, or (II) be converted into performance shares of the Merger Survivor or an affiliate thereof, on the same basis as Performance Shares of employees of the Company are converted.
(C) Performance Shares after the Disaggregation. Executive’s unextinguished Performance Shares, whether or not they are converted into performance shares of the Disaggregated Entity or Merger Survivor, will continue to vest during the Post-Disaggregation Period, subject to Section 4.3(c).
(iii) Restricted Stock.
(A) Extinguished or Converted at Disaggregation. If so provided in the Disaggregation Documents, all of Executive’s Restricted Stock shall (I) be extinguished immediately prior to the Disaggregation for an amount equal to the fair market value of an equal number of shares of Exelon common stock, or (II) shall be converted into restricted stock of the Disaggregated Entity or an affiliate (on a basis determined by the Company in good faith to preserve economic value for the Executive).
(B) Extinguished or Converted at Merger. If the Change in Control following the Disaggregation is a Merger, and if so provided in the agreement pursuant to which the Merger is effected, then all of Executive’s Restricted Stock that was not extinguished or converted to restricted stock of the Disaggregated Entity or an affiliate shall (I) be extinguished immediately prior to the Change in Control for such consideration as is provided for Restricted Stock of peer executives employed by the Company or an Affiliate, or (II) be converted into restricted stock of the Merger Survivor or an affiliate thereof, and such converted restricted stock will continue to vest during the Post-Disaggregation Period prior to the Termination Date.
(C) Restricted Stock after the Disaggregation. Executive’s unextinguished Restricted Stock, whether or not converted to restricted
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stock of the Disaggregated Entity or Merger Survivor, will continue to vest during the Post-Disaggregation Period, subject to Section 4.3(d).
Article III.
Termination of Employment
3.1 Disability.
(a) During the Agreement Term, the Employer (or, if applicable, the Disaggregated Entity) may terminate Executive’s employment at any time because of Executive’s Disability by giving Executive or her legal representative, as applicable, (i) written notice in accordance with Section 10.8 of the Company’s intention to terminate Executive’s employment pursuant to this Section and (ii) a certification of Executive’s Disability by a physician selected by the Employer or its insurers, subject to the reasonable consent of Executive or Executive’s legal representative, which consent shall not be unreasonably withheld or delayed. Executive’s employment shall terminate effective on the 30th day after Executive’s receipt of such notice (which such 30th day shall be deemed to be the “Disability Effective Date”) unless, before such 30th day, Executive shall have resumed the full-time performance of Executive’s duties.
(b) “Disability” means any medically determinable physical or mental impairment that has lasted for a continuous period of not less than six months and can be expected to be permanent or of indefinite duration, and that renders Executive unable to perform the duties required under this Agreement.
3.2 Death. Executive’s employment shall terminate automatically upon Executive’s death during the Agreement Term.
3.3 Termination by the Company for Cause. During the Post-Change Period, Post-Disaggregation Period, Imminent Control Change Period or Post-Significant Acquisition Period, the Company may terminate Executive’s employment (or cause Executive’s employment to be terminated) for Cause solely in accordance with all of the substantive and procedural provisions of this Section 3.3.
(a) Definition of Cause. “Cause” means any one or more of the following:
(i) the refusal to perform or habitual neglect in the performance of the Executive’s duties or responsibilities, or of specific directives of the officer or other executive of the Company or any of its affiliates to whom the Executive reports which are not materially inconsistent with the scope and nature of the Executive’s employment duties and responsibilities;
(ii) an Executive’s willful or reckless commission of act(s) or omission(s) which have resulted in or are likely to result in, a material loss to, or material damage to the reputation of, the Company or any of its affiliates, or that compromise the safety of any employee or other person;
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(iii) the Executive’s commission of a felony or any crime involving dishonesty or moral turpitude;
(iv) an Executive’s material violation of the Company’s or any of its affiliates’ Code of Business Conduct (including the corporate policies referenced therein) which would constitute grounds for immediate termination of employment, or of any statutory or common-law duty of loyalty to the Company or any of its affiliates; or
(v) any breach by the Executive of any one or more of the Restrictive Covenants.
For purposes of this Section, no act, or failure to act, on the part of the Executive shall be considered “willful” unless it is done, or omitted to be done, by the Executive in bad faith or without reasonable belief that the Executive’s action or omission was in the best interests of the Company. Any act, or failure to act, based upon authority given pursuant to a resolution duly adopted by the Board or upon the instructions of the chief executive officer or a senior officer of the Company other than Executive or based upon the advice of counsel for the Company shall be conclusively presumed to be done, or omitted to be done, by the Executive in good faith and in the best interests of the Company.
(b) Procedural Requirements for Termination for Cause During a Post-Change Period. The Executive’s Termination of Employment for which the Notice of Termination is given during a Post-Change Period shall not be deemed to be for Cause under this Section 3.3 unless and until there shall have been delivered to the Executive a copy of a resolution duly adopted by the affirmative vote of not less than 60% of the entire membership of the Board at a meeting of such Board called and held for such purpose (after reasonable written notice of such meeting is provided to the Executive and the Executive is given an opportunity, together with counsel, to be heard before the Board), finding that, in the good faith opinion of the Board, the Executive’s acts, or failure to act, constitutes Cause and specifying the particulars thereof in detail.
(c) Procedural Requirements for Termination for Cause During a Post-Disaggregation Period. In the event Executive’s Termination of Employment is from a Disaggregated Entity in a Post-Disaggregation Period, the procedural requirements for termination for Cause in this Section 3.3 shall be applied by substituting “Disaggregated Entity” for “Company,” “affiliate of the Disaggregated Entity” for “Affiliate,” and “Disaggregated Entity’s Board” for “Board.” Further, the Company shall have no obligation to provide payments or benefits under Section 4.3 if the Board determines that the Company could have terminated Executive’s employment for Cause if the Executive had been employed by the Company, such determination by the Board to be made as provided in Section 3.3(b) but applying the flush language at the end of Section 3.3(a) by substituting “Disaggregated Entity” for “Company” and “Disaggregated Entity’s Board” for “Board.”
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(d) Procedural Requirements for Termination for Cause During the Imminent Control Change Period or Post-Significant Acquisition Period. The Executive’s Termination of Employment for which the Notice of Termination is given during the Imminent Control Change Period or Post-Significant Acquisition Period shall not be deemed to be for Cause under this Section 3.3 unless and until there shall have been delivered to the Executive a copy of a resolution duly adopted by the affirmative vote of not less than a majority of the entire membership of the Board, finding that the Executive’s acts or failure to act, constitute Cause and specifying the particulars thereof in detail. Executive shall receive advance notice of such vote of the Board, but shall not have the right to appear in person or by counsel before the Board.
3.4 Termination by the Executive for Good Reason. During the Post-Change Period, an Imminent Control Change Period, a Post-Significant Acquisition Period or Post-Disaggregation Period, Executive may terminate her employment for Good Reason in accordance with the substantive and procedural provisions of this Section 3.4.
(a) Definition of Good Reason. For purposes of this Section 3.4, and subject to the provisions of subsections (b) through (e), “Good Reason” means the occurrence of any one or more of the following actions or omissions prior to the Termination Date during the Post-Change Period, the Imminent Control Change Period, the Post-Significant Acquisition Period or the Post-Disaggregation Period:
(i) a material reduction of the Executive’s salary, incentive compensation opportunity or aggregate benefits unless such reduction is part of a policy, program or arrangement applicable to peer executives (including peer executives of any successor to the Company;
(ii) a material adverse reduction in the Executive’s position, duties, or responsibilities, other than in a Post-Significant Acquisition period, and other than a change in the position or level of officer to whom the Executive reports or a change that is part of a policy, program or arrangement applicable to peer executives (including peer executives of any successor to the Company);
(iii) the failure of any successor to the Company to assume this Agreement;
(iv) a relocation (other than in a Post-Significant Acquisition Period), by more than 50 miles of (I) the Executive’s primary workplace, or (II) the principal offices of the Company or its successor (if such offices are the Executive’s workplace), in each case without Executive’s consent; provided, however, in both cases of (I) and (II) of this Section 3.4(a)(iv), such new location is farther from Executive’s residence then the prior location; or
(v) a material breach of this Agreement by the Company or its successor;
provided that the occurrence of a Disaggregation shall not be Good Reason if the Executive retains substantially the same position (determined without regard to
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reporting requirements) with the Disaggregated Entity, with substantially the same compensation and benefits in the aggregate, as immediately prior to such Disaggregation, notwithstanding Sections 3.4(a)(i), 3.4(a)(ii) and 3.4(a)(v).
(b) Application of “Good Reason” Definition During the Imminent Control Change Period. During the Imminent Control Change Period, “Good Reason” shall not include the events or conditions described in Section 3.4(a)(i), 3.4(a)(ii) or 3.4(a)(iv) unless the Imminent Control Change Period culminates in a Change Date. Further, if Executive’s Termination of Employment occurs during an Imminent Control Change Period that culminates in a Change Date, then, except as provided in Section 3.4(c), the definition of “Good Reason” shall be applied as though Sections 2.1, 2.6, 2.7, and 2.8 were applicable during the Imminent Control Change Period prior to the Executive’s Termination of Employment.
(c) Special Conditions Relating to Good Reason During the Post-Disaggregation Period. If Executive retains substantially the same position with the Disaggregated Entity as immediately prior to the Disaggregation (determined without regard to reporting requirements), then (1) Section 3.4(a)(ii) shall apply only with respect to the Executive’s position, duties or responsibilities as in effect at the Disaggregated Entity on the day following the Disaggregation, (2) subsection 3.4(a)(iv) shall apply only with respect to relocations required more than 60 days after the Disaggregation and shall be applied by substituting “Disaggregated Entity” for “any successor to the Company”, and (3) all references in Section 3.4 to the Company or its successor shall be to the Disaggregated Entity or its successor.
(d) Limitations on Good Reason. Notwithstanding the foregoing provisions of this Section 3.4, no act or omission shall constitute a material breach of this Agreement by the Company, nor grounds for “Good Reason”:
(i) unless the Executive gives the Company a Notice of Termination at least 30 days’ prior to the Termination Date and the Company fails to cure such act or omission within the 30-day period;
(ii) if the Executive first acquired knowledge of such act or omission more than 180 days before the Executive gives the Company and the Employer such Notice of Termination; or
(iii) if the Executive has consented in writing to such act or omission.
(e) Notice by Executive. In the event of any Termination of Employment by Executive for Good Reason, Executive shall as soon as practicable thereafter notify the Company and the Employer (and Disaggregated Entity, if applicable) of the events constituting such Good Reason by a Notice of Termination. Subject to the limitations in Section 3.4(d), a delay in the delivery of such Notice of Termination shall not waive any right of Executive under this Agreement.
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Article IV.
Company’s Obligations Upon Certain Terminations of Employment
4.1 Termination During the Post-Change Period or Post-Significant Acquisition Period. If, during the Post-Change Period or Post-Significant Acquisition Period (other than any portion of any of such periods that are also a Post-Disaggregation Period), the Employer terminates Executive’s employment other than for Cause or Disability, or Executive terminates employment for Good Reason, the Company’s sole obligations to Executive under Articles II and IV shall be as set forth in this Section 4.1.
(a) Termination during the Post-Change Period or Post-Significant Acquisition Period: Severance Payments. The Company shall pay or provide Executive, according to the payment terms set forth in Section 4.4 below, the following:
(i) Accrued Obligations. All Accrued Obligations;
(ii) Annual Incentive for Year of Termination. An amount equal to the Target Incentive applicable to the Executive under the Incentive Plan for the performance period in which the Termination Date occurs.
(iii) Deferred Compensation and Non-Qualified Defined Contribution Plans. All amounts previously deferred by, or accrued to the benefit of, Executive under the Exelon Corporation Deferred Compensation Plan, the Exelon Corporation Deferred Stock Plan, or any successor of either of them, or under any non-qualified defined contribution or deferred compensation plan of the Company or an Affiliate (unless Executive has made an irrevocable election in writing, filed with the Company no more than 60 days after the Applicable Trigger Date (or such earlier date as counsel to the Company may deem to be required to avoid constructive receipt of such amounts), and in any event at least 90 days prior to the Termination Date to have such amounts paid under the terms of the Exelon Corporation Deferred Compensation Plan or the Exelon Corporation Deferred Stock Plan, as applicable, or any successor of either (including any elections in effect thereunder)) whether vested or unvested, together with any accrued earnings thereon, to the extent that such amounts and earnings have not been previously paid by the Employer and are not provided under the terms of either such non-qualified plan;
(iv) Pension Enhancements. An amount equal to the positive difference, if any, between
(1) the lump sum value of Executive’s benefit under the SERP, calculated as if Executive had
(A) become fully vested in all benefits,
(B) attained as of the Termination Date an age that is three years greater than Executive’s actual age,
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(C) accrued a number of years of service (for purposes of determining the amount of such benefits, entitlement to - but not commencement of - early retirement benefits, and all other purposes of such defined benefit plans) that is three years greater than the sum of the number of years of service actually accrued by Executive as of the Termination Date and that includes the number of years of service credited to Executive pursuant to any other written agreement between the Company and the Executive, and
(D) received the severance benefits specified in Sections 4.1(a)(ii) and 4.1(a)(vi) as covered compensation in equal monthly installments during the Severance Period,
minus
(2) the aggregate amounts paid or payable to Executive under the SERP.
(v) Unvested Benefits Under Defined Benefit Plan. To the extent not paid pursuant to clause (iii) or (iv) of this Section 4.1(a), an amount equal to the actuarial equivalent present value of any unvested portion of Executive’s accrued benefits or cash balance account (as applicable) under any tax-qualified (under Section 401(a) of the Code) defined benefit retirement plan maintained by the Employer as of the Termination Date and forfeited by Executive by reason of the Termination of Employment; and
(vi) Multiple of Salary and Severance Incentive. An amount equal to three (3.0) times the sum of (x) Base Salary plus (y) the Severance Incentive.
(b) Termination during the Post-Change Period or Post-Significant Acquisition Period: Stock Options. Each of the Executive’s stock options, stock appreciation rights or similar incentive awards granted under the LTIP (“Stock Options”) shall (i) become fully vested, and (ii) remain exercisable until (1) the option expiration date for any such Stock Options granted prior to January 1, 2002 or (2) the fifth anniversary of the Termination Date or, if earlier, the option expiration date for any such Stock Options granted on or after January 1, 2002.
(c) Termination during the Post-Change Period or Post-Significant Acquisition Period: LTIP Vesting. On the Termination Date all of the performance shares, performance units or similar stock incentive awards granted to the Executive under the Exelon Performance Share Program under the LTIP (“Performance Shares”) to the extent earned by and awarded to the Executive (i.e. as to which the applicable performance cycle has elapsed) as of the Termination Date, shall become fully vested at the actual level earned and awarded, and, to the extent not yet earned by and awarded to the Executive (i.e. as to which the current performance cycle has not elapsed) as of the Termination Date, shall become fully vested at the LTIP Target Level.
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(d) Termination During the Post-Change Period or Post-Significant Acquisition Period: Other Restricted Stock. All forfeiture conditions that as of the Termination Date are applicable to any deferred stock unit, restricted stock or restricted share units awarded to the Executive by the Company other than under the Exelon Performance Share Program under the LTIP (“Restricted Stock”) shall (except as specifically provided to the contrary in the applicable awards) lapse immediately and all such awards will become fully vested, and within ten business days after the Termination Date, the Company shall deliver to Executive all of such shares theretofore held by or on behalf of the Company.
(e) Termination During the Post-Change Period or Post-Significant Acquisition Period: Continuation of Welfare Benefits. During the Severance Period (and continuing through such later date as any Welfare Plan may specify), the Company shall continue to provide (or shall cause the continued provision) to Executive and Executive’s family welfare benefits under the Welfare Plans to the same extent as if Executive had remained employed during the Severance Period. Such provision of welfare benefits shall be subject to the following:
(i) In determining benefits applicable under such Welfare Plans, the Executive’s annual compensation attributable to base salary and incentives for any plan year or calendar year, as applicable, shall be deemed to be not less than the Executive’s Base Salary and Annual Incentive.
(ii) The cost of such welfare benefits to Executive and family under this Section 4.1(e) shall not exceed the cost of such benefits to peer executives who are actively employed after the Termination Date.
(iii) The Executive’s rights under this Section 4.1(e) shall be in addition to and not in lieu of any post-termination continuation coverage or conversion rights the Executive may have pursuant to applicable law, including, without limitation, continuation coverage required by Section 4980B of the Code.
(iv) If the Executive has, as of the last day of the Severance Period, attained age 50 and completed at least 10 years of service (or any lesser age and service requirement then in effect under the Exelon Corporation Severance Benefit Plan or any successor plan), the Executive shall be entitled to the retiree benefits provided under any Welfare Plan of the Company; provided, however, that for purposes hereof, any years of credited service granted to the Executive in any other written plan or agreement between Executive and the Company shall be taken into account. For purposes of determining eligibility for (but not the time of commencement of) such retiree benefits, the Executive shall also be considered (1) to have remained employed until the last day of the Severance Period and to have retired on the last day of such period, and (2) to have attained at least the age the Executive would have attained on the last day of the Severance Period.
Notwithstanding the foregoing, if the Executive obtains a specific type of coverage under welfare plan(s) sponsored by another employer of Executive (e.g. medical, prescription,
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vision, dental, disability, individual life insurance benefits, group life insurance benefits, but excluding for the purposes of this sentence retiree benefits if Executive is so eligible), then the Company shall not be obligated to provide any such specific type of coverage. The Executive shall promptly notify the Company of any such coverage.
(f) Termination during the Post-Change Period or Post-Significant Acquisition Period: Outplacement. To the extent actually incurred by Executive, the Company shall pay or cause to be paid on behalf of Executive, as incurred, all reasonable fees and costs charged by a nationally recognized outplacement firm selected by the Executive for outplacement services provided up to 12 months after the Termination Date. No cash shall be paid in lieu of such fees and costs.
(g) Termination during the Post-Change Period or Post-Significant Acquisition Period: Indemnification. The Executive shall be indemnified and held harmless by the Company to the greatest extent permitted under applicable law as the same now exists or may hereafter be amended (but, in the case of any such amendment, only to the extent that such amendment permits the Company to provide broader indemnification than was permitted prior to such amendment) and the Company’s by-laws as such exist on the Applicable Trigger Date if the Executive was, is, or is threatened to be, made a party to any pending, completed or threatened action, suit, arbitration, alternate dispute resolution mechanism, investigation, administrative hearing or any other proceeding brought by a third party (and not by or on behalf of the Company or its shareholders) whether civil, criminal, administrative or investigative, and whether formal or informal, by reason of the fact that the Executive is or was, or had agreed to become, a director, officer, employee, agent, or fiduciary of the Company or any other entity which the Executive is or was serving at the request of the Company (“Proceeding”), against all expenses (including all reasonable attorneys’ fees) and all claims, damages, liabilities and losses incurred or suffered by the Executive or to which the Executive may become subject for any reason; provided, that the Company shall not be required to indemnify the Executive in connection with any proceeding initiated by the Executive, including a counterclaim or cross claim, unless such proceeding was authorized by the Company. A Proceeding shall not include any proceeding to the extent it concerns or relates to a matter described in Section 6.1(a) (concerning reimbursement of certain costs and expenses). Upon receipt from Executive of (i) a written request for an advancement of expenses, which Executive reasonably believes will be subject to indemnification hereunder and (ii) a written undertaking by Executive to repay any such amounts if it shall ultimately be determined that Executive is not entitled to indemnification under this Agreement or otherwise, the Company shall, to the extent permitted by applicable law, advance such expenses to Executive or pay such expenses for Executive, all in advance of the final disposition of any such matter.
(h) Termination during the Post-Change Period or Post-Significant Acquisition Period: Directors’ and Officers’ Liability Insurance. For a period of six years after the Termination Date (or for any known longer applicable statute of limitations period), the Company shall provide Executive with coverage under a directors’ and officers’ liability insurance policy in an amount no less than, and on terms
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no less favorable than, those provided to senior executive officers and directors of the Company on the Applicable Trigger Date.
4.2 Termination During an Imminent Control Change Period. If, during an Imminent Control Change Period, Executive has a Termination of Employment that would entitle Executive to benefits under Section 4 of the Exelon Corporation Senior Management Severance Plan or its successor, then the Company shall, prior to the occurrence of a Change Date, provide Executive any benefits to which Executive may be entitled under Section 4 of the Exelon Corporation Senior Management Severance Plan or its successor. If, during an Imminent Control Change Period, the Employer terminates Executive’s employment other than for Disability and other than for Cause, or if Executive terminates employment for Good Reason then subject to the preceding sentence, unless such Termination of Employment occurred during the Post-Significant Acquisition Period, the Company’s sole obligations to Executive under Articles II and IV shall be as set forth in this Section 4.2. The Company’s obligations to Executive under this Section 4.2 shall be reduced by any amounts or benefits paid or provided pursuant to the Exelon Corporation Senior Management Severance Plan (whether under Section 4 thereof or any other provision) or any successor thereto. If Executive’s Termination of Employment occurred during any portion of an Imminent Control Change Period that is also a Post-Significant Acquisition Period, the Company’s obligations to Executive, if any, shall be determined under Section 4.1.
(a) Termination During an Imminent Control Change Period: Cash Severance Payments. If the Imminent Control Change Period culminates in a Change Date, the Company shall pay (or cause to be paid) to Executive, a lump-sum cash amount, within thirty business days after the later of the Termination Date or the Change Date, equal to the sum of all amounts described in Section 4.1(a)(i) through (v). The amount described in Section 4.1(a)(vi) shall be paid to Executive as described in Section 4.4, provided that amounts that would have been paid prior to the Change Date shall be paid in a lump sum (without interest) within 30 business days after the Change Date.
(b) Termination During an Imminent Control Change Period: Vested Stock Options. Executive’s Stock Options, to the extent vested on the Termination Date,
(i) will not expire (unless such Stock Options would have expired had Executive remained an employee of the Company) during the Imminent Control Change Period; and
(ii) will continue to be exercisable after the Termination Date to the extent provided in the applicable grant agreement or Plan, and thereafter, such Stock Options shall not be exercisable during the Imminent Control Change Period.
If the Imminent Control Change Period lapses without a Change Date, then Executive’s Stock Options, to the extent vested on the Termination Date, may be exercised, in whole or in part, during the 30-day period following the lapse of the Imminent Control Change Period, or, if longer, the period during which Executive’s vested Stock Options could otherwise be exercised under the terms of the applicable grant agreement or Plan, (but in
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no case shall any Stock Options remain exercisable after the date on which such Stock Options would have expired if Executive had remained an employee of the Company).
If the Imminent Control Change Period culminates in a Change Date, then effective upon the Change Date, Executive’s Stock Options, to the extent vested on the Termination Date, may be exercised in whole or in part by the Executive at any time until (1) the option expiration date for such Stock Options granted prior to January 1, 2002 or (2) the earlier of the fifth anniversary of the Change Date or the option expiration date for such Stock Options granted on or after January 1, 2002.
(c) Termination During an Imminent Control Change Period: Unvested Stock Options. Executive’s Stock Options that are not vested on the Termination Date
(i) will not expire (unless such Stock Options would have expired had Executive remained an employee of the Company) during the Imminent Control Change Period; and
(ii) will not continue to vest and will not be exercisable during the Imminent Control Change Period after the expiration of the period for post-termination exercise under the terms of the applicable Stock Option Agreement.
If the Imminent Control Change lapses without a Change Date, such unvested Stock Options will thereupon expire.
If the Imminent Control Change culminates in a Change Date, then immediately prior to the Change Date, such unvested Stock Options shall become fully vested, and may thereupon be exercised in whole or in part by the Executive at any time until (1) the option expiration date for such Stock Options granted prior to January 1, 2002 or (2) the earlier of the fifth anniversary of the Change Date, or the option expiration date for such Stock Options granted on or after January 1, 2002.
(d) Termination During an Imminent Control Change Period: Performance Shares. Executive’s Performance Shares granted under the Exelon Performance Share Program under the LTIP will not be forfeited during the Imminent Control Change Period, and will not continue to vest during the Imminent Control Change Period. If the Imminent Control Change lapses without a Change Date, such Performance Shares shall be governed according to the terms of Section 4 of the Exelon Corporation Senior Management Severance Plan. If the Imminent Control Change Period culminates in a Change Date:
(1) All Performance Shares granted to the Executive under the Exelon Performance Share Program under the LTIP, which, as of the Termination Date, have been earned by and awarded to the Executive, shall become fully vested at the actual earned level on the Change Date, and
(2) All of the Performance Shares granted to the Executive under the Exelon Performance Share Program under the LTIP which, as of
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the Termination Date, have not been earned by and awarded to the Executive shall become fully vested on the Change Date at the LTIP Target Level.
(e) Termination During an Imminent Control Change Period: Restricted Stock. Executive’s unvested Restricted Stock will:
(i) not be forfeited during the Imminent Control Change Period; and
(ii) not continue to vest during the Imminent Control Change Period.
If the Imminent Control Change Period lapses without a Change Date, such unvested Restricted Stock shall thereupon be forfeited.
If the Imminent Control Change Period culminates in a Change Date, then immediately prior to the Change Date, Executive’s Restricted Stock shall (except as specifically provided to the contrary in the award) become fully vested, and within ten business days after the Change Date, the Company shall deliver to Executive all of such shares theretofore held by or on behalf of the Company, which will be subject to the same terms which other stockholders of the Company receive in the transaction.
(f) Termination During an Imminent Control Change Period: Continuation of Welfare Benefits. The Company shall continue to provide to Executive and Executive’s family welfare benefits (other than any severance pay that may be considered a welfare benefit) during the Imminent Change Period which are at least as favorable as welfare benefits under the most favorable Welfare Plans of the Company applicable with respect to peer executives who are actively employed after the Termination Date and their families; subject to the following:
(i) In determining benefits applicable under such Welfare Plans, the Executive’s annual compensation attributable to base salary and incentives for any plan year or calendar year, as applicable, shall be deemed to be not less than the Executive’s Base Salary and Annual Incentive;
(ii) The cost of such welfare benefits to Executive and family under this Section 4.2(f) shall not exceed the cost of such benefits to peer executives who are actively employed after the Termination Date.
(iii) Executive’s rights under this Section 4.2(f) shall be in addition to and not in lieu of any post-termination continuation coverage or conversion rights the Executive may have pursuant to applicable law, including, without limitation, continuation coverage required by Section 4980B of the Code.
If the Imminent Control Change Period lapses without a Change Date, welfare benefit plan coverage under this Section 4.2(f) shall thereupon cease, subject to Executive’s rights, if any, to continued coverage under a Welfare Plan, Section 4 of the Exelon Corporation Senior Management Severance Plan, or applicable law. If the Imminent Control Change Period culminates in a Change Date, then for the remainder of the
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Severance Period (and continuing through such later date as any Welfare Plan may specify), the Company shall continue to provide Executive and Executive’s family welfare benefits as described in, and subject to the limitations of Section 4.1(e).
Notwithstanding the foregoing, if the Executive obtains a specific type of coverage under welfare plan(s) sponsored by another employer of Executive (e.g. medical, prescription, vision, dental, disability, individual life insurance benefits, group life insurance benefits, but excluding for the purposes of this sentence retiree benefits if Executive is so eligible), then the Company shall not be obligated to provide such any specific type of coverage. The Executive shall immediately notify the Company of any such coverage.
(g) Termination During an Imminent Control Change Period: Outplacement. To the extent actually incurred by Executive, the Company shall pay or cause to be paid on behalf of Executive, as incurred, all reasonable fees and costs charged by a nationally recognized outplacement firm selected by the Executive for outplacement services provided up to 12 months after the Termination Date. No cash shall be paid in lieu of such fees and costs.
(h) Termination During an Imminent Control Change Period: Indemnification. The Executive shall be indemnified and held harmless by the Company to the same extent as provided in Section 4.1(g), but only during the Imminent Control Change Period (or greater period provided under the Company’s by-laws) if the Imminent Control Change Period lapses without a Change Date.
(i) Termination During an Imminent Control Change Period: Directors’ and Officers’ Liability Insurance. The Company shall provide the same level of directors’ and officers’ liability insurance for Executive as provided in Section 4.1(h), but only during the Imminent Control Change Period (or greater period provided under the Company’s by-laws) if the Imminent Control Change Period lapses without a Change Date.
4.3 Termination During a Post-Disaggregation Period. If, during a Post-Disaggregation Period the Disaggregated Entity terminates Executive’s employment other than for Cause or Disability, or if Executive terminates employment for Good Reason, the Company’s sole obligations to Executive under Articles II and IV shall be as set forth in this Section 4.3, subject to Section 3.3(c), but only to the extent not provided by the Disaggregated Entity.
(a) Termination During a Post-Disaggregation Period: Cash Severance Payments. The Company shall pay Executive the amounts described in Section 4.1(a), as provided in Section 4.4.
(b) Termination During a Post-Disaggregation Period: Stock Options. All of Executive’s Stock Options granted prior to the Disaggregation that have not expired, whether or not converted to options or stock of the Disaggregated Entity or Merger Survivor, shall be fully vested, and may be exercised in whole or in part by the Executive at any time until (1) the remaining option expiration date for such Stock Options granted prior to January 1, 2002 and (2) the earlier of the fifth anniversary of the Termination
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Date or the option expiration date for such Stock Options granted on or after January 1, 2002.
(c) Termination During a Post-Disaggregation Period: Performance Shares. Executive’s Performance Shares granted prior to the Disaggregation, whether or not earned by and awarded to the Executive as of the Disaggregation, and whether or not converted to performance shares of the Disaggregated Entity or the Merger Survivor, shall become fully vested (at the earned level for Performance Shares earned and awarded, and at the target level for any converted performance shares not yet earned and awarded) on the Termination Date.
(d) Termination During a Post-Disaggregation Period: Restricted Stock. Executive’s unvested Restricted Stock, whether or not converted to restricted stock of the Disaggregated Entity or Merger Survivor, shall become fully vested on the Termination Date.
(e) Termination During a Post-Disaggregation Period: Continuation of Welfare Benefits. Until the end of the Severance Period, the Company shall continue to provide to Executive and Executive’s family welfare benefits with the same rights in relation to continuation coverage, status in relation to other employer benefits, scope and cost as described in Section 4.1(e); provided that, to the extent Executive is eligible for post-termination continuation coverage under the plans of the Disaggregated Entity, whether pursuant to Section 4980B of the Code or otherwise, the continued coverage required hereunder shall be provided under the plans of the Disaggregated Entity (and the Company shall reimburse the cost to Executive of such coverage).
(f) Termination During a Post-Disaggregation Period: Outplacement. To the extent actually incurred by Executive, the Company shall pay or cause to be paid on behalf of Executive, as incurred, all reasonable fees and costs charged by a nationally recognized outplacement firm selected by the Executive for outplacement services provided up to 12 months after the Termination Date. No cash shall be paid in lieu of such fees and costs.
(g) Termination During a Post-Disaggregation Period: Indemnification. The Executive shall be indemnified and held harmless by the Company to the same extent as provided in Section 4.1(g).
(h) Termination During a Post-Disaggregation Period: Directors’ and Officers’ Liability Insurance. The Company shall provide Executive with directors’ and officers’ liability insurance to the same extent as provided in Section 4.1(h).
4.4 Timing of Severance Payments. Unless otherwise specified herein, the amounts described in Sections 4.1(a)(i), (ii), (iii), (iv) and (v) shall be paid within 30 business days of the Termination Date. The severance payments described in Section 4.1(a)(vi) shall be paid as follows:
(a) Beginning no later than the second paydate which occurs after the Termination Date, the Company shall make periodic payments to the Executive
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according to the Company’s normal payroll practices at a monthly rate equal to 1/12 of the sum of (i) the Executive’s Base Salary in effect as of the Termination Date plus (ii) the Severance Incentive; and
(b) Within 30 business days of the second anniversary of the Termination Date, the Company shall pay Executive a cash lump sum equal to the difference between the total Severance Payment less the total amount paid pursuant to normal payroll practices under Section 4.4(a).
4.5 Waiver and Release. Notwithstanding anything herein to the contrary, the Company shall have no obligation to Executive under Article IV or Article V unless and until Executive executes a release and waiver of Company and its Affiliates, in substantially the same form as attached hereto as Exhibit A, or as otherwise mutually acceptable.
4.6 Breach of Covenants. If a court determines that Executive has breached any non-competition, non-solicitation, confidential information or intellectual property covenant entered into between Executive and Company, the Company shall not be obligated to pay or provide any severance or benefits under Articles IV or V, all unexercised Stock Options shall terminate as of the date of the breach, and all Restricted Stock shall be forfeited as of the date of the breach.
4.7 Termination by the Company for Cause. If the Company (or Affiliate or, if applicable, the Disaggregated Entity) terminates Executive’s employment for Cause during the Post-Change Period, the Imminent Control Change Period, the Post-Significant Acquisition Period, or the Post-Disaggregation Period, the Company’s sole obligation to Executive under Articles II, IV, and V shall be to pay Executive, pursuant to the Company’s then-effective Plans, a lump-sum cash amount equal to all Accrued Obligations determined as of the Termination Date. The remaining applicable provisions of this Agreement (including the restrictive covenants in Article VIII) shall continue to apply.
4.8 Termination by Executive Other Than for Good Reason. If Executive elects to retire or otherwise terminate employment during the Post-Change Period, the Imminent Control Change Period, the Post-Significant Acquisition Period, or the Post-Disaggregation Period, other than for Good Reason, Disability or death, the Company’s sole obligation to Executive under Articles II, IV, and V shall be to pay Executive, pursuant to the Company’s then-effective Plans, a lump-sum cash amount equal to all Accrued Obligations determined as of the Termination Date. The remaining provisions of this Agreement (including the restrictive covenants in Article VIII) shall continue to apply.
4.9 Termination by the Company for Disability. If the Company (or Disaggregated Entity, if applicable) terminates Executive’s employment by reason of Executive’s Disability during a Post-Change Period, Imminent Control Change Period that culminates in a Change Date, Post-Significant Acquisition Period or Post-Disaggregation Period, the Company’s sole obligation to Executive under Articles II, IV, and V shall be as follows, and such obligations shall be reduced by amounts paid or provided by the Disaggregated Entity:
(a) to pay Executive, a lump-sum cash amount equal to the sum of amounts specified in Section 4.1(a)(i), (ii) and (iii) determined as of the Termination Date, and
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(b) to provide Executive disability and other benefits after the Termination Date that are not less than the most favorable of such benefits then available under Plans of the Company to disabled peer executives of the Company in effect immediately before the Termination Date.
The remaining provisions of this Agreement (including the restrictive covenants in Article VIII) shall continue to apply.
4.10 Upon Death. If Executive’s employment is terminated by reason of Executive’s death during a Post-Change Period, Imminent Control Change Period that culminates in a Change Date, Post-Significant Acquisition Period or Post-Disaggregation Period, the Company’s sole obligations to Executive and Executive’s Beneficiary under Articles II, IV, and V shall be as follows, and such obligations shall be reduced by amounts paid or provided by the Disaggregated Entity:
(a) to pay Executive’s Beneficiary, pursuant to the Company’s then-effective Plans, a lump-sum cash amount equal to all Accrued Obligations; and
(b) to provide Executive’s Beneficiary survivor and other benefits that are not less than the most favorable of such benefits then available under Plans of the Company to surviving families of peer executives of the Company in effect immediately before the Executive’s death, including retiree health care coverage under any Welfare Plan of the Company that provides such coverage without regard to whether the Executive had satisfied the eligibility requirements for such coverage as of the date of her death.
4.11 Sole and Exclusive Obligations. The obligations of the Company under this Agreement, as amended and restated effective May 1, 2004, with respect to any Termination of Employment of the Executive during the Post-Change Period, Imminent Control Change Period, Post-Significant Acquisition Period, or Post-Disaggregation Period shall, except as provided in Section 4.2, supersede any severance obligations of the Company in any other plan of the Company or agreement between Executive and the Company, including, without limitations, the Exelon Corporation Senior Management Severance Plan under Section 4 or any other provision thereof, or any other plan or agreement (including an offer of employment or employment contract) of the Company or any Affiliates which provides for severance benefits. In the event of any inconsistency, ambiguity or conflict between the terms of such other plan of the Company or agreement between Executive and the Company and this Agreement with respect to any severance obligations of the Company (other than obligations with respect to credited service under the SERP in any agreement other than a prior Change in Control Agreement entered into by and among Executive, Unicom Corporation, Commonwealth Edison Company or PECO Energy Company), this Agreement shall govern.
Article V.
Certain Additional Payments by the Company
5.1 Gross-Up Payment. If at any time or from time to time, it shall be determined by the Company’s independent auditors that any payment or other benefit to Executive pursuant to Article II or Article IV of this Agreement or otherwise (“Potential Parachute Payment”) is or will
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become subject to the excise tax imposed by Section 4999 of the Code or any similar tax payable under any United States federal, state, local, foreign or other law (“Excise Taxes”), then the Company shall, subject to Section 5.2, pay or cause to be paid a tax gross-up payment (“Gross-Up Payment”) with respect to all such Excise Taxes and other Taxes on the Gross-Up Payment. The Gross-Up Payment shall be an amount equal to the product of
(a) The amount of the Excise Taxes (calculated at the effective marginal rates of all federal, state, local, foreign or other law), multiplied by
(b) A fraction (the “Gross-Up Multiple”), the numerator or which is one (1.0), and the denominator of which is one (1.0) minus the lesser of (i) the sum, expressed as a decimal fraction, of the effective marginal rates of any Taxes and any Excise Taxes applicable to the Gross-Up Payment or (ii) .80, it being intended that the Gross-Up Multiple shall in no event exceed five (5.0). If different rates of tax are applicable to various portions of a Gross-Up Payment, the weighted average of such rates shall be used. For purposes of this Section, Executive shall be deemed to be subject to the highest effective marginal rate of Taxes.
The Gross-Up Payment is intended to compensate Executive for all such Excise Taxes and any other Taxes payable by Executive with respect to the Gross-Up Payment. The Company shall pay or cause to be paid the Gross–Up Payment to Executive within thirty (30) days of the calculation of such amount, but in no event after the Executive makes payment to the IRS of such Excise Taxes.
5.2 Limitation on Gross-Up Payments.
(a) To the extent possible, any payments or other benefits to Executive pursuant to Article II and Article IV of this Agreement shall be allocated as consideration for Executive’s entry into the covenants of Article VIII.
(b) Notwithstanding any other provision of this Article V, if the aggregate amount of the Potential Parachute Payments that, but for this Section 5.2, would be payable to Executive, does not exceed 110% of Floor Amount (as defined below), then no Gross-Up Payment shall be made to Executive and the aggregate amount of Potential Parachute Payments payable to Executive shall be reduced (but not below the Floor Amount) to the largest amount which would both (i) not cause any Excise Tax to be payable by Executive and (ii) not cause any Potential Parachute Payments to become nondeductible by the Company by reason of Section 280G of the Code (or any successor provision). For purposes of the preceding sentence, “Floor Amount” means the greatest pre-tax amount of Potential Parachute Payments that could be paid to Executive without causing Executive to become liable for any Excise Taxes in connection therewith.
5.3 Additional Gross-up Amounts. If, for any reason (whether pursuant to subsequently enacted provisions of the Code, final regulations or published rulings of the IRS, or a final judgment of a court of competent jurisdiction) the Company’s independent auditors later
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determine that the amount of Excise Taxes payable by Executive is greater than the amount initially determined pursuant to Section 5.1, then the Company shall, subject to Sections 5.2 and 5.4, pay Executive, within thirty (30) days of such determination, or pay to the IRS as required by applicable law, an amount (which shall also be deemed a Gross-Up Payment) equal to the product of:
(a) the sum of (i) such additional Excise Taxes and (ii) any interest, penalties, expenses or other costs incurred by Executive as a result of having taken a position in accordance with a determination made pursuant to Section 5.1 or 5.4, multiplied by
(b) the Gross-Up Multiple.
5.4 Amount Increased or Contested.
(a) Executive shall notify the Company in writing (an “Executive’s Notice”) of any claim by the IRS or other taxing authority (an “IRS Claim”) that, if successful, would require the payment by Executive of Excise Taxes in respect of Potential Parachute Payments in an amount in excess of the amount of such Excise Taxes determined in accordance with Section 5.1. Executive’s Notice shall include the nature and amount of such IRS Claim, the date on which such IRS Claim is due to be paid (the “IRS Claim Deadline”), and a copy of all notices and other documents or correspondence received by Executive in respect of such IRS Claim. Executive shall give the Executive’s Notice as soon as practicable, but no later than the earlier of (i) 10 days after Executive first obtains actual knowledge of such IRS Claim or (ii) five days before the IRS Claim Deadline; provided, however, that any failure to give such Executive’s Notice shall affect the Company’s obligations under this Article only to the extent that the Company is actually prejudiced by such failure. If at least one business day before the IRS Claim Deadline the Company shall:
(i) deliver to Executive a written certificate from the Company’s independent auditors (“Company Certificate”) to the effect that, notwithstanding the IRS Claim, the amount of Excise Taxes, interest or penalties payable by Executive is either zero or an amount less than the amount specified in the IRS Claim,
(ii) pay to Executive, or to the IRS as required by applicable law, an amount (which shall also be deemed a Gross-Up Payment) equal to difference between the product of (A) amount of Excise Taxes, interest and penalties specified in the Company Certificate, if any, multiplied by (B) the Gross-Up Multiple, less the portion of such product, if any, previously paid to Executive by the Company, and
(iii) direct Executive pursuant to Section 5.4(d) to contest the balance of the IRS Claim,
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then Executive shall pay only the amount, if any, of Excise Taxes, interest and penalties specified in the Company Certificate. In no event shall Executive pay an IRS Claim earlier than 30 business days after having given an Executive’s Notice to the Company (or, if sooner, the IRS Claim Deadline).
(b) At any time after the payment by Executive of any amount of Excise Taxes, other Taxes or related interest or penalties in respect of Potential Parachute Payments (including any such amount equal to or less than the amount of such Excise Taxes specified in any Company Certificate, or IRS Claim), the Company may in its discretion require Executive to pursue a claim for a refund (a “Refund Claim”) of all or any portion of such Excise Taxes, other Taxes, interest or penalties as may be specified by the Company in a written notice to Executive.
(c) If the Company notifies Executive in writing that the Company desires Executive to contest an IRS Claim or to pursue a Refund Claim, Executive shall:
(i) give the Company all information that it reasonably requests in writing from time to time relating to such IRS Claim or Refund Claim, as applicable,
(ii) take such action in connection with such IRS Claim or Refund Claim (as applicable) as the Company reasonably requests in writing from time to time, including accepting legal representation with respect thereto by an attorney selected by the Company, subject to the approval of Executive (which approval shall not be unreasonably withheld or delayed),
(iii) cooperate with the Company in good faith to contest such IRS Claim or pursue such Refund Claim, as applicable,
(iv) permit the Company to participate in any proceedings relating to such IRS Claim or Refund Claim, as applicable, and
(v) contest such IRS Claim or prosecute Refund Claim (as applicable) to a determination before any administrative tribunal, in a court of initial jurisdiction and in one or more appellate courts, as the Company may from time to time determine in its discretion.
The Company shall control all proceedings in connection with such IRS Claim or Refund Claim (as applicable) and in its discretion may cause Executive to pursue or forego any and all administrative appeals, proceedings, hearings and conferences with the Internal Revenue Service or other taxing authority in respect of such IRS Claim or Refund Claim (as applicable); provided that (i) any extension of the statute of limitations relating to payment of taxes for the taxable year of Executive relating to the IRS Claim is limited solely to such IRS Claim, (ii) the Company’s control of the IRS Claim or Refund Claim (as applicable) shall be limited to issues with respect to which a Gross-Up Payment would be payable, and (iii) Executive shall be entitled to settle or contest, as the case may be, any other issue raised by the Internal Revenue Service or other taxing authority.
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(d) The Company may at any time in its discretion direct Executive to (i) contest the IRS Claim in any lawful manner or (ii) pay the amount specified in an IRS Claim and pursue a Refund Claim; provided, however, that if the Company directs Executive to pay an IRS Claim and pursue a Refund Claim, the Company shall advance the amount of such payment to Executive on an interest-free basis and shall indemnify Executive, on an after-tax basis, for any Excise Tax or income tax, including related interest or penalties, imposed with respect to such advance.
(e) The Company shall pay directly all legal, accounting and other costs and expenses (including additional interest and penalties) incurred by the Company or Executive in connection with any IRS Claim or Refund Claim, as applicable, and shall indemnify Executive, on an after-tax basis, for any Excise Tax or income tax, including related interest and penalties, imposed as a result of such payment of costs and expenses.
5.5 Refunds. If, after the receipt by Executive or the IRS of any payment or advance of Excise Taxes or other Taxes by the Company pursuant to this Article, Executive receives any refund with respect to such Excise Taxes, Executive shall (subject to the Company’s complying with any applicable requirements of Section 5.4) promptly pay the Company the amount of such refund (together with any interest paid or credited thereon after taxes applicable thereto). If, after the receipt by Executive of an amount advanced by the Company pursuant to Section 5.4 or receipt by the IRS of an amount paid by the Company on behalf of the Executive pursuant to Section 5.4, a determination is made that Executive shall not be entitled to any refund with respect to such claim and the Company does not notify Executive in writing of its intent to contest such determination within 30 days after the Company receives written notice of such determination, then such advance shall be forgiven and shall not be required to be repaid and the amount of such advance shall offset, to the extent thereof, the amount of Gross-Up Payment required to be paid. Any contest of a denial of refund shall be controlled by Section 5.4(d).
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Article VI.
Expenses, Interest and Dispute Resolution
6.1 Enforcement and Late Payments.
(a) If, after the Agreement Date, Executive incurs reasonable legal fees or other expenses (including arbitration costs and expenses under Section 6.3) in an effort to secure, preserve, or obtain benefits under this Agreement, the Company shall, regardless of the outcome of such effort, reimburse Executive (in accordance with Section 6.1(b)) for such fees and expenses.
(b) Reimbursement of legal fees and expenses and gross-up payments shall be made on a current basis, promptly after Executive’s written submission of a request for reimbursement together with evidence that such fees and expenses were incurred.
(c) If Executive does not prevail (after exhaustion of all available judicial remedies) in respect of a claim by Executive or by the Company hereunder, and the Company establishes before a court of competent jurisdiction by clear and convincing evidence that Executive had no reasonable basis for Executive’s claim hereunder, or for Executive’s response to the Company’s claim hereunder, or that Executive acted in bad faith, no further reimbursement for legal fees and expenses shall be due to Executive in respect of such claim and Executive shall refund any amounts previously reimbursed hereunder with respect to such claim.
6.2 Interest. If the Company does not pay any cash amount due to Executive under this Agreement within three business days after such amount first became due and owing, interest shall accrue on such amount from the date it became due and owing until the date of payment at an annual rate equal to 200 basis points above the base commercial lending rate published in The Wall Street Journal in effect from time to time during the period of such nonpayment; provided that the Executive shall not be entitled to interest on any Gross Up Payment.
6.3 Arbitration. Any dispute, controversy or claim between the parties hereto arising out of or in connection with or relating to this Agreement (other than disputes related to Article V or to an alleged breach of the covenant contained in Article VIII) or any breach or alleged breach thereof, or any benefit or alleged benefit hereunder, shall be settled by arbitration in Chicago, Illinois, before an impartial arbitrator pursuant to the rules and regulations of the American Arbitration Association (“AAA”) pertaining to the arbitration of labor disputes. Either party may invoke the right to arbitration. The arbitrator shall be selected by means of the parties striking alternatively from a panel of seven arbitrators supplied by the Chicago office of AAA. The arbitrator shall have the authority to interpret and apply the provisions of this Agreement, consistent with Section 10.11 below. The decision of the arbitrator shall be final and binding upon the parties and a judgment thereon may be entered in the highest court of a forum, state or federal, having jurisdiction. The expenses of the arbitration shall be borne according to Section
35
6.1. No arbitration shall be commenced after the date when institution of legal or equitable proceedings based upon such subject matter would be barred by the applicable statutes of limitations. Notwithstanding anything to the contrary contained in this Section 6.3 or elsewhere in this Agreement, either party may bring an action in the District Court of Cook County, or the United States District Court for the Northern District of Illinois, if jurisdiction there lies, in order to maintain the status quo ante of the parties. The “status quo ante” is defined as the last peaceable, uncontested status between the parties. However, neither the party bringing the action nor the party defending the action thereby waives its right to arbitration of any dispute, controversy or claim arising out of or in connection or relating to this Agreement. Notwithstanding anything to the contrary contained in this Section 6.3 or elsewhere in this Agreement, either party may seek relief in the form of specific performance, injunctive or other equitable relief in order to enforce the decision of the arbitrator. The parties agree that in any arbitration commenced pursuant to this Agreement, the parties shall be entitled to such discovery (including depositions, requests for the production of documents and interrogatories) as would be available in a federal district court pursuant to Rules 26 through 37 of the Federal Rules of Civil Procedure. In the event that either party fails to comply with its discovery obligations hereunder, the arbitrator shall have full power and authority to compel disclosure or impose sanctions to the full extent of Rule 37 of the Federal Rules of Civil Procedure.
Article VII.
No Set-off or Mitigation
7.1 No Set-off by Company. Executive’s right to receive when due the payments and other benefits provided for under this Agreement is absolute, unconditional and subject to no setoff, counterclaim or legal or equitable defense; provided, however that the Company shall have no further obligation to pay or provide severance benefits under Article II, Article IV or Article V if at any time it determines, in accordance with the procedural requirements in Section 3.3, that in the course of his employment the Executive engaged in conduct described in Section 3.3(a)(iii) or the last clause of Section 3.3(a)(iv). Time is of the essence in the performance by the Company of its obligations under this Agreement. Any claim which the Company may have against Executive, whether for a breach of this Agreement or otherwise, shall be brought in a separate action or proceeding and not as part of any action or proceeding brought by Executive to enforce any rights against the Company under this Agreement.
7.2 No Mitigation. Executive shall not have any duty to mitigate the amounts payable by the Company under this Agreement by seeking new employment or self-employment following termination. Except as specifically otherwise provided in this Agreement, all amounts payable pursuant to this Agreement shall be paid without reduction regardless of any amounts of salary, compensation or other amounts which may be paid or payable to Executive as the result of Executive’s employment by another unaffiliated employer or self-employment.
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Article VIII.
Restrictive Covenants
8.1 Confidential Information. The Executive acknowledges that in the course of performing services for the Companies and Affiliates, she may create (alone or with others), learn of, have access to and receive Confidential Information. Confidential Information shall not include: (i) information that is or becomes generally known through no fault of Executive; (ii) information received from a third party outside of the Company that was disclosed without a breach of any confidentiality obligation; or (iii) information approved for release by written authorization of the Company. The Executive recognizes that all such Confidential Information is the sole and exclusive property of the Company and its Affiliates or of third parties which the Company or Affiliate is obligated to keep confidential, that it is the Company’s policy to keep all such Confidential Information confidential, and that disclosure of Confidential Information would cause damage to the Company and its Affiliates. The Executive agrees that, except as required by the duties of Executive’s employment with the Company or any of its Affiliates and except in connection with enforcing the Executive’s rights under this Agreement or if compelled by a court or governmental agency, in each case provided that prior written notice is given to Company, Executive will not, without the written consent of Company, willfully disseminate or otherwise disclose, directly or indirectly, any Confidential Information obtained during her employment with the Company or its Affiliates, and will take all necessary precautions to prevent disclosure, to any unauthorized individual or entity inside or outside the Company, and will not use the Confidential Information or permit its use for the benefit of Executive or any other person or entity other than the Company or its Affiliates. These obligations shall continue during and after the termination of Executive’s employment (whether or not after a Change in Control, Imminent Control Change, Significant Acquisition or Disaggregation).
8.2 Non-Competition. During the period beginning on the Agreement Date and ending on the second anniversary of the Termination Date, whether or not after a Change in Control, Imminent Control Change, Significant Acquisition or Disaggregation, Executive hereby agrees that without the written consent of the Company Executive shall not at any time, directly or indirectly, in any capacity:
(a) engage or participate in, become employed by, serve as a director of, or render advisory or consulting or other services in connection with, any Competitive Business; provided, however, that after the Termination Date this Section 8.2 shall not preclude Executive from being an employee of, or consultant to, any business unit of a Competitive Business if (i) such business unit does not qualify as a Competitive Business in its own right and (ii) Executive does not have any direct or indirect involvement in, or responsibility for, any operations of such Competitive Business that cause it to qualify as a Competitive Business.
(b) make or retain any financial investment, whether in the form of equity or debt, or own any interest, in any Competitive Business. Nothing in this subsection shall, however, restrict Executive from making an investment in any Competitive Business if such investment does not (i) represent more than 1% of the aggregate market value of the outstanding capital stock or debt (as applicable) of such Competitive Business, (ii) give
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| Executive any right or ability, directly or indirectly, to control or influence the policy decisions or management of such Competitive Business, and (iii) create a conflict of interest between Executive’s duties under this Agreement and her interest in such investment. |
8.3 Non-Solicitation. During the period beginning on the Agreement Date and ending on the second anniversary of any Termination Date, whether or not after a Change in Control, Imminent Control Change, Significant Acquisition or Disaggregation, Executive shall not, directly or indirectly:
(a) other than in connection with the good-faith performance of her duties as an officer of the Company, cause or attempt to cause any employee or agent of the Company to terminate her relationship with the Company;
(b) employ, engage as a consultant or adviser, or solicit the employment or engagement as a consultant or adviser, of any employee or agent of the Company (other than by the Company or its Affiliates), or cause or attempt to cause any Person to do any of the foregoing;
(c) establish (or take preliminary steps to establish) a business with, or cause or attempt to cause others to establish (or take preliminary steps to establish) a business with, any employee or agent of the Company, if such business is or will be a Competitive Business; or
(d) interfere with the relationship of the Company with, or endeavor to entice away from the Company, any Person who or which at any time during the period commencing one year prior to the Termination Date was or is, to the Executive’s knowledge, a material customer or material supplier of, or maintained a material business relationship with, the Company.
8.4 Intellectual Property. During the period of Executive’s employment with the Company and any Affiliate, and thereafter upon the Company’s request, whether or not after a Change in Control, Imminent Control Change, Significant Acquisition or Disaggregation, Executive shall disclose immediately to the Company all ideas, inventions and business plans that she makes, conceives, discovers or develops alone or with others during the course of her employment with the Company or during the one year period following Executive’s Termination Date, including any inventions, modifications, discoveries, developments, improvements, computer programs, processes, products or procedures (whether or not protectable upon application by copyright, patent, trademark, trade secret or other proprietary rights) (“Work Product”) that: (i) relate to the business of the Company or any customer or supplier to the Company or any of the products or services being developed, manufactured, sold or otherwise provided by the Company or that may be used in relation therewith; or (ii) result from tasks assigned to Executive by the Company; or (iii) result from the use of the premises or personal property (whether tangible or intangible) owned, leased or contracted for by the Company. Executive agrees that any Work Product shall be the property of the Company and, if subject to copyright, shall be considered a “work made for hire” within the meaning of the Copyright Act of 1976, as amended (the “Act”). If and to the extent that any such Work Product is not a “work
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made for hire” within the meaning of the Act, Executive hereby assigns to the Company all right, title and interest in and to the Work Product, and all copies thereof, and the copyright, patent, trademark, trade secret and all proprietary rights in the Work Product, without further consideration, free from any claim, lien for balance due or rights of retention thereto on the part of Executive.
(a) The Company hereby notifies Executive that the preceding paragraph does not apply to any inventions for which no equipment, supplies, facility, or trade secret information of the Company was used and which was developed entirely on the Executive’s own time, unless: (i) the invention relates (a) to the Company’s business, or (b) to the Company’s actual or demonstrably anticipated research or development, or (ii) the invention results from any work performed by the Executive for the Company.
(b) Executive agrees that upon disclosure of Work Product to the Company, Executive will, during her employment and at any time thereafter, at the request and cost of the Company, execute all such documents and perform all such acts as the Company or its duly authorized agents may reasonably require: (i) to apply for, obtain and vest in the name of the Company alone (unless the Company otherwise directs) letters patent, copyrights or other analogous protection in any country throughout the world, and when so obtained or vested to renew and restore the same; and (ii) to prosecute or defend any opposition proceedings in respect of such applications and any opposition proceedings or petitions or applications for revocation of such letters patent, copyright or other analogous protection, or otherwise in respect of the Work Product.
(c) In the event that the Company is unable, after reasonable effort, to secure Executive’s execution as provided in subsection (b) above, whether because of Executive’s physical or mental incapacity or for any other reason whatsoever, Executive hereby irrevocably designates and appoints the Company and its duly authorized officers and agents as her agent and attorney-in-fact, to act for and on her behalf to execute and file any such application or applications and to do all other lawfully permitted acts to further the prosecution, issuance and protection of letters patent, copyright and other intellectual property protection with the same legal force and effect as if personally executed by Executive.
8.5 Reasonableness of Restrictive Covenants.
(a) Executive acknowledges that the covenants contained in Sections 8.1, 8.2, 8.3 and 8.4 are reasonable in the scope of the activities restricted, the geographic area covered by the restrictions, and the duration of the restrictions, and that such covenants are reasonably necessary to protect the Company’s legitimate interests in its Confidential Information and in its relationships with its employees, customers and suppliers. Executive further acknowledges such covenants are essential elements of this Agreement and that, but for such covenants, the Company would not have entered into this Agreement.
(b) The Company and Executive have each consulted with their respective legal counsel and have been advised concerning the reasonableness and propriety of such
39
covenants. Executive acknowledges that her observance of the covenants contained in Sections 8.1, 8.2, 8.3 and 8.4 will not deprive Executive of the ability to earn a livelihood or to support her dependents.
8.6 Right to Injunction; Survival of Undertakings.
(a) In recognition of the confidential nature of the Confidential Information, and in recognition of the necessity of the limited restrictions imposed by Sections 8.1, 8.2, 8.3 and 8.4 the parties agree that it would be impossible to measure solely in money the damages which the Company would suffer if Executive were to breach any of her obligations under such Sections. Executive acknowledges that any breach of any provision of such Sections would irreparably injure the Company. Accordingly, Executive agrees that if she breaches any of the provisions of such Sections, the Company shall be entitled, in addition to any other remedies to which the Company may be entitled under this Agreement or otherwise, to an injunction to be issued by a court of competent jurisdiction, to restrain any breach, or threatened breach, of such provisions, and Executive hereby waives any right to assert any claim or defense that the Company has an adequate remedy at law for any such breach.
(b) If a court determines that any of the covenants included in this Article VIII is unenforceable in whole or in part because of such covenant’s duration or geographical or other scope, such court shall have the power to modify the duration or scope of such provision, as the case may be, so as to cause such covenant as so modified to be enforceable.
(c) All of the provisions of this Article VIII shall survive any Termination of Employment without regard to (i) the reasons for such termination or (ii) the expiration of the Agreement Term.
(d) The Company shall have no further obligation to pay or provide severance or benefits under Article II, Article IV, or Article V if a court determines that the Executive has breached any covenant in this Article VIII.
Article IX.
Non-Exclusivity of Rights
9.1 Other Rights. Except as expressly provided in Section 4.11 or elsewhere in this Agreement, this Agreement shall not prevent or limit Executive’s continuing or future participation in any benefit, bonus, incentive or other Plans provided by the Company and for which Executive may qualify, nor shall this Agreement limit or otherwise affect such rights as Executive may have under any other agreements with the Company. Amounts which are vested benefits or which Executive is otherwise entitled to receive under any Plan and any other payment or benefit required by law at or after the Termination Date shall be payable in accordance with such Plan or applicable law except as expressly modified by this Agreement.
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9.2 No Right to Continued Employment. Nothing in this Agreement shall guarantee the right of Executive to continue in employment, and the Company retains the right to terminate the Executive’s employment at any time for any reason or for no reason.
Article X.
Miscellaneous
10.1 No Assignability. This Agreement is personal to Executive and without the prior written consent of the Company shall not be assignable by Executive otherwise than by will or the laws of descent and distribution. This Agreement shall inure to the benefit of and be enforceable by Executive’s legal representatives.
10.2 Successors. This Agreement shall inure to the benefit of and be binding upon the Company and its successors and assigns. The Company will require any successor (whether direct or indirect, by purchase, merger, consolidation or otherwise) to all or substantially all of the business or assets of the Company to assume expressly and agree to perform this Agreement in the same manner and to the same extent that the Company would be required to perform it if no such succession had taken place. Any successor to the business or assets of the Company which assumes or agrees to perform this Agreement by operation of law, contract, or otherwise shall be jointly and severally liable with the Company under this Agreement as if such successor were the Company.
10.3 Affiliates. To the extent that immediately prior to the Applicable Trigger Date, the Executive has been on the payroll of, and participated in the incentive or employee benefit plans of, an Affiliate of the Company, the references to the Company contained in Sections 2.8(a)(i) through (vii) and the other Sections of this Agreement referring to benefits to which the Executive may be entitled shall be read to refer to such Affiliate.
10.4 Payments to Beneficiary. If Executive dies before receiving amounts to which Executive is entitled under this Agreement, such amounts shall be paid in a lump sum to one or more beneficiaries designated in writing by Executive (each, a “Beneficiary”). If none is so designated, the Executive’s estate shall be her Beneficiary.
10.5 Non-Alienation of Benefits. Benefits payable under this Agreement shall not be subject in any manner to anticipation, alienation, sale, transfer, assignment, pledge, encumbrance, charge, garnishment, execution or levy of any kind, either voluntary or involuntary, before actually being received by Executive, and any such attempt to dispose of any right to benefits payable under this Agreement shall be void.
10.6 Severability. If any one or more Articles, Sections or other portions of this Agreement are declared by any court or governmental authority to be unlawful or invalid, such unlawfulness or invalidity shall not serve to invalidate any Article, Section or other portion not so declared to be unlawful or invalid. Any Article, Section or other portion so declared to be unlawful or invalid shall be construed so as to effectuate the terms of such Article, Section or other portion to the fullest extent possible while remaining lawful and valid.
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10.7 Amendments. This Agreement shall not be amended or modified except by written instrument executed by the Company and Executive.
10.8 Notices. All notices and other communications under this Agreement shall be in writing and delivered by hand, by nationally-recognized delivery service that promises overnight delivery, or by first-class registered or certified mail, return receipt requested, postage prepaid, addressed as follows:
If to Executive, to Executive at her most recent home address on file with
the Company.
If to the Company:
Exelon Corporation
37th Floor
10 S. Dearborn Street
Chicago, Illinois 60603
Attention: S. Gary Snodgrass, Executive Vice President and Chief Human Resources Officer
Facsimile No.: (312) 394-5440
With copy to:
Pamela Baker, Esq.
Sonnenschein Nath & Rosenthal
8000 Sears Tower
Chicago, Illinois 60606
Facsimile No.: (312) 876-7934
or to such other address as either party shall have furnished to the other in writing. Notice and communications shall be effective when actually received by the addressee.
10.9 Joint and Several Liability. The Company and the Subsidiary shall be jointly and severally liable for the obligations of the Company, the Subsidiary, or the Employer hereunder.
10.10 Counterparts. This Agreement may be executed in two or more counterparts, each of which shall be deemed an original, but all of which together constitute one and the same instrument.
10.11 Governing Law. This Agreement shall be interpreted and construed in accordance with the laws of the State of Illinois, without regard to its choice of law principles.
10.12 Captions. The captions of this Agreement are not a part of the provisions hereof and shall have no force or effect.
10.13 Number and Gender. Wherever appropriate, the singular shall include the plural, the plural shall include the singular, and the masculine shall include the feminine.
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10.14 Tax Withholding. The Company may withhold from any amounts payable under this Agreement or otherwise payable to Executive any Taxes the Company determines to be appropriate under applicable law and may report all such amounts payable to such authority as is required by any applicable law or regulation.
10.15 No Waiver. Executive’s failure to insist upon strict compliance with any provision of this Agreement shall not be deemed a waiver of such provision or any other provision of this Agreement. A waiver of any provision of this Agreement shall not be deemed a waiver of any other provision, and any waiver of any default in any such provision shall not be deemed a waiver of any later default thereof or of any other provision.
10.16 Entire Agreement. This Agreement, as amended and restated effective May 1, 2004, contains the entire understanding of Company and Executive with respect to its subject matter.
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IN WITNESS WHEREOF, Executive and Exelon Corporation have executed this Change in Control Employment Agreement effective as day of May 1, 2004.
| EXECUTIVE | ||
| EXELON CORPORATION | ||
| By: | ||
| Title: |
||
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Exhibit 10.52
AMENDMENT NUMBER ONE
TO THE
EXELON CORPORATION
DEFERRED COMPENSATION PLAN
The Exelon Corporation Deferred Compensation Plan, effective January 1, 2001 (the “Plan”), is hereby amended, effective as of January 1, 2004, in the following respects:
| 1. | Section 4.4 is amended in its entirety to provide as follows: |
“4.4 Severance Benefit Elections. An individual who is an Eligible Employee with respect to a Plan Year and who becomes entitled to benefits under the Exelon Corporation Senior Management Severance Plan or another severance plan or other agreement with the Company then in effect with respect to such individual, shall defer the portion of such severance benefits representing base salary and annual incentive award in the manner (if any) provided in the applicable plan or agreement.”
| 2. | The first sentence of Section 4.7 is amended in its entirety to provide as follows: |
“An election under this Article IV with respect to any Plan Year shall become irrevocable on December 31 of the preceding Plan Year; provided, however, that a Participant may, to the extent permitted by the Plan Administrator, change his or her election with respect to the deferral of base salary under Section 4.2 during the Plan Year with respect to which it applies, but any such change shall be effective solely with respect to base salary earned after the effective date of such change.”
| 3. | The first sentence of Section 6.2 is amended in its entirety to provide as follows: |
“Except as otherwise provided in Section 6.3 or Section 6.4, the balance of a Participant’s accounts hereunder shall be paid or commence to be paid in accordance with the Section 6.1 commencing in the calendar quarter immediately following the first full calendar quarter to occur after the Participant’s termination of employment or, to the extent permitted by rules established by the Plan Administrator, April of the calendar year after the calendar year in which the Participant terminates employment.”
Executed effective as of January 1, 2004.
| EXELON CORPORATION | ||
| By: | /S/ S. GARY SNODGRASS | |
| S. Gary Snodgrass | ||
| Executive Vice President and | ||
| Chief Administrative Officer | ||
2
Exhibit 10.53
AMENDMENT NUMBER TWO
TO THE
EXELON CORPORATION
SUPPLEMENTAL MANAGEMENT RETIREMENT PLAN
The Exelon Corporation Supplemental Management Retirement Plan, as amended and restated, effective January 1, 1998, and as subsequently amended from time to time (the “Supplemental Plan”), is hereby amended, effective as of December 31, 2003, in the following respects:
| 1. | Article IV of the Supplemental Plan is hereby amended by adding the following new Section 4.4 at the end thereof: |
| 4.4 | Limitation on Benefits Payable under Agreements. Notwithstanding any other provision of this Supplemental Plan to the contrary, no Agreement entered into on or after December 31, 2003 shall credit to any individual service for periods while such individual is not employed by any Employer or compensation not earned by such individual from an Employer, unless one of the following applies: |
| (a) | such service and/or compensation is credited to an individual to provide such individual the excess of (i) the actuarial equivalent of the pension benefits the individual would have received from the individual’s prior employer had the individual remained employed by such prior employer, as determined by the Committee designated pursuant to Section 7.1, in consultation with independent actuaries engaged with respect to the Qualified Plan and/or the Supplemental Plan, over (ii) the actuarial equivalent of the pension benefits the individual will receive from such prior employer and the Company without the application of this Section 4.4; |
| (b) | such service is credited to an individual to permit such individual to commence pension benefits at the time the individual would have commenced pension benefits had the individual remained employed by the individual’s prior employer; |
| (c) | the crediting of such service and/or compensation is based upon a specified performance measure set forth in the Agreement; or |
| (d) | such service is credited to the individual pursuant to a severance plan or arrangement or pursuant to a change in control agreement, but only for the period in respect of which the individual receives salary continuation, severance or change in control payments, and such compensation does not exceed (i) the payments made to the individual under such a plan, arrangement or agreement nor (ii) with respect to any such plan, arrangement or agreement first entered into on or after January 1, 2004, two years of service. |
Nothing herein shall be interpreted to prohibit grants of service credits in excess of two years under existing plans, arrangements or agreements, nor require reduction of such grants under successor plans, arrangements or agreements.
Executed effective as of the date first set forth above.
| EXELON CORPORATION | ||
| By: | /S/ S. GARY SNODGRASS | |
| S. Gary Snodgrass | ||
| Senior Vice President and | ||
| Chief Administrative Officer | ||
2
Exhibit 10.54
Appendix A
EXELON CORPORATION
EMPLOYEE STOCK PURCHASE PLAN
(As Amended and Restated Effective May 1, 2004)
1. Establishment and Purpose. The Exelon Corporation Employee Stock Purchase Plan (the “Plan”) established by Exelon Corporation, a Pennsylvania corporation (the “Company”), is effective as of May 1, 2004 (the “Effective Date”) and is an amendment and restatement of the Plan as in effect June 1, 2001. The Plan provides employees of the Company, and its Subsidiary Companies (as defined below) added incentive to remain employed by such companies and to encourage increased efforts to promote the best interests of such companies by permitting eligible employees to purchase shares of common stock, no par value, of the Company (“Common Stock”) at below-market prices. The Plan is intended to qualify as an “employee stock purchase plan” under section 423 of the Internal Revenue Code of 1986, as amended (the “Code”). For purposes of the Plan, the term “Subsidiary Companies” shall mean all corporations which are subsidiary corporations (within the meaning of Section 424(f) of the Code) and of which the Company is the common parent. The Company and its Subsidiary Companies that, from time to time, have been designated by the Plan Administrator as eligible to participate in the Plan with respect to their employees are hereinafter referred to collectively as the “Participating Companies.”
2. Eligibility. (a) Eligible Employee. Participation in the Plan shall be limited to each employee of the Participating Companies who satisfies all of the following conditions (an “Eligible Employee”) as of the first day of the relevant Purchase Period (as defined in Section 3):
| (i) | such employee’s customary employment is for 20 or more hours per week; and |
| (ii) | such employee has been continuously employed by the Participating Companies for at least 3 consecutive calendar months. |
Notwithstanding the foregoing, an individual rendering services to a Participating Company pursuant to either of the following agreements shall not be considered an Eligible Employee with respect to any period preceding the date on which a court or administrative agency issues a final determination that such individual is an employee: (1) an agreement providing that such services are to be rendered as an independent contractor or (2) an agreement with an entity, including a leasing organization within the meaning of section 414(n)(2) of the Code, that is not a Participating Company.
(b) Limitations. Notwithstanding anything contained in the Plan to the contrary, no Eligible Employee shall acquire a right to purchase Common Stock hereunder to the extent that (i) immediately after receiving such right, such employee would own 5% or more of the total combined voting power or value of all classes of stock of the Company or any Subsidiary
A-1
Company (including any stock attributable to such employee under section 424(d) of the Code), or (ii) for any calendar year such right would permit such employee’s aggregate rights to purchase stock under all employee stock purchase plans of the Company and its Subsidiary Companies exercisable during such calendar year to accrue at a rate which exceeds $25,000 of fair market value of such stock for such calendar year. In addition, the number of shares of Common Stock which may be purchased by any Eligible Employee during any Purchase Period shall not exceed 125 (subject to adjustment pursuant to Section 12), or such other number as may be determined by the Plan Administrator (as defined in Section 11) and set forth in a written Appendix to the Plan.
3. Purchase Periods. A “Purchase Period” shall consist of the three consecutive month period beginning on each January 1, April 1, July 1 and October 1 commencing on or after the effective date of the Plan and prior to its termination.
4. Participation. (a) Enrollment. Each Eligible Employee shall be entitled to enroll in the Plan as of any Purchase Period which begins on or after such employee has become an Eligible Employee.
To enroll in the Plan, an Eligible Employee shall make a request to the Company or its designated agent at the time and in the manner specified by the Plan Administrator (as defined in Section 11), specifying the amount of payroll deduction to be applied to the compensation paid to the employee by the employee’s employer while the employee is a participant in the Plan. The amount of each payroll deduction specified in such request for each such payroll period shall be a whole percentage amount, unless otherwise determined by the Plan Administrator, not to exceed 10%, or such lesser percentage as may be determined by the Plan Administrator, of the participant’s regular base salary or wages (after applicable withholdings and deductions) paid to him or her during the Purchase Period by any of the Participating Companies. Subject to compliance with applicable rules prescribed by the Plan Administrator, the request shall become effective as of the Purchase Period following the day the Company or its designated agent receives such request.
Payroll deductions shall be made for each participant in accordance with such participant’s request until such participant’s participation in the Plan terminates, such participant’s request is revised or the Plan is suspended or terminated, all as hereinafter provided.
(b) Changes to Rate of Payroll Deduction. A participant may change the amount of his or her payroll deduction under the Plan effective as of any subsequent Purchase Period by so directing the Company or its designated agent at the time and in the manner specified by the Plan Administrator. A participant may not change the amount of his or her payroll deduction effective as of any time other than the beginning of a Purchase Period, except that a participant may elect to suspend his or her payroll deduction under the Plan as provided in Section 7.
(c) Purchase Accounts. Payroll deductions for each participant shall be credited to a purchase account established on behalf of the participant on the books of the participant’s employer or such employer’s designated agent (a “Purchase Account”). At the end of each Purchase Period, the amount in each participant’s Purchase Account will be applied to the
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purchase of the number of whole and fractional shares of Common Stock determined by dividing such amount by the Purchase Price (as defined in Section 5) for such Purchase Period. No interest shall accrue at any time for any amount credited to a Purchase Account of a participant (except as required by local law as determined by the Plan Administrator).
5. Purchase Price. The purchase price (the “Purchase Price”) per share of Common Stock hereunder for any Purchase Period shall be 90% of the lesser of (i) the closing price of a share of Common Stock on the New York Stock Exchange on the first day of such Purchase Period on which such exchange is open for trading or (ii) the closing price of a share of Common Stock on such exchange on the last day of such Purchase Period on which such exchange is open for trading. If such sum results in a fraction of one cent, the Purchase Price shall be increased to the next higher full cent.
6. Issuance of Stock. The Common Stock purchased by each participant shall be issued in book entry form and shall be considered to be issued and outstanding to such participant’s credit as of the end of the last day of each Purchase Period. A participant will be issued a certificate for his or her whole number of shares of Common Stock which have been held in book entry form for at least two years following the first day of the Purchase Period in which such shares were purchased, upon request of such participant or his or her legal representative or, if so directed by the Plan Administrator (as defined in Section 11), upon the termination of the Plan. In such event, the cash equivalent of any fractional shares shall also be distributed to such participant. Such cash equivalent shall be determined by multiplying the fractional share by the fair market value of a share of Common Stock (determined as provided in Section 5) on the last day of the Purchase Period immediately preceding such issuance.
The Plan Administrator may permit or require that shares be deposited directly with a broker designated by the Plan Administrator or to a designated agent of the Company, and the Plan Administrator may use electronic or automated methods of share transfer. The Plan Administrator may require that shares be retained with such broker or agent for a designated period of time and/or may establish other procedures to permit tracking of disqualifying dispositions of such shares, and may also impose a transaction fee with respect to a sale of shares of Common Stock issued to a participant’s credit and held by such a broker or agent. The Plan Administrator may permit shares purchased under the Plan to participate in a dividend reinvestment plan or program maintained by the Company, and establish a default method for the payment of dividends.
After the close of each Purchase Period, information will be made available to each participant regarding the entries made to such participant’s Purchase Account, the number of shares of Common Stock purchased and the applicable Purchase Price. In the event that the maximum number of shares of Common Stock are purchased by the participant for the Purchase Period and cash remains credited to the participant’s Purchase Account, such cash shall be refunded to such participant. For purposes of the preceding sentence, the maximum number of shares of Common Stock that may be purchased by a participant for a Purchase Period shall be determined under Section 2.
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7. Suspension of Payroll Deduction or Termination of Participation.
(a) Suspension of Payroll Deduction. A participant may elect at any time and in the manner specified by the Plan Administrator (as defined in Section 11) to suspend his or her payroll deduction under the Plan, provided such election is received by the Company or its designated agent prior to the date specified by the Plan Administrator for suspension of payroll deduction with respect to a Purchase Period. If the election is not received by such date, such suspension of payroll deduction shall be effective as of the next succeeding Purchase Period. Upon a participant’s suspension of payroll deduction, any cash credited to such participant’s Purchase Account shall be refunded to such participant. A participant who suspends payroll deduction under the Plan shall be permitted to resume payroll deduction as of any Purchase Period following the Purchase Period in which such suspension was effective, by making a new request at the time and in the manner specified by the Plan Administrator.
(b) Termination of Participation. If the participant dies, terminates employment with the Participating Companies for any reason, or otherwise ceases to be an Eligible Employee, such participant’s participation in the Plan shall immediately terminate. Upon such terminating event, the cash credited to such participant’s Purchase Account on the date of such termination shall be refunded to such participant or his or her legal representative, as the case may be.
8. Termination, Suspension or Amendment of the Plan.
(a) Termination. The Company, by action of the Board of Directors of the Company (the “Board”) or the Plan Administrator (as defined in Section 11), may terminate the Plan at any time, in which case notice of such termination shall be given to all participants, but any failure to give such notice shall not impair the effectiveness of the termination.
Without any action being required, the Plan shall terminate in any event when the maximum number of shares of Common Stock to be sold under the Plan (as provided in Section 12) has been purchased. Such termination shall not impair any rights which under the Plan shall have vested on or prior to the date of such termination. If at any time the number of shares of Common Stock remaining available for purchase under the Plan are not sufficient to satisfy all then-outstanding purchase rights, the Board or Plan Administrator may determine an equitable basis of apportioning available shares of Common Stock among all participants.
At any time following the termination of the Plan, the Plan Administrator may direct that one or more certificates for the number of whole shares of Common Stock held for each participant’s benefit and the cash equivalent of any fractional share so held shall be delivered to such participant. Such cash equivalent shall be determined by multiplying the fractional share by the fair market value of a share of Common Stock (determined as provided in Section 5) on the last day of the Purchase Period immediately preceding such termination. Except as otherwise provided in Section 14, the cash, if any, credited to each participant’s Purchase Account shall be distributed to such participant as soon as practicable after the Plan terminates.
(b) Suspension or Amendment. The Board or the Plan Administrator may suspend payroll deductions under the Plan or amend the Plan from time to time in any respect for any reason; provided, however, that no such suspension or amendment shall (a) materially
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adversely affect any purchase rights outstanding under the Plan during the Purchase Period in which such amendment or suspension is adopted, (b) increase the maximum number of shares of Common Stock which may be purchased under the Plan, (c) decrease the Purchase Price of a share of Common Stock for any Purchase Period below the lesser of 85% of the fair market value thereof on the first day of such Purchase Period and 85% of such fair market value on the last day of such Purchase Period or (d) adversely affect the qualification of the Plan under section 423 of the Code. If payroll deductions under the Plan are suspended pursuant to this Section, such payroll deductions shall resume as of the first Purchase Period commencing with or immediately following the date on which such suspension ends, in accordance with the participants’ payroll deduction elections then in effect.
9. Non-Transferability. Rights acquired under the Plan are not transferable and may be exercised only by a participant or his or her legal representative, as the case may be.
10. Shareholder’s Rights. No Eligible Employee or participant shall by reason of the Plan have any rights of a shareholder of the Company until he or she shall acquire a share of Common Stock as herein provided.
11. Administration of the Plan. The Plan shall be administered by the Treasurer of the Company (the “Plan Administrator”). In addition to the powers and authority specifically granted to the Plan Administrator pursuant to any other provision of the Plan, the Plan Administrator shall have full power and authority to: (i) interpret and administer the Plan and any instrument or agreement entered into under the Plan; (ii) establish such rules and regulations and appoint such agents as it shall deem appropriate for the proper administration of the Plan; (iii) designate which Subsidiary Companies shall participate in the Plan; (iv) make any other determination and take any other action that the Plan Administrator deems necessary or desirable for administration of the Plan. Decisions of the Plan Administrator shall be final, conclusive and binding upon all persons having an interest in the Plan.
The Plan shall be administered so as to ensure that all participants have the same rights and privileges as are provided by section 423(b)(5) of the Code.
12. Maximum Number of Shares. The maximum number of shares of Common Stock which may be purchased under the Plan is 3,000,000, subject to adjustment as set forth below. Shares of Common Stock sold hereunder may be treasury shares, authorized and unissued shares, shares purchased for participants in the open market (on an exchange or in negotiated transactions) or any combination thereof. If the Company shall, at any time after the effective date of the Plan, change its issued Common Stock into an increased number of shares, with or without par value, through a stock dividend or a stock split, or into a decreased number of shares, with or without par value, through a combination of shares, then, effective with the record date for such change, the maximum number of shares of Common Stock which thereafter may be purchased under the Plan and the maximum number of shares which thereafter may be purchased during any Purchase Period shall be the maximum number of shares which, immediately prior to such record date, remained available for purchase under the Plan and under any Purchase Period proportionately increased, in case of such stock dividend or stock split, or proportionately decreased in case of such combination of shares.
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13. Miscellaneous. Except as otherwise expressly provided herein, (i) any request, election or notice under the Plan from an Eligible Employee or participant shall be transmitted or delivered to the Company or its designated agent and, subject to any limitations specified in the Plan, shall be effective when so delivered and (ii) any request, notice or other communication from the Company or its designated agent that is transmitted or delivered to Eligible Employees or participants shall be effective when so transmitted or delivered. The Plan, and the Company’s obligation to sell and deliver shares of Common Stock hereunder, shall be subject to all applicable federal and state laws, rules and regulations, and to such approval by any regulatory or governmental agency as may, in the opinion of counsel for the Company, be required.
14. Change in Control. In the event of any Change in Control of the Company, as defined below, the then current Purchase Period shall thereupon end, the Plan Administrator shall direct that the cash credited to all participants’ Purchase Accounts shall be applied to purchase shares pursuant to Sections 4, 5 and 6 or refunded to participants, and the Plan shall immediately terminate. For purposes of this Section 14, the term “Change in Control” shall mean any of the following events:
(a) Any person, as such term is used in Rule 13d-5 promulgated under the Securities Exchange Act of 1934, as amended (the “Exchange Act”), or group, as defined in Sections 3(a)(9) and 13(d)(3) of the Exchange Act (each such person or group, an “SEC Person”), becomes the beneficial owner, as defined in Rule 13d-3 promulgated under the Exchange Act (a “Beneficial Owner”), of 20% or more of the then outstanding common stock of the Company or of the securities of the Company entitled to vote generally in the election of directors (“Voting Securities”) representing 20% or more of the combined voting power of all the then outstanding Voting Securities (such an SEC Person, a “20% Owner”); provided, however, that for purposes of this subsection (a), the following acquisitions shall not constitute a Change in Control: (1) any acquisition directly from the Company (excluding any acquisition resulting from the exercise of an exercise, conversion or exchange privilege unless the security being so exercised, converted or exchanged was acquired directly from the Company), (2) any acquisition by the Company, (3) any acquisition by an employee benefit plan (or related trust) sponsored or maintained by the Company or any corporation controlled by the Company (a “Company Plan”), or (4) any acquisition by any corporation pursuant to a transaction which complies with clauses (i), (ii) and (iii) of subsection (c) of this definition; provided further, that for purposes of clause (2), if any 20% Owner of the Company other than the Company or any Company Plan becomes a 20% Owner by reason of an acquisition by the Company, and such 20% Owner of the Company shall, after such acquisition by the Company, become the beneficial owner of any additional outstanding common shares of the Company or any additional outstanding Voting Securities of the Company (other than pursuant to any dividend reinvestment plan or arrangement maintained by the Company) and such beneficial ownership is publicly announced, such additional beneficial ownership shall constitute a Change in Control; or
(b) Individuals who, as of the effective date of the Plan, constitute the Board (the “Incumbent Board”) cease for any reason to constitute at least a majority of the Incumbent Board; provided, however, that any individual becoming a director subsequent
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to the date hereof whose election, or nomination for election by the Company’s shareholders, was approved by a vote of at least a majority of the directors then comprising the Incumbent Board shall be considered as though such individual were a member of the Incumbent Board, but excluding, for this purpose, any such individual whose initial assumption of office occurs as a result of an actual or threatened election contest (as such terms are used in Rule 14a-11 promulgated under the Exchange Act) or other actual or threatened solicitation of proxies or consents by or on behalf of a person other than the Board; or
(c) Consummation of a reorganization, merger or consolidation (“Merger”), or the sale or other disposition of more than 50% of the operating assets of the Company (determined on a consolidated basis), other than in connection with a sale-leaseback or other arrangement resulting in the continued utilization of such assets (or the operating products of such assets) by the Company (such reorganization, merger, consolidation, sale or other disposition, a “Corporate Transaction”); excluding, however, a Corporate Transaction pursuant to which:
(i) all or substantially all of the individuals and entities who are the Beneficial Owners, respectively, of the outstanding common stock of Company and outstanding Voting Securities of the Company immediately prior to such Corporate Transaction beneficially own, directly or indirectly, more than 60% of, respectively, the then-outstanding shares of common stock and the combined voting power of the then-outstanding voting securities entitled to vote generally in the election of directors, as the case may be, of the corporation resulting from such Corporate Transaction (including, without limitation, a corporation which, as a result of such transaction, owns the Company or all or substantially all of the assets of the Company either directly or through one or more subsidiaries) in substantially the same proportions as their ownership immediately prior to such Corporate Transaction of the outstanding common stock of Company and outstanding Voting Securities of the Company, as the case may be;
(ii) no SEC Person (other than the corporation resulting from such Corporate Transaction, and any person which beneficially owned, immediately prior to such corporate Transaction, directly or indirectly, 20% or more of the outstanding common stock of the Company or the outstanding Voting Securities of the Company, as the case may be) becomes a 20% Owner, directly or indirectly, of the then-outstanding common stock of the corporation resulting from such Corporate Transaction or the combined voting power of the outstanding voting securities of such corporation; and
(iii) individuals who were members of the Incumbent Board will constitute at least a majority of the members of the board of directors of the corporation resulting from such Corporate Transaction; or
(d) Approval by the Company’s shareholders of a plan of complete liquidation or dissolution of the Company, other than a plan of liquidation or dissolution which
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results in the acquisition of all or substantially all of the assets of the Company by an affiliated company.
15. Rules for Non-United States Jurisdictions. The Plan Administrator may establish rules or procedures relating to the operation and administration of the Plan to accommodate specific requirements of applicable local laws and procedures, including, without limitation, rules and procedures governing payroll deductions, payment of interest, conversion of local currency, payroll tax, withholding procedures and handling of stock certificates which vary with local requirements.
The Plan Administrator may also adopt sub-plans applicable to particular Participating Companies or locations, which sub-plans may be designed to be outside the scope of section 423 of the Code. The rules of such sub-plans may take precedence over the provisions of this Plan, with the exception of Section 4, but unless otherwise superceded by the terms of such sub-plan, the provisions of this Plan shall govern the operation of such sub-plan.
16. No Enlargement of Employee Rights. Nothing contained in this Plan shall be deemed to give any Eligible Employee the right to continued employment with the Company or any Subsidiary Company or to interfere with the right of the Company or any Subsidiary Company to discharge any Eligible Employee at any time.
17. Governing Law. This Plan, any related agreements (such as an enrollment form), and all determinations made and actions taken pursuant thereto, to the extent not otherwise governed by the Code or the law of the United States, shall be governed by the laws of the state of Pennsylvania and construed in accordance therewith without giving effect to principles of conflicts of law.
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IN WITNESS WHEREOF, this Plan has been executed this day of , 2004.
| EXELON CORPORATION | ||
| By: | ||
| J. Barry Mitchell Senior Vice President and Treasurer | ||
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Exhibit 10-54
APPENDIX I TO
EXELON CORPORATION
EMPLOYEE STOCK PURCHASE PLAN
(As Amended and Restated Effective May 1, 2004)
Limitation on Shares Purchased
Pursuant to the authority granted to the Plan Administrator under Section 2(b) of the Exelon Corporation Employee Stock Purchase Plan, the number of shares of Common Stock which may be purchased under the Plan by any Eligible Employee with respect to any Purchase Period commencing on or after April 1, 2004 shall not exceed one hundred fifty-five (155). Such limitation shall be applied following the consummation of the May 5, 2004 stock split.
IN WITNESS WHEREOF, the Plan Administrator has executed this APPENDIX I effective as of April 1, 2004.
| EXELON CORPORATION | ||
| By: | /S/ J. BARRY MITCHELL | |
| J. Barry Mitchell | ||
| Senior Vice President and Treasurer | ||
Exhibit 14
Code of Business Conduct
Living Up To Our Commitments With Integrity
Code of Business Conduct
Table of Contents
| Page Number | ||||
| Introduction |
||||
| Letter from the Chairman |
1 | |||
| The Role of the Code of Business Conduct |
2 | |||
| About the Ethics & Compliance Office |
2 | |||
| Where to Get Assistance |
2 | |||
| Ethical Decision Making |
3 | |||
| The Law |
4 | |||
| Introduction |
4 | |||
| Antitrust and Unfair Competition |
4 | |||
| Copyrights and Trademarks |
4 | |||
| Employment |
5 | |||
| Fair Treatment |
5 | |||
| Harassment |
5 | |||
| Safety and Health |
5 | |||
| Workplace Violence and Weapons |
6 | |||
| Drugs and Alcohol |
6 | |||
| Environment |
6 | |||
| Governmental Relations |
6 | |||
| Government Business |
7 | |||
| “Insider Information” and Securities Trading |
7 | |||
| International Trade |
8 | |||
| Regulatory Rules of Conduct |
8 | |||
| Business Conduct |
10 | |||
| Business Conduct |
10 | |||
| Accountability |
10 | |||
| Business Units and Managerial Accountability |
10 | |||
| Community Relations |
11 | |||
| Company Assets |
11 | |||
| Confidential Information |
12 | |||
| Computer Security |
12 | |||
| Competitive Information |
12 | |||
| Conflict of Interest |
12 | |||
| Personal Financial Interests |
13 | |||
| Corporate Opportunities |
13 | |||
| Outside Business Contacts |
14 | |||
| Gifts and Gratuities |
14 | |||
| Entertainment |
14 | |||
| Exceptions to the Conflict of Interest Policy |
15 | |||
| Customers |
15 | |||
| Quality and Service |
15 | |||
| Diversity |
15 | |||
| Political Activity |
16 | |||
| Individual Political Activities |
16 | |||
| Corporate Political Activities |
16 | |||
| Privacy |
16 | |||
| Records and Reports |
17 | |||
| Reporting Violations |
17 | |||
| Retaliation |
17 | |||
| Sales and Marketing |
18 | |||
| Supplier Relationships |
18 | |||
| Violations |
18 | |||
| Waivers for Directors and Executive Officers |
19 | |||
| Questions or Concerns |
20 | |||
| Resources |
20 | |||
| Additional References |
21 | |||
Letter from the Chairman
Dear Fellow Employees and Members of the Board of Directors:
Our vision is to strive to build exceptional value by becoming the best and most consistently profitable electricity and gas company in the United States. To be truly successful in achieving this vision, we must earn and maintain the trust of our customers, shareholders, fellow employees, government officials, competitors and the communities we serve. This can be accomplished by living up to our commitments, applying our corporate values of Boldness, Creativity, Accountability and Commitment, and most importantly, by conducting our business with the utmost integrity and regard for ethical standards.
Poor ethics can be devastating to businesses and can have severe consequences for employees and shareholders. Never has it been more clear that we must conduct our business ethically and according to legal and regulatory requirements. We count on all of our employees to conduct themselves according to the highest standards of ethical conduct.
The Exelon Code of Business Conduct is the “roadmap” for all of us on how to conduct our business both legally and ethically. Please review the Code carefully. If you have any questions about the Code or any items not addressed, please contact the Ethics & Compliance Office at 1-800-23-ETHIC or contact your supervisor or manager.
Thank you for working with us to create a company that will be not only successful, but admired as well.
Sincerely,
John W. Rowe
Chairman and Chief Executive Officer
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The Role of the Code of Business Conduct
The Code of Business Conduct represents the fundamental principle Exelon expects its employees and directors to follow: that we at all times behave ethically, honestly and forthrightly while living up to our commitments to co-workers, customers, shareholders, government authorities, and the communities where we do business.
The Code of Business Conduct does not cover every situation we may possibly encounter. It is not a substitute for good judgment nor a restraint on personal initiative. It is a guide designed to alert Exelon employees, directors, suppliers and contractors to major legal and ethical issues that frequently arise. Business units may also publish standards and policies that are more restrictive.
Exelon requires that every employee and director make a personal commitment to the observance of the highest ethical standards. By honoring this commitment, we can be sure that integrity, honesty and trust will be a way of life at Exelon.
About the Ethics & Compliance Office
One of the ways Exelon supports ethical business practices is through the Ethics & Compliance Office. The office reports to the Corporate Secretary in the Office of the Corporate General Counsel. The Corporate General Counsel serves as Exelon’s Ethics & Compliance Officer. An Ethics & Compliance Committee made up of Senior Managers from the various business units of Exelon offers guidance and direction to the Ethics & Compliance Office. Committee representatives will provide organizational support for the program in their respective business units.
The Office is a resource for any employee or supplier of Exelon who has a question or concern about ethical business activities. The Office may be reached by phone, e-mail, regular mail, or in person. All issues raised will be treated confidentially to the fullest extent possible. Reports to the Ethics & Compliance Office will be handled promptly, thoroughly, fairly, and discreetly.
The Ethics & Compliance Office may be contacted anonymously by calling 1-800-23-ETHIC. No attempt is made to identify the caller. Caller ID is not used on this phone. Anonymous callers who wish to follow up on their call will be assigned a confidential case number. Anonymous callers will be advised if additional information is required before an effective investigation can take place.
Where to Get Assistance
An employee who has ethical questions or concerns may seek assistance in one of three different ways:
| • | by contacting the employee’s supervisor, who in turn may seek assistance from other departments of Exelon with experience in the area raised by the employee’s question or concern (such as Human Resources, Law Department, Security, Employee Concerns Program for Nuclear Employees, Employee Assistance Program, Safety, etc.) |
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| • | by contacting the appropriate department directly |
| • | by contacting the Ethics Office Resource Line at 1-800-23-ETHIC (1-800-233-8442) |
Regardless of the method used, the person or office contacted will confidentially gather all relevant information and provide guidance to the employee to resolve the employee’s concern or assist the employee in making a more informed decision.
Ethical Decision Making
One of the major goals of the Code of Business Conduct is to help all of us make ethical business decisions. The policies and procedures contained in the Code establish guidelines for conduct in some general areas that pose ethical or legal concerns. But this document would have to be hundreds of pages long if it were to cover all the areas that we may encounter.
Therefore, employees may find it helpful to ask the following questions before taking action in specific situations:
| • | Is it legal and ethical? |
| • | Would it compromise my integrity or the company’s? |
| • | Does it conform to Exelon’s company policy? |
| • | How would my actions appear to my supervisors, peers, subordinates, friends, or the public if reported in the news media? |
| • | Does it make me feel uncomfortable? |
Ultimately, employees are personally responsible for their decisions and should discuss ethical concerns, issues and questions with their supervisor, manager, Human Resources or the Ethics Office Resource Line at 1-800-23-ETHIC.
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The Law
Introduction
We will obey all laws and regulations that apply to us. We will never pressure another employee to break a law or regulation, or use other employees, contractors, suppliers, or agents to circumvent the law or the Code of Business Conduct. Exelon will not knowingly use suppliers who operate in violation of applicable laws or regulations, including environmental, safety and employment laws.
Antitrust and Unfair Competition
As our competitive environment changes, it is important to review the antitrust and other laws that encourage fair competition among businesses. These laws prohibit a wide range of transactions and activities. Violations of these laws can subject the individuals involved, as well as the company, to huge fines and damages. To guarantee fair competition, we must not:
| • | Agree with a competitor to fix or control prices, allocate markets, divide up customers, or otherwise restrict competition; |
| • | Directly or indirectly discuss matters involved in competition with a competitor; |
| • | Arbitrarily refuse to deal with or purchase from others simply because they are competitors or they have chosen a competitor’s products or services; |
| • | Imply that our suppliers or customers are required to purchase products or services from us; |
| • | Make anyone buy a product or service they do not want in order to get a different product or service; |
| • | Boycott certain customers or suppliers; |
| • | Interfere with contracts between a prospective customer and a supplier competing with Exelon; |
| • | Engage in industrial espionage or commercial bribery; |
| • | Disparage competitors or their products or services; |
| • | Engage in misleading advertising or other promotional activities; |
| • | Give potential or existing customers or suppliers’ employees gratuities in order to improperly influence their decisions about doing business with Exelon; |
| • | Use our size or historical position to intimidate any person or organization. |
Employees who interact with competitors, and anyone who has a question about antitrust implications of a situation, should consult with the Law Department or the Ethics & Compliance Office.
Copyrights and Trademarks
Exelon, ComEd, PECO, and our other brand names, logos, and trademarks are very important assets. To protect these assets, they must be used consistently and solely for purposes of advancing Exelon’s interests. For Corporate Identity Standards, refer to the Brand Management and Corporate Identity Corporate Procedure.
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Other companies and individuals also own valuable trademark and copyright assets. Employees are prohibited from making, acquiring or using unauthorized copies of any computer software for either Exelon use or personal use. Also, unauthorized copying of tapes, books, magazines, periodicals and other legally protected work is a misuse of assets and a potential financial and legal liability for our company. Additional copies of needed materials should be obtained by purchasing them through the appropriate channels. Check with the Law Department or the Ethics & Compliance Office if you have any questions on copyright laws.
Employment
Fair Treatment
It is Exelon Policy to provide fair treatment and equal employment opportunity for everyone. Each individual will be judged based on qualifications, demonstrated skills and achievements, without regard to race, color, gender, national origin, age, religion, disability, sexual orientation, marital status or other protected classifications.
Harassment
We all have the right to work in an environment that is free from harassment or intimidation. Verbal or physical conduct by any employee that harasses or disrupts another’s work performance or creates an intimidating, offensive, abusive, or hostile work environment will not be tolerated. Unwelcome sexual advances, requests for sexual favors, and other unwelcome verbal or physical conduct of a sexual nature are specifically prohibited.
We have the responsibility to speak up when a co-worker’s conduct makes us or others uncomfortable, and to promptly report harassment, when it occurs, to the Supervisor, Department Head, HR representative, or the Ethics & Compliance Office. Any employee who reports harassment is assured that a prompt investigation will be conducted. Appropriate corrective action will be taken if the investigation reveals that there is merit to the concern.
Safety and Health
Safety is fundamental in everything that we do and it will not be compromised. Exelon is committed to managing its business to promote the safety of its employees, customers and the general public from hazards associated with the services Exelon provides. Each of us is responsible for observing the safety and health rules and practices that apply to our jobs, and for taking precautions necessary to protect ourselves, our co-workers, and the public. Accidents, injuries, hazards and unsafe activities or conditions must be promptly reported. Appropriate and timely action will be taken to correct known unsafe conditions.
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Workplace Violence and Weapons
Any activity that threatens the safety of the workplace or any individual is prohibited. This includes incidents of violence against other employees or the company, stalking cases or any other type of behavior which endangers, or threatens to endanger, the safety of Exelon employees or its customers. As part of our commitment to a safe environment, we also prohibit the possession of unauthorized weapons (including incapacitating devices), explosives or other dangerous substances on the job, on company premises (including parking lots), in company vehicles, or while attending company-sponsored activities.
Drugs and Alcohol
The health and safety of employees, customers and the public demands that each of us report to work free from the influence of any substance, including alcohol, that could prevent us from conducting work activities safely and effectively. Employees who for medical reasons are using prescription or non-prescription drugs that may impair alertness or judgment, and therefore jeopardize their safety and that of their co-workers, should inform their supervisor. To conform with federal regulations, some business units may require more stringent reporting requirements.
As explained in detail in our Drug and Alcohol Policy, we require a drug-free workplace to support health and safety for all. Using, possessing, distributing, or being under the influence of illegal or illicit drugs while on duty, on company premises (including parking lots), or in company vehicles is prohibited. Employees with problems related to alcohol or drugs are encouraged to seek confidential assistance from the Employee Assistance Program or other qualified professionals.
Environment
We must continue to demonstrate respect for public health and the environment while providing safe, reliable and economical service to our customers. It is our policy to meet-or surpass, where practical, all environmental laws and regulations.
We strive for leadership in the cost-effective recycling of materials and the reduction of waste. We will work in partnership with the community to preserve, restore and enhance natural habitats. We promote a corporate culture where competitive initiatives are consistent with environmental responsibility.
Governmental Relations
We cooperate fully with, and promptly respond to, all reasonable requests from governmental agencies and authorities. All information provided to the government must be truthful and accurate. Never mislead any investigator, and never destroy, falsify, or alter documents or records relating to the subject of any potential or pending governmental inquiry or investigation (refer to the Document Management Retention & Disposition Corporate Procedure). Never attempt to prevent any other employee or person from providing accurate information to any government official or agency.
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We should consider that Exelon is entitled to all of the safeguards provided by law to a person being investigated, including representation by legal counsel from the very beginning of the investigation. In order to ensure that all appropriate information is communicated to the governmental authorities and that the rights of Exelon are protected, any employee who receives a request for information from a government authority about Exelon’s business, or who obtains information that suggests a government investigation or inquiry has commenced, or is about to commence, should promptly report that fact to the Legal Department before responding to any non-routine request.
Also, representatives from local, state and federal government face very stringent regulations on gifts, favors, meals and entertainment. Often even a simple gesture like buying a cup of coffee for a government official may be a violation of the law. Various federal, state and local government agencies, have their own rules. Therefore, before providing anything of value to a government official, check with Government Affairs, External Affairs, or the Law Department.
Government Business
We must only use legitimate means to obtain business. In dealing with the government, we are prohibited from seeking or receiving unauthorized information related to potential government business. This would include, but is not limited to, proprietary data, competitors’ pricing information for government contacts, and non-public documents relating to government purchasing. We are also prohibited from offering, giving, receiving, or soliciting any form of bribe, rebate, gratuity, honorarium, or kickback in order to get government business. Consult with the department manager for proper direction.
“Insider Information” and Securities Trading
The securities laws impose restrictions on stock transactions. Trading securities or providing material inside information to others is illegal. Information is material if it has the potential to affect the price of Exelon stock or the securities of another company after it is disclosed. Such information includes, for example, news about financial results, plans to issue or buy back securities, dividend declarations, significant new contracts, major management or operational changes, mergers, acquisitions, new services or inventions, or major litigation.
Information should be treated as “inside” if it hasn’t been disclosed to the general investing public. In order to avoid the appearance that any Exelon employee is trading on inside information, no employee should engage in “short sales,” or trade in market options such as puts or calls on Exelon securities. Refer to the Buying and Selling Exelon Securities Corporate Procedure. Employees with questions should consult with the Corporate Secretary or the Ethics & Compliance Office.
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International Trade
U.S. laws govern the conduct of international trade including Anti-boycott, US Embargoes, and Export Control laws. Also, the Foreign Corrupt Practices Act prohibits bribes, offers, or promises of payments to any foreign official or political party, or to any foreign candidate, for the purpose of obtaining or retaining business. Any employee involved with international trade should consult with the Law Department for details of laws and regulations that affect them.
Regulatory Rules of Conduct
The restructuring of our industry has necessitated a new approach to the way the different parts of our business communicate and interact with one another. Both Illinois and Pennsylvania have created rules addressing the interactions between the electric distribution companies (“EDCs”) and their affiliated retail electric generation suppliers. In addition, Illinois has developed rules governing the interaction between the distribution function of the EDC and its internal retail merchant function. These rules are designed to ensure the utility does not provide to its affiliated retail electric supplier or, as applicable, its retail merchant function, preferential treatment that could result in an unfair competitive advantage in the new retail electric supply market. Pennsylvania also has competitive safeguards covering the generation company’s (“Genco”) relationship with its affiliated EDC and retail electric supplier.
ComEd is subject to Affiliate Non-Discrimination Rules established by the Illinois Commerce Commission (“ICC”) in 1998. These rules require that, in certain respects, ComEd function independently of its affiliated alternative retail electric supplier (“ARES”). Additionally, ComEd committed to the ICC that it would treat all its affiliates as an affiliated ARES for purposes of these rules. The ICC’s Affiliate Non-Discrimination Rules address the utility/affiliate relationship in the areas of marketing and advertising, employee sharing and interaction, information exchanges, and cross-subsidization.
Likewise, ComEd is subject to a Code of Conduct that addresses the relationship between the utility’s distribution and retail merchant functions. Like the Affiliate Non-Discrimination Rules, the Code of Conduct also addresses marketing, employee sharing and interaction, information exchanges, and cross-subsidization with the objective of insuring that ComEd’s internal retail merchant function does not receive an unfair competitive advantage.
PECO EDC is subject to statewide Competitive Safeguards that prohibit an EDC from providing its affiliated Electric Generation Supplier (“EGS”) any advantage in sharing customer or distribution system information or in providing regulated services and require that the EDCs and affiliated EGSs function independently.
PECO EDC, PECO EGS and the affiliated Genco are subject as well to Genco Competitive Safeguards established pursuant to PECO Energy’s 1998 Restructuring Settlement. These safeguards prohibit Genco from providing PECO EDC or PECO EGS any unreasonable preference over, or noncomparable treatment to, a non-affiliated EGS in the purchase, sale, use or transfer of generation and transmission products, services, or assets.
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Additionally, the Federal Energy Regulatory Commission (FERC) has rules that regulate the sharing of information between a company’s transmission system functions and its wholesale merchant functions and energy affiliates. Refer to the Implementation of FERC Standards of Conduct Corporate Procedure.
As a multi-state holding company, Exelon is also subject to the Public Utility Holding Company Act (PUHCA) administered by the Securities and Exchange Commission (SEC). PUHCA regulates intercompany transactions within the Exelon system, governs the amount of financing Exelon can do, and restricts the type of amount of business in which Exelon can invest.
Every employee must comply with all statutes, regulatory rules, and accounting standards that govern these regulatory relationships. For guidance about a particular situation, check the regulatory codes of conduct for Pennsylvania, Illinois or FERC. Because these rules are complex, you should also consult with your supervisor or manager, the Law Department, or the Ethics & Compliance Office.
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Business Conduct
Accountability
Each of us is accountable for following the law, complying with Exelon and business unit policies and procedures, and striving to live up to our own values as well as those of Exelon. Committing an illegal or unethical act as an Exelon employee, agent, or contractor is never justifiable.
Our responsibility includes a duty to report any illegal or unethical conduct that we engage in or observe others engaging in to our supervisor, manager, senior management, Human Resources, or the Ethics & Compliance Office. Failure to promptly report such conduct could allow wrongdoing to continue, subjecting each of us and the company to greater harm. Federal regulations that apply to several of our business units make this both a legal and an ethical responsibility. We are also expected to cooperate in the investigation of any alleged violation. Violations of the Code of Business Conduct can result in disciplinary action, which may include a change of job location or responsibilities, suspension, termination or other action.
Business Units and Managerial Accountability
As with all employees, managers are expected to exemplify the highest standards of ethical business conduct. Additionally, managers have a responsibility to create a work environment in which all employees, consultants and contract workers know that behavior consistent with our standards is expected of them. In particular, managers are responsible for ensuring that employees are informed of and adhere to policies and procedures necessary to do their jobs. Therefore, each Business Unit, through its management and supervisors, is responsible for the following:
| • | Identifying the laws and regulations that affect the Business Unit |
| • | Identifying the procedures that guide actions under the laws and regulations |
| • | Effectively communicating standards and procedures through training programs and by disseminating information on requirements and expectations |
| • | Assessing the potential for unethical or illegal conduct in its area of responsibility and taking action to mitigate or address it |
| • | Enforcing the Code of Business Conduct |
| • | Supporting a system for reporting concerns about ethics and unsafe conduct that protects employee confidentiality and anonymity to the fullest extent possible and ensures there is no retaliation against any employee for reporting a concern in good faith |
| • | Monitoring and documenting compliance with the Corporate Compliance Program |
| • | Consistently administering disciplinary action regarding ethical misconduct and violations of the Code of Business Conduct |
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Community Relations
We are committed to being a good neighbor and we support and encourage employee involvement in community activities and professional organizations. Exelon is also proud to provide financial support to hundreds of charitable and civic organizations in the communities where our employees live and work. However, we must ensure that all contributions of money, property and services are properly authorized and comply with all company policies and procedures and legal and regulatory requirements. We may not bring pressure on others to contribute to charitable organizations. Nor may we use company resources to solicit support for charitable causes without the prior approval of senior management.
We should be proud to work for a company that truly improves the quality of life of our customers. Imagine what life would be like without dependable energy. We would have darkened homes, shuttered businesses, unsafe streets and unreliable hospitals. We must continue to take seriously our commitment to dependable service.
Our customers and communities also depend on us to generate and distribute electricity, gas, and our other products and services safely. Our plants are in our neighborhoods, our lines run through our backyards. We must zealously protect the safety of our customers and communities by complying with all applicable company and government safety policies and regulations.
Safety is the primary responsibility of every Exelon employee. Any threat to public safety must be immediately reported to appropriate management or responsible authority.
Company Assets
We are entrusted with many company assets; physical assets like buildings, equipment and supplies; financial assets including cash and bank accounts; human assets, such as employees under our supervision; and information assets such as proprietary information and corporate records. Each of us has a special responsibility to protect all Exelon assets from loss, damage, misuse, theft, fraud, or embezzlement. No one should use company assets, property, information, or their position for personal gain or without appropriate authority.
Company resources should be used only to conduct company business. Limited and occasional personal use of company equipment, including computers, may be allowed provided it does not interfere with normal work responsibilities or expose Exelon to potential liabilities. Prior approval by the employee’s supervisor may be necessary for some uses. E-mail and the Internet must be used responsibly and in accordance with the Acceptable Use Corporate Procedure.
Regardless of condition or value, company property may not be sold, loaned, borrowed, given away, or otherwise disposed of, except with proper authorization.
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Confidential Information
One of Exelon’s most valuable assets is information. Our confidential information assets consist of information that is not generally disclosed to the public, and is helpful to Exelon, or would be to its competitors. It is also information that can be harmful to Exelon or its customers, if disclosed. Examples of confidential information include software, research and development information, marketing plans, business concepts and strategies, investment plans, new product plans or programs, wages and salaries, employee information, and detailed financial data. Each of us must be vigilant to protect our confidential information. These same protections also apply to similar information supplied to us by vendors and customers.
Safeguard trade secrets and confidential information by marking information accordingly, keeping it secure, and limiting access to those who need to know it in order to do their job. Avoid discussing confidential or competitive information in public areas like elevators, restaurants, public restrooms, and airplanes. The obligation to preserve Exelon’s confidential information continues even after we no longer work for the company. Further details may be found in Corporate Procedures, Protecting Exelon Information and Information Asset Protection.
Computer Security
We depend on the continuous, efficient operation of our computer systems. Each one of us must safeguard integrity and confidentiality by protecting passwords, IDs and access to computer systems. Take precautions against intrusion by “viruses” from the Internet or unauthorized software. For more information, refer to the Information Asset Protection Corporate Procedure.
Facility Security
We have invested a great deal in the security of our facilities. Each of us needs to understand and follow all security procedures, and to immediately report any potential threats to the department head or the Security Department.
Competitive Information
While information about our competitors, customers and suppliers is a valuable asset, federal law and our high ethical standards require that we obtain this information legally. Theft of proprietary information and inducing disclosures by a competitor’s past or present employees are prohibited.
Conflict of Interest
A conflict of interest exists whenever the personal interests of the employee or director are inconsistent with the responsibilities of his or her employment or position. Even the appearance of a conflict between personal interests and those of the company can undermine trust and therefore must be avoided or promptly disclosed to one’s manager
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and the Ethics & Compliance Office for guidance and resolution. Employees should make prior disclosures and seek guidance whenever there is a question concerning a conflict of interest, between the employee’s personal interest and the interests of the company. Conflicts include any activity, interest or association that might compromise or even appear to compromise the independent exercise of an employee’s judgment in the best interests of the company.
Personal Financial Interests
All employees and directors must avoid any activity, investment, interest or association which compromises, or which might reasonably be interpreted to compromise impartial and objective business decisions. Employees, directors, and members of their families, shall not knowingly have any material financial interest in:
| • | Any existing or proposed transaction to which the company is or is likely to become a party. |
| • | Property which the company is acquiring or likely to acquire (Not applicable to property acquired under the company’s Relocation Policy.) |
| • | Corporations, partnerships or other entities which compete with the company (except for insignificant stock interest in publicly held companies). |
A material financial interest is not subject to precise definition for all circumstances. In general, a financial interest is materials if it might compromise, or appear to compromise, the independent exercise of an employee’s or director’s judgment in the best interest of the company, its shareholders, and the public.
Exceptions to this policy may be granted only after disclosure to, and approval from, the functional area responsible officer and the Ethics & Compliance Officer.
Outside Employment or Activity
Employees may not engage in work or any activity that is in conflict with, or appears to conflict with the interest of Exelon or the employee’s ability to perform his or her work for the company. This includes performing work or services for any person, corporation, supplier, partnership or other entity which does business or is likely to do business with the company. The solicitation or conduct of any outside business, work or activity for personal gain during working hours is prohibited. Using company time or resources for outside employment is never acceptable. Disclosure to, and approval from, the functional area responsible officer and the Ethics & Compliance Officer is required before engaging in work that may appear to be a conflict of interest.
Corporate Opportunities
An employee or director may not use company assets, or information learned as a result of his or her position with the company, if the use of those assets or that information would provide the employee or director a business opportunity which otherwise would not exist and in which the company may have an interest (such as the acquisition of a property right or an investment opportunity).
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Outside Business Contacts
In the course of performing assigned duties, employees frequently have business contacts outside of the company with customers, suppliers, competitors, government agencies, and the news media. Employees should only perform services and answer questions which fall within the realm of their responsibilities. Employees may not offer or perform services for customers or suppliers which are routinely offered by the company.
Gifts and Gratuities
Employees, including members of their immediate families, may not directly or indirectly request, take, accept, or receive cash, bonuses, fees, commissions, gifts, gratuities, favors, loans, private or personal discounts from suppliers, excessive entertainment or any other similar form of consideration, of other than nominal or insignificant value, from any person, corporation, partnership or other entity with which the company does business, or is likely to do business.
Similarly, employees, or members of their immediate families, should never offer any gift, favor, entertainment or accommodation to a customer, supplier, contractor or anyone who has a business relationship with Exelon, if it will violate company policies or procedures or laws or regulations or obligate the recipient or violate the policy of the recipient’s organization.
We must avoid being placed in an embarrassing position, which might make it difficult to carry out our duties impartially. Therefore, adherence to this policy is essential in order that we all can maintain unquestioned integrity in our business relationships. If a gift or gratuity of more than nominal value is received, it should be returned with a polite note explaining Exelon’s policy, and the employee should notify their manager and the Ethics & Compliance Office.
Entertainment
Company policy does not preclude employees from providing or accepting meals and refreshments which are business related and are reasonable. Reimbursements must be properly reported in accordance with company procedures. Acceptance of such meals and amenities is contrary to policy when the employee has, or should have, any reason to believe that the offer was made with the intent to improperly influence the employee in the performance of his or her duties.
Entertainment through special events such as football games, golf outings, social dinner meetings and other social events, is not to be encouraged as a prerequisite for doing business with the company. However, such entertainment may be accepted or extended by employees when appropriate for business objectives and it is not excessive in value or frequency. Elaborate entertainment, such as overnight or weekend trips, must be avoided.
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Some areas of the company, such as purchasing, internal audit, and legal, will implement stricter gift and entertainment standards. Other areas of the company may also choose to implement stricter standards.
Exceptions to the Conflict of Interest Policy
| • | Exceptions for employees may be granted only after disclosure to, and approval from, the functional area responsible officer and the Ethics & Compliance Officer. |
| • | Exceptions for directors or executive officers (including the principal executive officer, the principal financial officer, the principal accounting officer or controller) may only be granted by the Board of Directors or a committee of the Board. Any such exception must also be promptly disclosed to the shareholders. |
Customers
Price is certainly an important consideration for most customers. However, it is not the only one, and in most cases it’s not the primary factor in a purchase decision. Customers purchase from companies that understand — and sometimes even anticipate — their needs. We must satisfy fundamental customer needs like quality, reliability, and service, and in a way that is ethical and legal. Refer to each state regulatory Code of Conduct and Federal Energy Regulatory Commission (FERC) regulations for information on the legal requirements we face when dealing with current or potential customers.
Quality and Service
We satisfy customers when we treat them as we would like to be treated. That means we need to treat customers with honesty, fairness, and respect. We must keep our commitments of quality, reliability, and service. Any time we make a promise that we cannot keep, some hard-earned customer’s trust is lost. We therefore should only make promises when we are reasonably confident that we will be able to keep them.
In order to deliver quality and protect our name, compliance with quality specifications and safety or testing requirements is essential. Failure to conduct required testing or misrepresentation of test procedures or data is never acceptable.
Diversity
Embracing diversity is not simply the right thing to do; it makes good business sense. Our diverse employees are a competitive advantage, enabling us to make more informed business decisions and to better serve our diverse customer base. We will actively seek and promote a more diverse workforce. We are also committed to diversity in regard to our suppliers and vendors.
We also promote an environment of diverse ideas where communication is open, direct, honest, and respectful. This does not mean that we beat each other up over any differences. It means that we listen and speak with the goal of understanding the value that we each bring. We encourage free and open discussion. We honestly communicate plans, expectations, and results. When we disagree, we do so respectfully, treating each other with dignity.
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Political Activity
Individual Political Activities
We each have the right to participate in the political process and to engage in political activities of our own choosing. While involved in personal civic and political affairs, however, we must at all times make clear that our views and actions are our own, and not those of Exelon. To determine if the political activity may create a potential conflict, employees may contact the Ethics & Compliance Office, which will review the case and inform the employee of any action considered necessary to avoid the conflict.
Exelon funds or resources are not to be used to support an individual’s political parties, affiliated organizations, causes or candidates. Company resources include financial and non-financial such as using company time, telephones and copiers to solicit for a political cause or candidate.
Corporate Political Activities
Exelon will communicate and lobby on behalf of the interests of the company, but only as permitted by law. This includes the Public Utility Holding Company Act (PUCHA) which imposes significant restrictions on the political activities of corporations that are multi-state companies.
Our Political Action Committee(s) supports candidates whose political philosophies best represent the interests of the company, our employees, shareholders and customers. Donations to a Political Action Committee are strictly voluntary. Also, at times Exelon may request employees to make personal contact with government officials or to write letters presenting our position on specific issues.
Employees who lobby government employees or officials on issues that affect Exelon should contact Governmental Affairs or External Affairs to ensure that such activities fully comply with the law. Employees should also contact Governmental Affairs or External Affairs before ever discussing any employment or business opportunities with any public official. Corporate contributions or payments of any kind to any official, candidate, political party or political committee may be made only with the prior written approval of Governmental Affairs or External Affairs.
Privacy
As a company and as individuals we need to respect the privacy of our co-workers. The company will retain only the personal information necessary for effective operations, and will limit access to such information to authorized persons with the need-to-know for business or legal reasons.
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While Exelon does not routinely monitor personal communications, employees should not expect that these communications are always private. When monitoring of communications is necessary for quality or legal reasons, we will comply with all state and federal laws. For the safety and protection of other employees and the company, Exelon may search employee workspaces, including company-owned lockers and vehicles.
Records and Reports
We rely on accurate information in order to make responsible business decisions. We therefore require honest and accurate recording, reporting and retention of information. This includes all business records, including financial reports, research reports, marketing information, sales reports, tax refunds, expense accounts, time sheets, claims and other documents including those submitted to governmental agencies. All records and accounts must accurately reflect transactions and events, and conform both to generally accepted accounting principles and to the Exelon system of internal controls.
It is wrong, for example, to make false claims on an expense report or time sheet, to falsify quality or safety results, or misrepresent assets, liabilities, revenues or expenses. No entry may be made in any record that intentionally hides or disguises the true nature of any transaction. Likewise, employees must never withhold or fail to communicate information which should be brought to the attention of higher levels of management.
Almost all business records may become subject to public disclosure in the course of litigation or governmental investigations. Records are also often obtained by outside parties or the media. Employees should therefore attempt to be as clear, concise, truthful and accurate as possible when recording any information. Avoid exaggeration, inappropriate language, guesswork, legal conclusions, and derogatory characterizations of people and their motives. Records should not be retained longer than necessary, and should be discarded in accordance with Exelon’s Document Management, Retention & Disposition Corporate Policy and Procedure.
Reporting Violations
Employees have the obligation to report any situation or transaction which may violate, or could appear to violate, the letter or intent of the Code of Business Conduct. Reporting shall be to the employee’s supervisor, manager, Human Resources, the Ethics Office Resource Line at 1-800-23-ETHIC, or through the company Intranet link “Report an Ethics Concern.”
Retaliation
Individuals living up to their responsibility to report an ethical or legal concern shall not be subject to retaliation. No company officer, employee, contractor, subcontractor, or agent may discharge, demote, suspend, threaten, harass, or in any other manner discriminate against an employee in terms and conditions of employment because the employee reports a known or suspected violation of the law or the Code of Business Conduct. Any form of reprisal against an employee because the employee raised a matter
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is contrary to our culture and values — and it will not be tolerated. A person who engages in any act of intentional retaliation will be disciplined, up to and including termination. Employees who knowingly submit false reports will also be subject to disciplinary action. An employee who believes that prohibited retaliation has occurred should immediately report the concern to Human Resources, Legal, or the Ethics & Compliance Office.
Sales and Marketing
Understanding and anticipating customer needs and accurately representing products, services, benefits and prices are first steps in creating satisfied customers. Providing misleading impressions, omitting important facts, or making false claims about our competitors’ offerings is not acceptable.
Marketing and advertising of our products and services should be based on quality, service, pricing and other legitimate attributes. It’s never acceptable to use any illegal or unethical means to obtain business, including offering bribes or kickbacks. In addition, it is not acceptable to enter into agreements with competitors, suppliers or customers that have the intent to limit competition or may be viewed as anti-competitive.
It is Exelon’s policy to forgo any business which can be obtained only by improper or illegal methods. Accordingly, if, at any time, it appears that Exelon or its employees must engage in unethical or illegal activity to gain business, that business opportunity must not be pursued further, and the employee with that knowledge should contact the Ethics and Compliance Office or the Legal Department immediately.
Supplier Relationships
All purchasing decisions must be made on the best value received by Exelon. Quality, technical excellence, service, delivery and price are among the objective criteria that will drive our purchasing decisions.
Personal, family and financial relationships can make it difficult to make objective business decisions. An employee who has personal or family relationships with a supplier or business partner of the company should disclose this relationship to his or her manager and the Ethics & Compliance Office. See the Conflict of Interest section or refer to the Corporate Supply Chain Requirements Corporate Procedure for additional information.
Violations
Exelon views this Code of Business Conduct to be of the utmost importance. Accordingly, it will be enforced fairly at all levels. Violations of this Code will not be tolerated. In accordance with company regulations, violations may result in sanctions, including, as appropriate, a reprimand, probation, demotion, temporary suspension, termination, required reimbursement for Exelon’s losses or damages, and referral for criminal prosecution, or civil action.
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Waivers for Directors and Executive Officers
Waivers of the Code for directors or executive officers (including the principal executive officer, the principal financial officer, the principal accounting officer, or controller) may only be granted by the Board of Directors or a committee of the Board. Such waivers must also be promptly disclosed to shareholders.
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Questions or Concerns
Employees who have questions about the Code of Business Conduct or concerns about conduct that may violate Exelon standards or the law, are encouraged to talk to their supervisors. If this is uncomfortable or seems inappropriate, talk to the Department Head or other functional senior manager, Human Resources, call the Ethics Office Resource Line at 1-800-23-ETHIC, or use the company Intranet link “Report an Ethics Concern” to write a confidential or anonymous report.
Resources
Our best resources for good, ethical business judgment are our supervisors and managers, the Code of Business Conduct, and our personal values. Other resources include:
Corporate Security
Ethics & Compliance Office
Diversity
Employee Assistance Program (EAP)
Employee Concerns Program (Exelon Nuclear only)
Environmental Services
Human Resources
Governmental Affairs & External Affairs
Legal
Safety
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Additional References
Corporate Policies
Exelon’s CEO, in conjunction with the senior governance bodies, have established the following corporate policies which describe the fundamental principles, values and practices under which Exelon operates and conducts business, as well as the corporate-wide rules, standards and practices that all employees and contractors must follow:
| Number | ||
| • Adherence to Corporate Policy & Procedures |
LE-AC-1 | |
| • Corporate Accounting |
FI-AC-2 | |
| • Corporate & Public Affairs |
CP-AC-1 | |
| • Document Management, Retention & Disposition |
LE-AC-4 | |
| • Environmental Protection |
EN-AC-1 | |
| • Ethics, Legal & Regulatory Compliance |
LE-AC-2 | |
| • Finance & Treasury |
FI-AC-1 | |
| • Human Resources & Diversity |
HR-AC-1 | |
| • Information Protection |
LE-AC-3 | |
| • Safety |
SA-AC-1 | |
| • Security |
SE-AC-1 | |
| • Supply Management |
SM-AC-1 | |
| • Use of Information Technology Assets |
IT-AC-1 |
These policies are necessary references when employees are dealing with ethical and legal matters, including those issues covered by the Code of Business Conduct. Corporate Policies and the Corporate Procedures that support each of the policies above can be accessed through Exelon’s Intranet homepage.
| Ethics & Compliance Office | ||
| phone: | 1-800-23-ETHIC (1-800-233-8442) | |
| mail: | P.O. Box 805379 | |
| Chicago, IL 60680-5379 | ||
| e-mail: | Ethics Advice and Inquiries | |
| Intranet: | “Report an Ethics Concern” | |
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Exhibit 21-1
EXELON CORPORATION SUBSIDIARY LISTING
| Affiliates |
Jurisdiction of |
|||
| Adwin Equipment Company |
Pennsylvania | |||
| Adwin Realty Company |
Pennsylvania | |||
| AllEnergy Gas & Electric Marketing Company, LLC |
Delaware | |||
| Ambassador II Joint Venture |
Pennsylvania | |||
| AmerGen Clinton NQF, LLC |
Nevada | |||
| AmerGen Consolidation, LLC |
Nevada | |||
| AmerGen Energy Company, LLC |
Delaware | |||
| AmerGen Oyster Creek NQF, LLC |
Nevada | |||
| AmerGen TMI NQF, LLC |
Nevada | |||
| ATNP Finance Company |
Delaware | |||
| Braidwood 1 NQF, LLC |
Nevada | |||
| Braidwood 2 NQF, LLC |
Nevada | |||
| Byron I NQF, LLC |
Nevada | |||
| Byron 2 NQF, LLC |
Nevada | |||
| Cenesco Company, LLC |
Delaware | |||
| ComEd Financing II |
Delaware | |||
| ComEd Financing III |
Delaware | |||
| ComEd Funding, LLC |
Delaware | |||
| ComEd Transitional Funding Trust |
Delaware | |||
| Commonwealth Edison Company |
Illinois | |||
| Commonwealth Edison Company of Indiana, Inc. |
Indiana | |||
| Concomber, Ltd. |
Bermuda | |||
| Dresden 1 NQF, LLC |
Nevada | |||
| Dresden 2 NQF, LLC |
Nevada | |||
| Dresden 3 NQF, LLC |
Nevada | |||
| ECP Telecommunications Holdings, LLC |
Delaware | |||
| ECPH, LLC |
Delaware | |||
| Edison Development Canada Inc. |
Ontario | |||
| Edison Finance Partnership |
Canada | |||
| EEI Telecommunications Holdings, LLC |
Delaware | |||
| EGW Meter Services, LLC |
Delaware | |||
| EIS Engineering, Inc. |
Delaware | |||
| EIS Investments, LLC |
Delaware | |||
| ENEH Services, LLC |
Delaware | |||
| ETT Boston, Inc. |
Delaware | |||
| ETT Canada, Inc. |
New Brunswick | |||
| ETT North America, Inc. |
Delaware | |||
| Exelon Allowance Management Company, LLC |
Delaware | |||
| Exelon AOG Holding #1, Inc. |
Delaware | |||
| Exelon AOG Holding #2, Inc. |
Delaware | |||
| Exelon Business Services Company |
Pennsylvania | |||
| Exelon Capital Trust I |
Delaware | |||
| Exelon Capital Trust II |
Delaware | |||
| Exelon Capital Trust III |
Delaware | |||
| Exelon Communications Company, LLC |
Pennsylvania | |||
| Exelon Communications Holdings, LLC |
Delaware | |||
| Exelon Corporation |
Pennsylvania |
| Affiliates |
Jurisdiction of |
|||
| Exelon Edgar, LLC |
Delaware | |||
| Exelon Energy Company |
Delaware | |||
| Exelon Energy Delivery Company, LLC |
Delaware | |||
| Exelon Enterprises Company, LLC |
Pennsylvania | |||
| Exelon Enterprises Investments, Inc. |
Delaware | |||
| Exelon Enterprises Management, Inc. |
Pennsylvania | |||
| Exelon Framingham Development, LLC |
Delaware | |||
| Exelon Framingham, LLC |
Delaware | |||
| Exelon Generation Company, LLC |
Pennsylvania | |||
| Exelon Generation Consolidation, LLC |
Nevada | |||
| Exelon Generation Finance Company, LLC |
Delaware | |||
| Exelon Generation International, Inc. |
Pennsylvania | |||
| Exelon Hamilton LLC |
Delaware | |||
| Exelon Investment Holdings, LLC |
Illinois | |||
| Exelon New Boston, LLC |
Delaware | |||
| Exelon New England Development, LLC |
Delaware | |||
| Exelon New England Holdings, LLC |
Delaware | |||
| Exelon New England Power Marketing, Limited Partnership |
Delaware | |||
| Exelon Peaker Development General, LLC |
Delaware | |||
| Exelon Peaker Development Limited, LLC |
Delaware | |||
| Exelon PowerLabs, LLC |
Pennsylvania | |||
| Exelon Services, Inc. |
Delaware | |||
| Exelon SHC, Inc. |
Delaware | |||
| Exelon Synfuel I, LLC |
Delaware | |||
| Exelon Synfuel II, LLC |
Delaware | |||
| Exelon Synfuel III, LLC |
Delaware | |||
| Exelon Thermal Development, Inc. |
Delaware | |||
| Exelon Thermal Holdings, Inc. |
Delaware | |||
| Exelon Ventures Company, LLC |
Delaware | |||
| Exelon West Medway Development, LLC |
Delaware | |||
| Exelon West Medway Expansion, LLC |
Delaware | |||
| Exelon West Medway, LLC |
Delaware | |||
| Exelon Wyman, LLC |
Delaware | |||
| ExRES Power Holdings, Inc. |
Delaware | |||
| EXRES SHC, Inc. |
Delaware | |||
| ExTel Corporation, LLC |
Delaware | |||
| ExTex LaPorte Limited Partnership |
Texas | Trading as: Exelon Power Texas | ||
| ExTex Marketing, LLC |
Delaware | |||
| ExTex Power, LP |
Delaware | |||
| ExTex Retail Services Company, LLC |
Delaware | Trading as: Exelon Power Services | ||
| F & M Holdings Company LLC |
Delaware | |||
| Fischbach and Moore Electric, Inc. |
Delaware | |||
| Fischbach and Moore Electrical Contracting, Inc. |
Delaware | |||
| Fischbach and Moore, Inc. |
New York | |||
| Horizon Energy Company |
Pennsylvania | |||
| II Services, Inc. |
Delaware | |||
| Infrasource Field Services, LLC |
Oklahoma | |||
| La Salle 1 NQF, LLC |
Nevada | |||
| La Salle 2 NQF, LLC |
Nevada | |||
| Limerick I NQF, LLC |
Nevada |
| Affiliates |
Jurisdiction of |
|||
| Limerick 2 NQF, LLC |
Nevada | |||
| NEWCOSY, Inc. |
Delaware | |||
| NEWCOTRA, Inc. |
Delaware | |||
| North America Power Services, Inc. |
Delaware | |||
| Northwind Boston, LLC |
Massachusetts | |||
| Northwind Thermal Technologies Canada Inc. |
New Brunswick | |||
| Nuclear US Holdings, Inc. |
Delaware | |||
| Nuclear US Investments, LLC |
Delaware | |||
| Nuclear, Limited Partnership |
Delaware | |||
| NuStart Energy Development Management Committee |
Delaware | |||
| NuStart Energy Development, LLC |
Delaware | |||
| OldcoVSI, Inc. |
Delaware | |||
| OSP Servicios, S.A. de C.V. |
Mexico | |||
| Peach Bottom I NQF, LLC |
Nevada | |||
| Peach Bottom 2 NQF, LLC |
Nevada | |||
| Peach Bottom 3 NQF, LLC |
Nevada | |||
| PEC Financial Services, LLC |
Pennsylvania | |||
| PECO Energy Capital Corp. |
Delaware | |||
| PECO Energy Capital Trust III |
Delaware | |||
| PECO Energy Capital Trust IV |
Delaware | |||
| PECO Energy Capital Trust V |
Delaware | |||
| PECO Energy Capital Trust VI |
Delaware | |||
| PECO Energy Capital, LP |
Delaware | |||
| PECO Energy Company |
Pennsylvania | |||
| PECO Energy Power Company |
Pennsylvania | |||
| PECO Energy Transition Trust |
Delaware | |||
| PECO Wireless, LP |
Delaware | |||
| Penesco Company, LLC |
Delaware | |||
| PHT Holdings, LLC |
Delaware | |||
| Port City Power, LLC |
Delaware | |||
| Quad Cities 1 NQF, LLC |
Nevada | |||
| Quad Cities 2 NQF, LLC |
Nevada | |||
| Rand-Bright Corporation |
Wisconsin | |||
| Salem I NQF, LLC |
Nevada | |||
| Salem 2 NQF, LLC |
Nevada | |||
| Scherer Holdings 1, LLC |
Delaware | |||
| Scherer Holdings 2, LLC |
Delaware | |||
| Scherer Holdings 3, LLC |
Delaware | |||
| Sithe Energies, Inc. |
Delaware | |||
| Sithe Energy Management Services II, Inc. |
Delaware | |||
| Sithe Energy Management Services, Inc. |
Delaware | |||
| Sithe International Finance II, LLC |
Delaware | |||
| Sithe International Finance, LLC |
Delaware | |||
| Sithe International, Inc. |
Delaware | |||
| Sithe Latin America Holdings, Ltd. |
Cayman Islands | |||
| Sithe Overseas Power Services, Ltd. |
Virgin Islands | |||
| Sithe Pardo Holdings, Ltd. |
Cayman Islands |
| Affiliates |
Jurisdiction of |
|||
| Sithe Tamuin Energy Services II, S. de R.L. de C.V. |
Mexico | |||
| Sithe Tamuin Energy Services, S. de R.L. de CV. |
Mexico | |||
| Sithe Tamuin Holdings A, LLC |
Delaware | |||
| Sithe Tamuin Holdings, LLC |
Delaware | |||
| Sithe Tamuin Holdings II, LLC |
Delaware | |||
| Sithe Tamuin Holdings III, LLC |
Delaware | |||
| Sithe Tamuin Investments II, S. de R.L. de C.V. |
Mexico | |||
| Sithe Tamuin Investments, S. de R.L. de C.V. |
Mexico | |||
| Southeast Chicago Energy Project, LLC |
Delaware | |||
| Spruce Equity Holdings, LP |
Delaware | |||
| Spruce Holdings G.P. 2000, LLC |
Delaware | |||
| Spruce Holdings L.P. 2000, LLC |
Delaware | |||
| Spruce Holdings Trust |
Delaware | |||
| Susquehanna Electric Company |
Maryland | |||
| Susquehanna Power Company |
Maryland | |||
| Tamuin Development Services de R.L. de C.V. |
Mexico | |||
| Tamuin Mexican Business Trust |
Mexico | |||
| Tamuin Mexican Business Trust II |
Mexico | |||
| T.H. Green Electric Co., Inc. |
New York | |||
| TEG Holdings, LLC |
Delaware | |||
| Termoelectrica Del Golfo S. de R.L. de C.V. |
Mexico | |||
| Termoelectrica Penoles S. de R.L. de C.V. |
Mexico | |||
| Texas Ohio Gas, Inc. |
Texas | |||
| The Proprietors of the Susquehanna Canal |
Maryland | |||
| UII, LLC |
Illinois | |||
| Unicom Assurance Company, Ltd. |
Bermuda | |||
| Unicom Power Marketing Inc. |
Delaware | |||
| UniGridEnergy, LLC |
Delaware | |||
| URI, LLC |
Illinois | |||
| Wansley Holdings 1, LLC |
Delaware | |||
| Wansley Holdings 2, LLC |
Delaware | |||
| Zion I NQF, LLC |
Nevada | |||
| Zion 2 NQF, LLC |
Nevada |
Exhibit 21-2
COMMONWEALTH EDISON COMPANY SUBSIDIARY LISTING
| Affiliates |
Trade Name |
Jurisdiction or Formation | ||
| ComEd Financing II |
Delaware | |||
| ComEd Financing III |
Delaware | |||
| ComEd Funding, LLC |
Delaware | |||
| ComEd Transitional Funding Trust |
Delaware | |||
| Commonwealth Edison Company |
Illinois | |||
| Commonwealth Edison Company of Indiana, Inc. |
Indiana | |||
| Edison Development Canada, Inc. |
Ontario | |||
| Edison Finance Partnership |
Canada |
Exhibit 21-3
PECO ENERGY COMPANY SUBSIDIARY LISTING
| Affiliates |
Trade Name |
Jurisdiction or Formation | ||
| Adwin Realty Company |
Pennsylvania | |||
| ATNP Finance Company |
Delaware | |||
| ExTel Corporation, LLC |
Delaware | |||
| Horizon Energy Company |
Pennsylvania | |||
| PEC Financial Services, LLC |
Pennsylvania | |||
| PECO Energy Capital Corp |
Delaware | |||
| PECO Energy Capital, LP |
Delaware | |||
| PECO Energy Capital Trust III |
Delaware | |||
| PECO Energy Capital Trust IV |
Delaware | |||
| PECO Energy Capital Trust V |
Delaware | |||
| PECO Energy Capital Trust VI |
Delaware | |||
| PECO Energy Transition Trust |
Delaware |
Exhibit 21-4
EXELON GENERATION COMPANY, LLC SUBSIDIARY LISTING
| Affiliates |
Trade Name |
Jurisdiction or Formation | ||
| AmerGen Consolidation, LLC (includes 3 un-named subsidiaries all of which hold decommissioning related investments) |
Nevada | |||
| AmerGen Energy Company, LLC |
Delaware | |||
| Exelon Energy Company (includes 2 un-named subsidiaries which provide retail energy and gas delivery services) |
Delaware | |||
| Exelon Generation Company, LLC (includes 16 un-named subsidiaries which provide power generation or related support services) |
Pennsylvania | |||
| Exelon Generation Consolidation, LLC (includes 16 un-named subsidiaries all of which hold decommissioning related investments) |
Nevada | |||
| Exelon Generation Finance Company, LLC |
Delaware | |||
| Exelon New England Holdings, LLC (includes 11 un-named subsidiaries, all of which operate fossil fuel generating stations or provide related support functions) |
Delaware | |||
| Exelon SHC, Inc. (includes 11 un-named subsidiaries, all of which operate and hold investments in fossil fuel generating stations) |
Delaware | |||
| PECO Energy Power Company (include 2 un-named subsidiaries, all of which operate fossil fuel generating stations or provide related support functions) |
Pennsylvania | |||
| Southeast Chicago Energy Project, LLC |
Delaware | |||
| Susquehanna Electric Company |
Maryland | |||
Exhibit 23-1
CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
We hereby consent to the incorporation by reference in the Registration Statements on Form S-3 (No. 333-57640, 333-84446 and 333-108546), on Form S-4 (No. 333-122704), and on Form S-8 (No. 333-61390 and 333-49780) of Exelon Corporation and Subsidiary Companies of our report dated February 22, 2005 relating to the financial statements, financial statement schedule, management’s assessment of the effectiveness of internal control over financial reporting and the effectiveness of internal control over financial reporting, which appears in this Form 10-K.
PricewaterhouseCoopers LLP
Chicago, Illinois
February 22, 2005
Exhibit 23-2
CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
We hereby consent to the incorporation by reference in the Registration Statements on Form S-3 (No. 33-6879, 33-51379, and 333-99363) and on Form S-8 (No. 333-33847) of Commonwealth Edison Company and Subsidiary Companies of our report dated February 22, 2005 relating to the financial statements and financial statement schedule, which appears in this Form 10-K.
PricewaterhouseCoopers LLP
Chicago, Illinois
February 22, 2005
Exhibit 23-3
CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
We hereby consent to the incorporation by reference in the Registration Statements on Form S-3 (No. 333-99361 and 333-105207) of PECO Energy Company and Subsidiary Companies of our report dated February 22, 2005 relating to the financial statements and financial statement schedule, which appears in this Form 10-K.
PricewaterhouseCoopers LLP
Chicago, Illinois
February 22, 2005
Exhibit 24-1
POWER OF ATTORNEY
KNOWN ALL MEN BY THESE PRESENTS that I, Edward A. Brennan do hereby appoint John W. Rowe and Randall E. Mehrberg, or either of them, attorney for me and in my name and on my behalf to sign the annual Securities and Exchange Commission report on Form 10-K for 2004 of Exelon Corporation, together with any amendments thereto, to be filed with the Securities and Exchange Commission, and generally to do and perform all things necessary to be done in the premises as fully and effectually in all respects as I could do if personally present.
| /S/ EDWARD A. BRENNAN |
| Edward A. Brennan |
DATE: February 23, 2005
Exhibit 24-2
POWER OF ATTORNEY
KNOWN ALL MEN BY THESE PRESENTS that I, M. Walter D’Alessio do hereby appoint John W. Rowe and Randall E. Mehrberg, or either of them, attorney for me and in my name and on my behalf to sign the annual Securities and Exchange Commission report on Form 10-K for 2004 of Exelon Corporation, together with any amendments thereto, to be filed with the Securities and Exchange Commission, and generally to do and perform all things necessary to be done in the premises as fully and effectually in all respects as I could do if personally present.
| /S/ M. WALTER D’ALESSIO |
| M. Walter D’Alessio |
DATE: February 21, 2005
Exhibit 24-3
POWER OF ATTORNEY
KNOWN ALL MEN BY THESE PRESENTS that I, Nicholas DeBenedictis do hereby appoint John W. Rowe and Randall E. Mehrberg, or either of them, attorney for me and in my name and on my behalf to sign the annual Securities and Exchange Commission report on Form 10-K for 2004 of Exelon Corporation, together with any amendments thereto, to be filed with the Securities and Exchange Commission, and generally to do and perform all things necessary to be done in the premises as fully and effectually in all respects as I could do if personally present.
| /S/ NICHOLAS DEBENEDICTIS |
| Nicholas DeBenedictis |
DATE: February 23, 2005
Exhibit 24-4
POWER OF ATTORNEY
KNOWN ALL MEN BY THESE PRESENTS that I, Bruce DeMars do hereby appoint John W. Rowe and Randall E. Mehrberg, or either of them, attorney for me and in my name and on my behalf to sign the annual Securities and Exchange Commission report on Form 10-K for 2004 of Exelon Corporation, together with any amendments thereto, to be filed with the Securities and Exchange Commission, and generally to do and perform all things necessary to be done in the premises as fully and effectually in all respects as I could do if personally present.
| /S/ BRUCE DEMARS |
| Bruce DeMars |
DATE: February 21, 2005
Exhibit 24-5
POWER OF ATTORNEY
KNOWN ALL MEN BY THESE PRESENTS that I, Nelson A. Diaz do hereby appoint John W. Rowe and Randall E. Mehrberg, or either of them, attorney for me and in my name and on my behalf to sign the annual Securities and Exchange Commission report on Form 10-K for 2004 of Exelon Corporation, together with any amendments thereto, to be filed with the Securities and Exchange Commission, and generally to do and perform all things necessary to be done in the premises as fully and effectually in all respects as I could do if personally present.
| /s/ NELSON A. DIAZ |
| Nelson A. Diaz |
DATE: February 22, 2005
Exhibit 24-6
POWER OF ATTORNEY
KNOWN ALL MEN BY THESE PRESENTS that I, Sue L. Gin do hereby appoint John W. Rowe and Randall E. Mehrberg, or either of them, attorney for me and in my name and on my behalf to sign the annual Securities and Exchange Commission report on Form 10-K for 2004 of Exelon Corporation, together with any amendments thereto, to be filed with the Securities and Exchange Commission, and generally to do and perform all things necessary to be done in the premises as fully and effectually in all respects as I could do if personally present.
| /s/ SUE L. GIN |
| Sue L. Gin |
DATE: February 22, 2005
Exhibit 24-7
POWER OF ATTORNEY
KNOWN ALL MEN BY THESE PRESENTS that I, Rosemarie B. Greco do hereby appoint John W. Rowe and Randall E. Mehrberg, or either of them, attorney for me and in my name and on my behalf to sign the annual Securities and Exchange Commission report on Form 10-K for 2004 of Exelon Corporation, together with any amendments thereto, to be filed with the Securities and Exchange Commission, and generally to do and perform all things necessary to be done in the premises as fully and effectually in all respects as I could do if personally present.
| /s/ ROSEMARIE B. GRECO |
| Rosemarie B. Greco |
DATE: February 22, 2005
Exhibit 24-8
POWER OF ATTORNEY
KNOWN ALL MEN BY THESE PRESENTS that I, Edgar D. Jannotta do hereby appoint John W. Rowe and Randall E. Mehrberg, or either of them, attorney for me and in my name and on my behalf to sign the annual Securities and Exchange Commission report on Form 10-K for 2004 of Exelon Corporation, together with any amendments thereto, to be filed with the Securities and Exchange Commission, and generally to do and perform all things necessary to be done in the premises as fully and effectually in all respects as I could do if personally present.
| /s/ EDGAR D. JANNOTTA |
| Edgar D. Jannotta |
DATE: February 23, 2005
Exhibit 24-9
POWER OF ATTORNEY
KNOWN ALL MEN BY THESE PRESENTS that I, John M. Palms, Ph.D. do hereby appoint John W. Rowe and Randall E. Mehrberg, or either of them, attorney for me and in my name and on my behalf to sign the annual Securities and Exchange Commission report on Form 10-K for 2004 of Exelon Corporation, together with any amendments thereto, to be filed with the Securities and Exchange Commission, and generally to do and perform all things necessary to be done in the premises as fully and effectually in all respects as I could do if personally present.
| /s/ JOHN M. PALMS |
| John M. Palms, Ph.D. |
DATE: February 19, 2005
Exhibit 24-10
POWER OF ATTORNEY
KNOWN ALL MEN BY THESE PRESENTS that I, John W. Rogers, Jr. do hereby appoint John W. Rowe and Randall E. Mehrberg, or either of them, attorney for me and in my name and on my behalf to sign the annual Securities and Exchange Commission report on Form 10-K for 2004 of Exelon Corporation, together with any amendments thereto, to be filed with the Securities and Exchange Commission, and generally to do and perform all things necessary to be done in the premises as fully and effectually in all respects as I could do if personally present.
| /s/ JOHN W. ROGERS, JR. |
| John W. Rogers, Jr. |
DATE: February 23, 2005
Exhibit 24-11
POWER OF ATTORNEY
KNOWN ALL MEN BY THESE PRESENTS that I, Ronald Rubin do hereby appoint John W. Rowe and Randall E. Mehrberg, or either of them, attorney for me and in my name and on my behalf to sign the annual Securities and Exchange Commission report on Form 10-K for 2004 of Exelon Corporation, together with any amendments thereto, to be filed with the Securities and Exchange Commission, and generally to do and perform all things necessary to be done in the premises as fully and effectually in all respects as I could do if personally present.
| /S/ RONALD RUBIN
| ||
| Ronald Rubin | ||
DATE: February 22, 2005
Exhibit 24-12
POWER OF ATTORNEY
KNOWN ALL MEN BY THESE PRESENTS that I, Richard L. Thomas do hereby appoint John W. Rowe and Randall E. Mehrberg, or either of them, attorney for me and in my name and on my behalf to sign the annual Securities and Exchange Commission report on Form 10-K for 2004 of Exelon Corporation, together with any amendments thereto, to be filed with the Securities and Exchange Commission, and generally to do and perform all things necessary to be done in the premises as fully and effectually in all respects as I could do if personally present.
| /S/ RICHARD L. THOMAS
| ||
| Richard L. Thomas | ||
DATE: February 21, 2005
Exhibit 31-1
CERTIFICATION PURSUANT TO RULE 13a-14(a) AND 15d-14(a) OF THE SECURITIES AND EXCHANGE ACT OF 1934
I, John W. Rowe, certify that:
1. I have reviewed this annual report on Form 10-K of Exelon Corporation;
2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
(b) Designed such internal control over financial reporting, or caused such internal control over financing reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s fourth fiscal quarter that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and
5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):
(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.
| Date: February 23, 2005 |
/s/ JOHN W. ROWE | |||||||
| Chairman, Chief Executive Officer and President (Principal Executive Officer) | ||||||||
Exhibit 31-2
CERTIFICATION PURSUANT TO RULE 13a-14(a) AND 15d-14(a) OF THE SECURITIES AND EXCHANGE ACT OF 1934
I, Robert S. Shapard, certify that:
1. I have reviewed this annual report on Form 10-K of Exelon Corporation;
2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
(b) Designed such internal control over financial reporting, or caused such internal control over financing reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s fourth fiscal quarter that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and
5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):
(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.
| Date: February 23, 2005 |
/s/ ROBERT S. SHAPARD | |||||||
| Executive Vice President and Chief Financial Officer (Principal Financial Officer) | ||||||||
Exhibit 31-3
CERTIFICATION PURSUANT TO RULE 13a-14(a) AND 15d-14(a) OF THE SECURITIES AND EXCHANGE ACT OF 1934
I, John L. Skolds, certify that:
1. I have reviewed this annual report on Form 10-K of Commonwealth Edison Company;
2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) for the registrant and have:
(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
(b) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
(c) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s fourth fiscal quarter that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and
5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):
(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.
| Date: February 23, 2005 |
/s/ JOHN L. SKOLDS | |||||||
| President, Exelon Energy Delivery (Principal Executive Officer) | ||||||||
Exhibit 31-4
CERTIFICATION PURSUANT TO RULE 13a-14(a) AND 15d-14(a) OF THE SECURITIES AND EXCHANGE ACT OF 1934
I, J. Barry Mitchell, certify that:
1. I have reviewed this annual report on Form 10-K of Commonwealth Edison Company;
2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) for the registrant and have:
(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
(b) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
(c) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s fourth fiscal quarter that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and
5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):
(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.
| Date: February 23, 2005 |
/s/ J. BARRY MITCHELL | |||||
| Senior Vice President, Treasurer and Chief Financial Officer (Principal Financial Officer) | ||||||
Exhibit 31-5
CERTIFICATION PURSUANT TO RULE 13a-14(a) AND 15d-14(a) OF THE SECURITIES AND EXCHANGE ACT OF 1934
I, John L. Skolds, certify that:
1. I have reviewed this annual report on Form 10-K of PECO Energy Company;
2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) for the registrant and have:
(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
(b) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
(c) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s fourth fiscal quarter that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and
5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):
(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.
| Date: February 23, 2005 |
/s/ JOHN L. SKOLDS | |||||||
| President, Exelon Energy Delivery (Principal Executive Officer) | ||||||||
Exhibit 31-6
CERTIFICATION PURSUANT TO RULE 13a-14(a) AND 15d-14(a) OF THE SECURITIES AND EXCHANGE ACT OF 1934
I, J. Barry Mitchell, certify that:
1. I have reviewed this annual report on Form 10-K of PECO Energy Company;
2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) for the registrant and have:
(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
(b) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
(c) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s fourth fiscal quarter that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and
5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):
(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.
| Date: February 23, 2005 |
/s/ J. BARRY MITCHELL | |||
| Senior Vice President, Treasurer and Chief Financial Officer (Principal Financial Officer) | ||||
Exhibit 31-7
CERTIFICATION PURSUANT TO RULE 13a-14(a) AND 15d-14(a) OF THE SECURITIES AND EXCHANGE ACT OF 1934
I, John F. Young, certify that:
1. I have reviewed this annual report on Form 10-K of Exelon Generation Company, LLC;
2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) for the registrant and have:
(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
(b) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
(c) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s fourth fiscal quarter that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and
5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):
(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.
| Date: February 23, 2005 |
/s/ JOHN F. YOUNG | |||||||
| President (Principal Executive Officer) | ||||||||
Exhibit 31-8
CERTIFICATION PURSUANT TO RULE 13a-14(a) AND 15d-14(a) OF THE SECURITIES AND EXCHANGE ACT OF 1934
I, J. Barry Mitchell, certify that:
1. I have reviewed this annual report on Form 10-K of Exelon Generation Company, LLC;
2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) for the registrant and have:
(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
(b) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
(c) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s fourth fiscal quarter that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and
5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):
(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.
| Date: February 23, 2005 |
/s/ J. BARRY MITCHELL | |||||
| Senior Vice President, Treasurer and Chief Financial Officer (Principal Financial Officer) | ||||||
Exhibit 32-1
Certificate Pursuant to Section 1350 of Chapter 63 of Title 18 United States Code
The undersigned officer hereby certifies, as to the Report on Form 10-K of Exelon Corporation for the year ended December 31, 2004, that (i) the report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934, and (ii) the information contained in the report fairly presents, in all material respects, the financial condition and results of operations of Exelon Corporation.
| Date: February 23, 2005 |
/s/ JOHN W. ROWE | |||||||
| John W. Rowe Chairman, Chief Executive Officer and President | ||||||||
Exhibit 32-2
Certificate Pursuant to Section 1350 of Chapter 63 of Title 18 United States Code
The undersigned officer hereby certifies, as to the Report on Form 10-K of Exelon Corporation for the year ended December 31, 2004, that (i) the report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934, and (ii) the information contained in the report fairly presents, in all material respects, the financial condition and results of operations of Exelon Corporation.
| Date: February 23, 2005 |
/s/ ROBERT S. SHAPARD | |||||||
| Robert S. Shapard Executive Vice President and Chief Financial Officer | ||||||||
Exhibit 32-3
Certificate Pursuant to Section 1350 of Chapter 63 of Title 18 United States Code
The undersigned officer hereby certifies, as to the Report on Form 10-K of Commonwealth Edison Company for the year ended December 31, 2004, that (i) the report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934, and (ii) the information contained in the report fairly presents, in all material respects, the financial condition and results of operations of Commonwealth Edison Company.
| Date: February 23, 2005 |
/s/ JOHN L. SKOLDS | |||||||
| John L. Skolds President Exelon Energy Delivery | ||||||||
Exhibit 32-4
Certificate Pursuant to Section 1350 of Chapter 63 of Title 18 United States Code
The undersigned officer hereby certifies, as to the Report on Form 10-K of Commonwealth Edison Company for the year ended December 31, 2004, that (i) the report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934, and (ii) the information contained in the report fairly presents, in all material respects, the financial condition and results of operations of Commonwealth Edison Company.
| Date: February 23, 2005 |
/s/ J. BARRY MITCHELL | |||||||
| J. Barry Mitchell Senior Vice President, Treasurer and Chief Financial Officer | ||||||||
Exhibit 32-5
Certificate Pursuant to Section 1350 of Chapter 63 of Title 18 United States Code
The undersigned officer hereby certifies, as to the Report on Form 10-K of PECO Energy Company for the year ended December 31, 2004, that (i) the report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934, and (ii) the information contained in the report fairly presents, in all material respects, the financial condition and results of operations of PECO Energy Company.
| Date: February 23, 2005 |
/s/ JOHN L. SKOLDS | |||||||
| John L. Skolds President Exelon Energy Delivery | ||||||||
Exhibit 32-6
Certificate Pursuant to Section 1350 of Chapter 63 of Title 18 United States Code
The undersigned officer hereby certifies, as to the Report on Form 10-K of PECO Energy Company for the year ended December 31, 2004, that (i) the report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934, and (ii) the information contained in the report fairly presents, in all material respects, the financial condition and results of operations of PECO Energy Company.
| Date: February 23, 2005 |
/s/ J. BARRY MITCHELL | |||||||
| J. Barry Mitchell Senior Vice President, Treasurer and Chief Financial Officer | ||||||||
Exhibit 32-7
Certificate Pursuant to Section 1350 of Chapter 63 of Title 18 United States Code
The undersigned officer hereby certifies, as to the Report on Form 10-K of Exelon Generation Company, LLC for the year ended December 31, 2004, that (i) the report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934, and (ii) the information contained in the report fairly presents, in all material respects, the financial condition and results of operations of Exelon Generation Company, LLC.
| Date: February 23, 2005 |
/s/ JOHN F. YOUNG | |||||||
| John F. Young President | ||||||||
Exhibit 32-8
Certificate Pursuant to Section 1350 of Chapter 63 of Title 18 United States Code
The undersigned officer hereby certifies, as to the Report on Form 10-K of Exelon Generation Company, LLC for the year ended December 31, 2004, that (i) the report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934, and (ii) the information contained in the report fairly presents, in all material respects, the financial condition and results of operations of Exelon Generation Company, LLC.
| Date: February 23, 2005 |
/s/ J. BARRY MITCHELL | |||||||
| J. Barry Mitchell Senior Vice President, Treasurer and Chief Financial Officer | ||||||||