UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, DC 20549
FORM 8-K
CURRENT REPORT
Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934
October 23, 2009
Date of Report (Date of earliest event reported)
| Commission File |
Exact Name of Registrant as Specified in Its Charter; State of Incorporation; Address of Principal Executive Offices; and Telephone Number |
IRS Employer | ||
| 1-16169 | EXELON CORPORATION (a Pennsylvania corporation) 10 South Dearborn Street P.O. Box 805379 Chicago, Illinois 60680-5379 (312) 394-7398 |
23-2990190 | ||
| 333-85496 | EXELON GENERATION COMPANY, LLC (a Pennsylvania limited liability company) 300 Exelon Way Kennett Square, Pennsylvania 19348-2473 (610) 765-5959 |
23-3064219 | ||
| 1-1839 | COMMONWEALTH EDISON COMPANY (an Illinois corporation) 440 South LaSalle Street Chicago, Illinois 60605-1028 (312) 394-4321 |
36-0938600 | ||
| 000-16844 | PECO ENERGY COMPANY (a Pennsylvania corporation) P.O. Box 8699 2301 Market Street Philadelphia, Pennsylvania 19101-8699 (215) 841-4000 |
23-0970240 | ||
Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligation of the registrant under any of the following provisions:
| ¨ | Written communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425) |
| ¨ | Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12) |
| ¨ | Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b)) |
| ¨ | Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c)) |
Section 2 – Financial Information
| Item 2.02. | Results of Operations and Financial Condition. |
Section 7 – Regulation FD
| Item 7.01. | Regulation FD Disclosure. |
On October 23, 2009, Exelon Corporation (Exelon) announced via press release Exelon’s results for the third quarter ended September 30, 2009. A copy of the press release and related attachments is attached hereto as Exhibit 99.1. Also attached as Exhibit 99.2 to this Current Report on Form 8-K are the presentation slides to be used at the third quarter 2009 earnings conference call. This Form 8-K and the attached exhibits are provided under Items 2.02, 7.01 and 9.01 of Form 8-K and are furnished to, but not filed with, the Securities and Exchange Commission.
Section 9 – Financial Statements and Exhibits
| Item 9.01. | Financial Statements and Exhibits. |
| (d) | Exhibits. |
| Exhibit No. |
Description | |
| 99.1 | Press release and earnings release attachments | |
| 99.2 | Earnings conference call presentation slides | |
* * * * *
This combined Form 8-K is being furnished separately by Exelon, Exelon Generation Company, LLC, Commonwealth Edison Company and PECO Energy Company (Registrants). Information contained herein relating to any individual Registrant has been furnished by such Registrant on its own behalf. No Registrant makes any representation as to information relating to any other Registrant.
This Current Report includes 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 these forward-looking statements include those discussed herein as well as those discussed in (1) Exelon’s 2008 Annual Report on Form 10-K in (a) ITEM 1A. Risk Factors, (b) ITEM 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations and (c) ITEM 8. Financial Statements and Supplementary Data: Note 18; (2) Exelon’s Third Quarter 2009 Quarterly Report on Form 10-Q (to be filed on October 23, 2009) in (a) Part II, Other Information, ITEM 1A. Risk Factors and (b) Part I, Financial Information, ITEM 1. Financial Statements: Note 14; and (3) other factors discussed in filings with the Securities and Exchange Commission 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 Current 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 Current Report.
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, each Registrant has duly caused this report to be signed on its behalf by the undersigned hereunto duly authorized.
| EXELON CORPORATION EXELON GENERATION COMPANY, LLC |
| /s/ Matthew F. Hilzinger |
| Matthew F. Hilzinger |
| Senior Vice President and Chief Financial Officer |
| Exelon Corporation |
| COMMONWEALTH EDISON COMPANY |
| /s/ Joseph R. Trpik, Jr. |
| Joseph R. Trpik, Jr. |
| Senior Vice President, Chief Financial Officer and Treasurer |
| Commonwealth Edison Company |
| PECO ENERGY COMPANY |
| /s/ Phillip S. Barnett |
| Phillip S. Barnett |
| Senior Vice President and Chief Financial Officer |
| PECO Energy Company |
October 23, 2009
EXHIBIT INDEX
| Exhibit No. |
Description | |
| 99.1 | Press release and earnings release attachments | |
| 99.2 | Earnings conference call presentation slides | |
EXHIBIT 99.1
| Contact: | Karie Anderson | FOR IMMEDIATE RELEASE | ||
| Investor Relations | ||||
| 312-394-4255 | ||||
| Kathleen Cantillon | ||||
| Corporate Communications | ||||
| 312-394-7417 | ||||
Exelon Announces Third Quarter Results;
Narrows Full Year 2009 Earnings Guidance
CHICAGO (October 23, 2009) – Exelon Corporation (NYSE: EXC) today announced that its third quarter 2009 consolidated earnings prepared in accordance with GAAP were $757 million, or $1.14 per diluted share, compared with earnings of $700 million, or $1.06 per diluted share, in the third quarter of 2008.
Exelon’s adjusted (non-GAAP) operating earnings for the third quarter of 2009 were $633 million, or $0.96 per diluted share, compared with $706 million, or $1.07 per diluted share, for the same period in 2008.
“We are achieving our financial commitments despite difficult weather, economic and market conditions,” said John W. Rowe, Exelon’s chairman and CEO. “We continue to deliver cost savings and solid operations as shown by a 94.7 percent nuclear capacity factor for the third quarter and reliable utility performance through the critical summer months. We remain committed to achieving full year 2009 operating earnings within the guidance range we issued last fall and are narrowing that range to $4.00 to $4.10 per share.”
The decrease in third quarter 2009 adjusted (non-GAAP) operating earnings to $0.96 per share from $1.07 per share in third quarter 2008 was primarily due to:
| • | Lower energy gross margins at Exelon Generation Company, LLC (Generation) largely due to unfavorable portfolio and market conditions; |
| • | Higher costs at Generation associated with a higher number of scheduled nuclear refueling outage days; |
| • | Reversal of benefits recorded in the first quarter of 2009 related to an Illinois investment tax credit ruling; |
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| • | Reduced load at Commonwealth Edison Company (ComEd) and PECO Energy Company (PECO), primarily driven by the impact of unfavorable weather conditions and current economic conditions; and |
| • | Increased depreciation and amortization expense primarily related to the higher scheduled competitive transition charge (CTC) amortization at PECO and increased depreciation across the operating companies due to ongoing capital expenditures. |
Lower third quarter 2009 earnings were partially offset by:
| • | Increased electric distribution revenue at ComEd resulting from the September 2008 distribution rate case order; and |
| • | Decreased operating and maintenance expense largely due to savings achieved through the ongoing cost management initiative and lower uncollectible accounts expense at PECO, partially offset by increased pension and other postretirement benefits (OPEB) expense. |
Adjusted (non-GAAP) operating earnings for the third quarter of 2009 do not include the following items (after-tax) that were included in reported GAAP earnings:
| • | Unrealized gains of $87 million, or $0.13 per diluted share, related to nuclear decommissioning trust (NDT) fund investments; |
| • | Mark-to-market gains of $77 million, or $0.12 per diluted share, primarily from Generation’s economic hedging activities; |
| • | Costs totaling $58 million, or $0.09 per diluted share, associated with early debt retirements; |
| • | Income of $32 million, or $0.05 per diluted share, resulting from the reduction in Generation’s decommissioning obligations; |
| • | Costs of $11 million, or $0.02 per diluted share, associated with the 2007 Illinois electric rate settlement agreement; |
| • | External costs of $6 million, or $0.01 per diluted share, related to Exelon’s terminated offer to acquire NRG Energy, Inc. (NRG); and |
| • | Income of $3 million for the true-up of severance costs as a result of headcount reductions associated with Exelon’s cost management program. |
Adjusted (non-GAAP) operating earnings for the third quarter of 2008 did not include the following items (after-tax) that were included in reported GAAP earnings:
| • | Mark-to-market gains of $65 million, or $0.10 per diluted share, primarily from Generation’s economic hedging activities; |
| • | Costs of $26 million, or $0.04 per diluted share, associated with the 2007 Illinois electric rate settlement agreement; |
| • | Unrealized losses of $60 million, or $0.09 per diluted share, related to NDT fund investments; and |
| • | Income of $15 million, or $0.02 per diluted share, resulting from the reduction in Generation’s decommissioning obligations. |
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2009 Earnings Outlook
Exelon narrowed its guidance range for 2009 adjusted (non-GAAP) operating earnings to $4.00 to $4.10 per share from $4.00 to $4.30 per share. Operating earnings guidance is based on the assumption of normal weather for the remainder of the year.
The outlook for 2009 adjusted (non-GAAP) operating earnings for Exelon and its subsidiaries excludes the following items:
| • | Mark-to-market adjustments from economic hedging activities |
| • | Unrealized gains and losses from NDT fund investments primarily related to the Clinton, Oyster Creek and Three Mile Island nuclear plants (the former AmerGen units) |
| • | Significant impairments of assets, including goodwill |
| • | Changes in decommissioning obligation estimates |
| • | Costs associated with the 2007 Illinois electric rate settlement agreement |
| • | Costs associated with ComEd’s 2007 settlement with the City of Chicago |
| • | Costs incurred for employee severance related to the cost reduction program announced in June 2009 |
| • | Costs associated with early debt retirements |
| • | External costs associated with the terminated offer to acquire NRG |
| • | Non-cash remeasurement of income tax uncertainties and reassessment of state deferred income taxes |
| • | Other unusual items |
| • | Significant future changes to GAAP |
Third Quarter and Recent Highlights
| • | Nuclear Operations: Generation’s nuclear fleet, including its owned output from the Salem Generating Station, produced 35,684 gigawatt-hours (GWh) in the third quarter of 2009, compared with 36,451 GWh in the third quarter of 2008. The Exelon-operated nuclear plants achieved a 94.7 percent capacity factor for the third quarter of 2009 compared with 97.2 percent for the third quarter of 2008. The Exelon-operated nuclear plants began two scheduled refueling outages in the third quarter of 2009, compared with beginning one scheduled refueling outage in the third quarter of 2008. The number of refueling outage days totaled 36 and 17, respectively, in the third quarter of 2009 and 2008. Also contributing to lower total nuclear output was a higher number of non-refueling outage days at the Exelon-operated plants, which totaled 21 days in the third quarter of 2009, compared to 8 days in the third quarter of 2008. |
| • | Fossil and Hydro Operations: Generation’s fossil fleet commercial availability was 87.0 percent in the third quarter of 2009, compared with 95.1 percent in the third quarter of 2008, primarily reflecting the impact of extended maintenance outages in 2009. The equivalent availability factor for the hydroelectric facilities was 97.1 percent in the third quarter of 2009, compared with 90.9 percent in the third quarter of 2008, primarily due to an extended planned outage in 2008 to overhaul one of the Conowingo units. |
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| • | Three Mile Island (TMI) Unit 1 Nuclear Plant License Extension: On October 22, 2009, the Nuclear Regulatory Commission approved a 20-year operating license extension until April 19, 2034 for the TMI Unit 1 Generating Station. TMI Unit 1 began operating in 1974. |
| • | Hedging Update: Exelon’s hedging program involves the hedging of commodity risk for Exelon’s expected generation, typically on a ratable basis over a three-year period. Expected generation represents the amount of energy estimated to be generated or purchased through owned or contracted-for capacity. The proportion of expected generation hedged as of September 30, 2009 is 98-100 percent for 2009, 88-91 percent for 2010 and 63-66 percent for 2011. The primary objective of Exelon’s hedging program is to manage market risks and protect the value of its generation and its investment grade balance sheet while preserving its ability to participate in improving long-term market fundamentals. |
| • | ComEd Smart Meter/Smart Grid Plan: On June 1, 2009, ComEd filed a petition with the Illinois Commerce Commission (ICC) recommending a one-year Advanced Metering Infrastructure (AMI) pilot program. Current plans call for the deployment of approximately 131,000 smart meters in 10 suburban communities and in the City of Chicago, and will include tests of customers’ responses to alternative pricing plans, in-home displays and Home Area Network control systems. ComEd requested recovery of and a return on its investment through a rider beginning in 2010. On October 14, 2009, the ICC approved ComEd’s AMI pilot program and rider with minor modifications. |
On August 4, 2009, ComEd announced it filed an application with the U.S. Department of Energy (DOE) for $175 million in matching funds made available under the American Recovery and Reinvestment Act of 2009. The matching funds would enable an expansion of the company’s AMI pilot, from approximately 131,000 customers to 310,000 customers, and additional investments in Smart Grid technologies. The DOE is expected to select projects for funding later this year.
On September 2, 2009, ComEd submitted a petition to the ICC requesting recovery of the remaining costs of the stimulus projects after receiving the matching funds from the DOE.
| • | Illinois Uncollectibles Recovery Rider: On August 9, 2009, Illinois Governor Pat Quinn signed legislation that includes assistance to low-income customers to manage their energy bills. In addition, the legislation includes a provision for utilities to recover their actual uncollectible accounts expenses through a rider adjustment mechanism. The rider would minimize regulatory lag during times when uncollectible accounts expenses are increasing beyond what is recovered through base rates and provide credits when lower than what is covered in base rates. On September 8, 2009, ComEd filed a proposed tariff with the ICC to implement this rider. An ICC decision is expected in the first quarter of 2010. |
| • | PECO Smart Meter/Smart Grid Plan: PECO is planning to spend up to approximately $650 million on its smart meter and smart grid infrastructure. On August 14, 2009, PECO filed its $550 million Smart Meter Procurement and Installation Plan with the Pennsylvania Public Utility Commission (PAPUC) in accordance with the requirements of Pennsylvania Act 129. PECO is requesting PAPUC approval to install more than 1.6 million smart meters and deploy advanced |
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communication networks over a 15-year period. The first phase of the plan includes the procurement and deployment of automated meter infrastructure and initial deployment of 100,000 smart meters over the next three years.
On August 6, 2009, PECO filed with the DOE its application seeking $200 million in American Recovery and Reinvestment Act grant funds under the Smart Grid Investment Grant Program. PECO’s “Smart Future Greater Philadelphia” project will increase the number of smart meters initially installed to 600,000, accelerate universal meter deployment by five years and increase Smart Grid investments up to approximately $100 million over the next three years.
| • | PECO Energy Procurement: On September 23, 2009, the PAPUC approved the results of PECO’s second competitive procurement request for proposal (RFP) for residential customers and its initial generation supply procurement for the small and medium commercial classes. The September procurements for the residential class included full requirements fixed price contracts for 17-month and 29-month periods beginning January 1, 2011, and forward purchase block contracts to procure electric generation for the 12-month period beginning January 1, 2011. The procurements for the small and medium commercial classes included full requirements fixed-price contracts for the 17-month period beginning January 1, 2011. |
The June and September procurements combined accounted for approximately 49 percent of the total full requirements electricity needed for PECO’s residential customers beginning in 2011 at an average retail price of 9.41 cents per kilowatt-hour (kWh), about a 4 percent increase compared to current prices. The September procurement accounted for approximately 24 percent and 16 percent of the full requirement fixed-price product for PECO’s small and medium commercial customers, respectively, at an average blended retail price of 9.79 cents per kWh. PECO’s next supply purchases for the residential and the small and medium commercial classes will take place in May 2010.
| • | Pension Contribution: On September 9, 2009, Exelon announced that it was making a $350 million discretionary pension contribution allocated to the 2008 plan year, taking advantage of Federal pension funding relief provided by the Worker, Retiree and Employer Recovery Act of 2008 that allows use of average expected returns to establish asset values for determining funding requirements. The U.S. Treasury Department also has provided some funding relief through options in selecting the interest rates used for funding. The discretionary pension contribution – funded with cash from operations in excess of Exelon’s original 2009 plan – and Exelon’s pension funding elections will lower near-term mandatory pension contributions, which should increase future financial flexibility. |
| • | Financing Activities: On September 23, 2009, Generation issued $600 million of Senior Notes maturing on October 1, 2019, with a coupon of 5.20 percent and $900 million of Senior Notes maturing on October 1, 2039, with a coupon of 6.25 percent. Generation used the net proceeds from the sale (1) to pay approximately $622 million of principal, premium and accrued interest in connection with the purchase of approximately $555 million in aggregate principal amount of its 6.95 percent Notes due June 15, 2011 pursuant to Generation’s cash tender offer announced on September 16, 2009, (2) for a $432 million distribution to Exelon Corporation to fund its purchase of approximately $387 million in aggregate principal amount of its 6.75 percent Senior |
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Notes due May 1, 2011 pursuant to its cash tender offer announced on September 16, 2009, and (3) to fund Generation’s repurchase of $307 million of pollution-control bonds in early September. On September 23, 2009, Exelon Corporation and Generation called the remaining bonds that were not tendered pursuant to their tender offers, according to the terms of the respective bond issues. These bonds are obligated to be tendered today under the terms of the bonds and the call notices. Through these debt repurchase and refinancing activities, Exelon was able to capitalize on favorable market conditions, resulting in lower interest expense and an extended debt maturity profile.
| • | Credit Rating Actions: Following the termination of Exelon’s proposed offer for NRG on July 21, 2009, the rating agencies took the following actions. |
On July 21, 2009, Fitch Ratings, Ltd. removed Exelon and Generation from Ratings Watch Negative. The ratings for Exelon and Generation were affirmed and each entity was assigned a Stable Ratings Outlook.
On July 22, 2009, Standard & Poor’s Ratings Services (S&P) affirmed its corporate credit rating on Exelon, Generation and PECO of “BBB” and removed their ratings from CreditWatch Negative. In addition, S&P raised the corporate credit rating of ComEd to “BBB” from “BBB-”, raised its debt and preferred stock ratings and removed its ratings from CreditWatch Negative. An S&P research report cited “improvement in both ComEd’s business risk profile and its financial measures”. The outlook for ratings of all the Exelon entities is stable.
On July 23, 2009, Moody’s Investors Service (Moody’s) confirmed the ratings of Exelon and Generation and assigned a stable outlook. Moody’s also confirmed the long-term debt rating of PECO but downgraded its short-term rating to “P-2” from “P-1” and changed the outlook on PECO’s long-term debt to negative.
On August 3, 2009, Moody’s changed its credit rating methodology, widening the notching between most senior secured debt ratings and senior unsecured debt ratings of investment grade regulated utilities. As a result, Moody’s upgraded ComEd’s senior secured debt rating to “Baa1” from “Baa2”.
OPERATING COMPANY RESULTS
Generation consists of owned and contracted electric generating facilities, wholesale energy marketing operations and competitive retail sales operations.
Third quarter 2009 net income was $657 million compared with $635 million in the third quarter of 2008. Third quarter 2009 net income included (all after tax) costs of $9 million associated with the 2007 Illinois electric rate settlement, mark-to-market gains of $77 million from economic hedging activities before the elimination of intercompany transactions, unrealized gains of $87 million related to NDT fund investments, income of $32 million resulting from the reduction in decommissioning obligations primarily related to the former AmerGen nuclear plants, income of $2 million from the true-up of 2009 costs incurred for severance, and costs of $36 million associated with the early retirement of long-term debt. Third quarter 2008 net income included (all after tax) costs of $25 million associated with the
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2007 Illinois electric rate settlement, mark-to-market gains of $96 million from economic hedging activities before the elimination of intercompany transactions, unrealized losses of $60 million related to NDT fund investments primarily related to the former AmerGen nuclear plants, and income of $15 million resulting from the reduction in decommissioning obligations primarily related to the former AmerGen nuclear plants. Excluding the impact of these items, Generation’s net income in the third quarter of 2009 decreased $105 million compared with the same quarter last year primarily due to:
| • | Lower energy gross margins, largely due to unfavorable portfolio and market conditions, decreased nuclear output as a result of a higher number of refueling and non-refueling outage days and higher nuclear fuel costs; and |
| • | Higher costs related to a higher number of scheduled nuclear refueling outage days and increased pension and OPEB expense. |
The decrease in net income was partially offset by:
| • | Establishment of a reserve in 2008 related to Generation’s accounts receivable from Lehman Brothers Holdings Inc. due to its bankruptcy filing; and |
| • | Savings achieved through the cost management initiative. |
Generation’s average realized margin on all electric sales, including sales to affiliates and excluding trading activity, was $36.32 per MWh in the third quarter of 2009 compared with $36.54 per MWh in the third quarter of 2008.
ComEd consists of the electricity transmission and distribution operations in northern Illinois.
ComEd recorded net income of $46 million in the third quarter of 2009, compared with net income of $33 million in the third quarter of 2008. Third quarter net income in 2009 and 2008 included costs of $2 million and $1 million after tax, respectively, associated with the Illinois electric rate settlement. Excluding the impact of these items, ComEd’s net income in the third quarter of 2009 increased $14 million from the same quarter last year primarily due to:
| • | Increased distribution revenue due to the September 2008 distribution rate case order; |
| • | Lower operating and maintenance expense, which primarily reflected savings achieved through the cost management initiative and the impact of decreased storm costs, partially offset by increased pension and OPEB expense; and |
| • | Discrete disallowances recorded in 2008, net of allowed regulatory assets, mandated by the September 2008 rate case order. |
The increase in net income was partially offset by:
| • | Reversal of an Illinois investment tax credit ruling – this benefit previously was recorded in the first quarter of 2009; and |
| • | Reduced load, primarily driven by the impact of unfavorable weather conditions and current economic conditions. |
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In the third quarter of 2009, cooling degree-days in the ComEd service territory were down 34.2 percent relative to the same period in 2008, and were 34.0 percent below normal. This reflected the Chicago area’s coolest summer weather in 17 years. ComEd’s total retail kilowatt-hour (kWh) deliveries decreased by 9.8 percent quarter over quarter, with declines in deliveries to all major customer classes. In addition, the number of residential customers being served in the ComEd region decreased 0.5 percent from the third quarter of 2008.
Weather-normalized retail kWh deliveries decreased by 3.8 percent from the third quarter of 2008. For ComEd, weather had an unfavorable after-tax impact of $18 million on third quarter 2009 earnings relative to 2008 and an unfavorable after-tax impact of $24 million relative to normal weather that was incorporated in earnings guidance.
PECO consists of the electricity transmission and distribution operations and the retail natural gas distribution business in southeastern Pennsylvania.
PECO’s net income in the third quarter of 2009 was $92 million, up from $90 million in the third quarter of 2008. This increase was primarily due to:
| • | Lower uncollectible accounts expense. |
The increase in net income was partially offset by:
| • | Reduced load, primarily driven by the impact of current economic conditions and unfavorable weather conditions; and |
| • | Higher CTC amortization, which was in accordance with PECO’s 1998 restructuring settlement with the PAPUC. As expected, the increase in amortization expense exceeded the increase in CTC revenues. |
In the third quarter of 2009, cooling degree-days in the PECO service territory were down 6.2 percent from 2008, and were 5.9 percent below normal. Total retail kWh deliveries were down 5.6 percent from last year, reflecting a decline in deliveries across all customer classes, primarily driven by the impact of current economic conditions and unfavorable weather conditions. The number of residential electric customers being served in the PECO region decreased 0.4 percent from the third quarter of 2008.
Weather-normalized retail kWh deliveries decreased by 3.9 percent from the third quarter of 2008, primarily reflecting decreased residential and large commercial and industrial deliveries. For PECO, weather had an unfavorable after-tax impact of $9 million on third quarter 2009 earnings relative to 2008 and an unfavorable after-tax impact of $19 million relative to normal weather that was incorporated in earnings guidance.
Adjusted (non-GAAP) Operating Earnings
Adjusted (non-GAAP) operating earnings, which generally exclude significant one-time charges or credits that are not normally associated with ongoing operations, mark-to-market adjustments from economic hedging activities and unrealized gains and losses from NDT fund investments, are provided as a supplement to results reported in accordance with GAAP. Management uses such adjusted (non-
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GAAP) operating earnings measures internally to evaluate the company’s performance and manage its operations. Reconciliation of GAAP to adjusted (non-GAAP) operating earnings for historical periods is attached. Additional earnings release attachments, which include the reconciliation on page 7, are posted on Exelon’s Web site: www.exeloncorp.com and have been filed with the Securities and Exchange Commission on Form 8-K on October 23, 2009.
Conference call information: Exelon has scheduled a conference call for 10:30 AM ET (9:30 AM CT) on October 23, 2009. The call-in number in the U.S. and Canada is 800-690-3108, and the international call-in number is 973-935-8753. If requested, the conference ID number is 32242270. Media representatives are invited to participate on a listen-only basis. The call will be web-cast and archived on Exelon’s Web site: www.exeloncorp.com. (Please select the Investor Relations page.)
Telephone replays will be available until November 6. The U.S. and Canada call-in number for replays is 800-642-1687, and the international call-in number is 706-645-9291. The conference ID number is 32242270.
Forward Looking Statements
This press release includes 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 these forward-looking statements include those discussed herein as well as those discussed in (1) Exelon’s 2008 Annual Report on Form 10-K in (a) ITEM 1A. Risk Factors, (b) ITEM 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations and (c) ITEM 8. Financial Statements and Supplementary Data: Note 18; (2) Exelon’s Third Quarter 2009 Quarterly Report on Form 10-Q (to be filed on October 23, 2009) in (a) Part II, Other Information, ITEM 1A. Risk Factors and (b) Part I, Financial Information, ITEM 1. Financial Statements: Note 14; and (3) other factors discussed in filings with the Securities and Exchange Commission (SEC) by Exelon Corporation, Commonwealth Edison Company, PECO Energy Company and Exelon Generation Company, LLC (Companies). Readers are cautioned not to place undue reliance on these forward-looking statements, which apply only as of the date of this press release. None of the Companies undertakes any obligation to publicly release any revision to its forward-looking statements to reflect events or circumstances after the date of this press release.
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Exelon Corporation is one of the nation’s largest electric utilities with approximately 5.4 million customers and $19 billion in annual revenues. The company has one of the industry’s largest portfolios of electricity generation capacity, with a nationwide reach and strong positions in the Midwest and Mid-Atlantic. Exelon distributes electricity to approximately 5.4 million customers in Illinois and Pennsylvania and natural gas to approximately 485,000 customers in southeastern Pennsylvania. Exelon is headquartered in Chicago and trades on the NYSE under the ticker EXC.
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EXELON CORPORATION
Earnings Release Attachments
Table of Contents
| Consolidating Statements of Operations - Three Months Ended September 30, 2009 and 2008 |
1 | |
| Consolidating Statements of Operations - Nine Months Ended September 30, 2009 and 2008 |
2 | |
| Business Segment Comparative Statements of Operations - Generation and ComEd - Three and Nine Months Ended September 30, 2009 and 2008 |
3 | |
| Business Segment Comparative Statements of Operations - PECO and Other - Three and Nine Months Ended September 30, 2009 and 2008 |
4 | |
| Consolidated Balance Sheets - September 30, 2009 and December 31, 2008 |
5 | |
| Consolidated Statements of Cash Flows - Nine Months Ended September 30, 2009 and 2008 |
6 | |
| Reconciliation of Adjusted (non-GAAP) Operating Earnings to GAAP Consolidated Statements of Operations - Exelon - Three Months Ended September 30, 2009 and 2008 |
7 | |
| Reconciliation of Adjusted (non-GAAP) Operating Earnings to GAAP Consolidated Statements of Operations - Exelon - Nine Months Ended September 30, 2009 and 2008 |
8 | |
| Reconciliation of Adjusted (non-GAAP) Operating Earnings to GAAP Earnings By Business Segment - Three Months Ended September 30, 2009 and 2008 |
9 | |
| Reconciliation of Adjusted (non-GAAP) Operating Earnings to GAAP Earnings By Business Segment - Nine Months Ended September 30, 2009 and 2008 |
10 | |
| Reconciliation of Adjusted (non-GAAP) Operating Earnings to GAAP Consolidated Statements of Operations - Generation - Three and Nine Months Ended September 30, 2009 and 2008 |
11 | |
| Reconciliation of Adjusted (non-GAAP) Operating Earnings to GAAP Consolidated Statements of Operations - ComEd - Three and Nine Months Ended September 30, 2009 and 2008 |
12 | |
| Reconciliation of Adjusted (non-GAAP) Operating Earnings to GAAP Consolidated Statements of Operations - PECO - Three and Nine Months Ended September 30, 2009 and 2008 |
13 | |
| Reconciliation of Adjusted (non-GAAP) Operating Earnings to GAAP Consolidated Statements of Operations - Other - Three and Nine Months Ended September 30, 2009 and 2008 |
14 | |
| Exelon Generation Statistics - Three Months Ended September 30, 2009, June 30, 2009, March 31, 2009, December 31, 2008 and September 30, 2008 |
15 | |
| Exelon Generation Statistics - Nine Months Ended September 30, 2009 and 2008 |
16 | |
| ComEd Statistics - Three and Nine Months Ended September 30, 2009 and 2008 |
17 | |
| PECO Statistics - Three and Nine Months Ended September 30, 2009 and 2008 |
18 | |
EXELON CORPORATION
Consolidating Statements of Operations
(unaudited)
(in millions)
| Three Months Ended September 30, 2009 | ||||||||||||||||||||
| Generation | ComEd | PECO | Other | Exelon Consolidated |
||||||||||||||||
| Operating revenues |
$ | 2,445 | $ | 1,475 | $ | 1,327 | $ | (908 | ) | $ | 4,339 | |||||||||
| Operating expenses |
||||||||||||||||||||
| Purchased power |
303 | 776 | 625 | (908 | ) | 796 | ||||||||||||||
| Fuel |
379 | — | 26 | (1 | ) | 404 | ||||||||||||||
| Operating and maintenance |
592 | 273 | 154 | 1 | 1,020 | |||||||||||||||
| Operating and maintenance for regulatory required programs (a) |
— | 19 | — | — | 19 | |||||||||||||||
| Depreciation and amortization |
74 | 125 | 272 | 14 | 485 | |||||||||||||||
| Taxes other than income |
51 | 79 | 78 | 4 | 212 | |||||||||||||||
| Total operating expenses |
1,399 | 1,272 | 1,155 | (890 | ) | 2,936 | ||||||||||||||
| Operating income (loss) |
1,046 | 203 | 172 | (18 | ) | 1,403 | ||||||||||||||
| Other income and deductions |
||||||||||||||||||||
| Interest expense, net |
(24 | ) | (82 | ) | (46 | ) | (36 | ) | (188 | ) | ||||||||||
| Equity in losses of unconsolidated affiliates and investments |
(1 | ) | — | (6 | ) | (1 | ) | (8 | ) | |||||||||||
| Other, net |
192 | (19 | ) | 2 | (27 | ) | 148 | |||||||||||||
| Total other income and deductions |
167 | (101 | ) | (50 | ) | (64 | ) | (48 | ) | |||||||||||
| Income (loss) before income taxes |
1,213 | 102 | 122 | (82 | ) | 1,355 | ||||||||||||||
| Income taxes |
556 | 56 | 30 | (44 | ) | 598 | ||||||||||||||
| Net income (loss) |
$ | 657 | $ | 46 | $ | 92 | $ | (38 | ) | $ | 757 | |||||||||
| Three Months Ended September 30, 2008 | ||||||||||||||||||||
| Generation | ComEd | PECO | Other | Exelon Consolidated |
||||||||||||||||
| Operating revenues |
$ | 3,073 | $ | 1,729 | $ | 1,441 | $ | (1,015 | ) | $ | 5,228 | |||||||||
| Operating expenses |
||||||||||||||||||||
| Purchased power |
528 | 1,068 | 693 | (962 | ) | 1,327 | ||||||||||||||
| Fuel |
669 | — | 50 | (1 | ) | 718 | ||||||||||||||
| Operating and maintenance |
625 | 306 | 192 | (13 | ) | 1,110 | ||||||||||||||
| Operating and maintenance for regulatory required programs (a) |
— | 11 | — | — | 11 | |||||||||||||||
| Depreciation and amortization |
58 | 119 | 243 | 11 | 431 | |||||||||||||||
| Taxes other than income |
53 | 87 | 73 | 5 | 218 | |||||||||||||||
| Total operating expenses |
1,933 | 1,591 | 1,251 | (960 | ) | 3,815 | ||||||||||||||
| Operating income (loss) |
1,140 | 138 | 190 | (55 | ) | 1,413 | ||||||||||||||
| Other income and deductions |
||||||||||||||||||||
| Interest expense, net |
(34 | ) | (87 | ) | (55 | ) | (27 | ) | (203 | ) | ||||||||||
| Equity in losses of unconsolidated affiliates and investments |
— | (2 | ) | (4 | ) | — | (6 | ) | ||||||||||||
| Other, net |
(164 | ) | 3 | 2 | 1 | (158 | ) | |||||||||||||
| Total other income and deductions |
(198 | ) | (86 | ) | (57 | ) | (26 | ) | (367 | ) | ||||||||||
| Income (loss) before income taxes |
942 | 52 | 133 | (81 | ) | 1,046 | ||||||||||||||
| Income taxes |
307 | 19 | 43 | (23 | ) | 346 | ||||||||||||||
| Net income (loss) |
$ | 635 | $ | 33 | $ | 90 | $ | (58 | ) | $ | 700 | |||||||||
| (a) | Includes amounts for various legislative and/or regulatory programs that are recoverable from customers on a full and current basis through a reconcilable automatic adjustment clause. An equal and offsetting amount has been reflected in operating revenues during the period. |
1
EXELON CORPORATION
Consolidating Statements of Operations
(unaudited)
(in millions)
| Nine Months Ended September 30, 2009 | ||||||||||||||||||||
| Generation | ComEd | PECO | Other | Exelon Consolidated |
||||||||||||||||
| Operating revenues |
$ | 7,424 | $ | 4,417 | $ | 4,045 | $ | (2,684 | ) | $ | 13,202 | |||||||||
| Operating expenses |
||||||||||||||||||||
| Purchased power |
962 | 2,373 | 1,742 | (2,677 | ) | 2,400 | ||||||||||||||
| Fuel |
1,295 | — | 346 | (1 | ) | 1,640 | ||||||||||||||
| Operating and maintenance |
2,210 | 796 | 481 | 5 | 3,492 | |||||||||||||||
| Operating and maintenance for regulatory required programs (a) |
— | 44 | — | — | 44 | |||||||||||||||
| Depreciation and amortization |
223 | 371 | 726 | 40 | 1,360 | |||||||||||||||
| Taxes other than income |
150 | 215 | 213 | 14 | 592 | |||||||||||||||
| Total operating expenses |
4,840 | 3,799 | 3,508 | (2,619 | ) | 9,528 | ||||||||||||||
| Operating income (loss) |
2,584 | 618 | 537 | (65 | ) | 3,674 | ||||||||||||||
| Other income and deductions |
||||||||||||||||||||
| Interest expense, net |
(77 | ) | (241 | ) | (145 | ) | (92 | ) | (555 | ) | ||||||||||
| Equity in losses of unconsolidated affiliates and investments |
(2 | ) | — | (19 | ) | — | (21 | ) | ||||||||||||
| Other, net |
325 | 67 | 8 | (33 | ) | 367 | ||||||||||||||
| Total other income and deductions |
246 | (174 | ) | (156 | ) | (125 | ) | (209 | ) | |||||||||||
| Income (loss) before income taxes |
2,830 | 444 | 381 | (190 | ) | 3,465 | ||||||||||||||
| Income taxes |
1,133 | 169 | 106 | (69 | ) | 1,339 | ||||||||||||||
| Net income (loss) |
$ | 1,697 | $ | 275 | $ | 275 | $ | (121 | ) | $ | 2,126 | |||||||||
| Nine Months Ended September 30, 2008 | ||||||||||||||||||||
| Generation | ComEd | PECO | Other | Exelon Consolidated |
||||||||||||||||
| Operating revenues |
$ | 8,311 | $ | 4,594 | $ | 4,195 | $ | (2,734 | ) | $ | 14,366 | |||||||||
| Operating expenses |
||||||||||||||||||||
| Purchased power |
1,704 | 2,729 | 1,859 | (2,727 | ) | 3,565 | ||||||||||||||
| Fuel |
1,211 | — | 397 | — | 1,608 | |||||||||||||||
| Operating and maintenance |
2,023 | 828 | 557 | (25 | ) | 3,383 | ||||||||||||||
| Operating and maintenance for regulatory required programs (a) |
— | 17 | — | — | 17 | |||||||||||||||
| Depreciation and amortization |
202 | 343 | 653 | 32 | 1,230 | |||||||||||||||
| Taxes other than income |
153 | 227 | 203 | 14 | 597 | |||||||||||||||
| Total operating expenses |
5,293 | 4,144 | 3,669 | (2,706 | ) | 10,400 | ||||||||||||||
| Operating income (loss) |
3,018 | 450 | 526 | (28 | ) | 3,966 | ||||||||||||||
| Other income and deductions |
||||||||||||||||||||
| Interest expense, net |
(108 | ) | (279 | ) | (171 | ) | (80 | ) | (638 | ) | ||||||||||
| Equity in losses of unconsolidated affiliates and investments |
(1 | ) | (7 | ) | (11 | ) | — | (19 | ) | |||||||||||
| Other, net |
(292 | ) | 12 | 13 | 11 | (256 | ) | |||||||||||||
| Total other income and deductions |
(401 | ) | (274 | ) | (169 | ) | (69 | ) | (913 | ) | ||||||||||
| Income (loss) from continuing operations before income taxes |
2,617 | 176 | 357 | (97 | ) | 3,053 | ||||||||||||||
| Income taxes |
891 | 66 | 111 | (46 | ) | 1,022 | ||||||||||||||
| Income (loss) from continuing operations |
1,726 | 110 | 246 | (51 | ) | 2,031 | ||||||||||||||
| Loss from discontinued operations |
(1 | ) | — | — | — | (1 | ) | |||||||||||||
| Net income (loss) |
$ | 1,725 | $ | 110 | $ | 246 | $ | (51 | ) | $ | 2,030 | |||||||||
| (a) | Includes amounts for various legislative and/or regulatory programs that are recoverable from customers on a full and current basis through a reconcilable automatic adjustment clause. An equal and offsetting amount has been reflected in operating revenues during the period. |
2
EXELON CORPORATION
Business Segment Comparative Statements of Operations
(unaudited)
(in millions)
| Generation | ||||||||||||||||||||||||
| Three Months Ended September 30, | Nine Months Ended September 30, | |||||||||||||||||||||||
| 2009 | 2008 | Variance | 2009 | 2008 | Variance | |||||||||||||||||||
| Operating revenues |
$ | 2,445 | $ | 3,073 | $ | (628 | ) | $ | 7,424 | $ | 8,311 | $ | (887 | ) | ||||||||||
| Operating expenses |
||||||||||||||||||||||||
| Purchased power |
303 | 528 | (225 | ) | 962 | 1,704 | (742 | ) | ||||||||||||||||
| Fuel |
379 | 669 | (290 | ) | 1,295 | 1,211 | 84 | |||||||||||||||||
| Operating and maintenance |
592 | 625 | (33 | ) | 2,210 | 2,023 | 187 | |||||||||||||||||
| Depreciation and amortization |
74 | 58 | 16 | 223 | 202 | 21 | ||||||||||||||||||
| Taxes other than income |
51 | 53 | (2 | ) | 150 | 153 | (3 | ) | ||||||||||||||||
| Total operating expenses |
1,399 | 1,933 | (534 | ) | 4,840 | 5,293 | (453 | ) | ||||||||||||||||
| Operating income |
1,046 | 1,140 | (94 | ) | 2,584 | 3,018 | (434 | ) | ||||||||||||||||
| Other income and deductions |
||||||||||||||||||||||||
| Interest expense, net |
(24 | ) | (34 | ) | 10 | (77 | ) | (108 | ) | 31 | ||||||||||||||
| Equity in losses of investments |
(1 | ) | — | (1 | ) | (2 | ) | (1 | ) | (1 | ) | |||||||||||||
| Other, net |
192 | (164 | ) | 356 | 325 | (292 | ) | 617 | ||||||||||||||||
| Total other income and deductions |
167 | (198 | ) | 365 | 246 | (401 | ) | 647 | ||||||||||||||||
| Income from continuing operations before income taxes |
1,213 | 942 | 271 | 2,830 | 2,617 | 213 | ||||||||||||||||||
| Income taxes |
556 | 307 | 249 | 1,133 | 891 | 242 | ||||||||||||||||||
| Income from continuing operations |
657 | 635 | 22 | 1,697 | 1,726 | (29 | ) | |||||||||||||||||
| Loss from discontinued operations |
— | — | — | — | (1 | ) | 1 | |||||||||||||||||
| Net income |
$ | 657 | $ | 635 | $ | 22 | $ | 1,697 | $ | 1,725 | $ | (28 | ) | |||||||||||
| ComEd | ||||||||||||||||||||||||
| Three Months Ended September 30, | Nine Months Ended September 30, | |||||||||||||||||||||||
| 2009 | 2008 | Variance | 2009 | 2008 | Variance | |||||||||||||||||||
| Operating revenues |
$ | 1,475 | $ | 1,729 | $ | (254 | ) | $ | 4,417 | $ | 4,594 | $ | (177 | ) | ||||||||||
| Operating expenses |
||||||||||||||||||||||||
| Purchased power |
776 | 1,068 | (292 | ) | 2,373 | 2,729 | (356 | ) | ||||||||||||||||
| Operating and maintenance |
273 | 306 | (33 | ) | 796 | 828 | (32 | ) | ||||||||||||||||
| Operating and maintenance for regulatory required programs (a) |
19 | 11 | 8 | 44 | 17 | 27 | ||||||||||||||||||
| Depreciation and amortization |
125 | 119 | 6 | 371 | 343 | 28 | ||||||||||||||||||
| Taxes other than income |
79 | 87 | (8 | ) | 215 | 227 | (12 | ) | ||||||||||||||||
| Total operating expenses |
1,272 | 1,591 | (319 | ) | 3,799 | 4,144 | (345 | ) | ||||||||||||||||
| Operating income |
203 | 138 | 65 | 618 | 450 | 168 | ||||||||||||||||||
| Other income and deductions |
||||||||||||||||||||||||
| Interest expense, net |
(82 | ) | (87 | ) | 5 | (241 | ) | (279 | ) | 38 | ||||||||||||||
| Equity in losses of unconsolidated affiliates |
— | (2 | ) | 2 | — | (7 | ) | 7 | ||||||||||||||||
| Other, net |
(19 | ) | 3 | (22 | ) | 67 | 12 | 55 | ||||||||||||||||
| Total other income and deductions |
(101 | ) | (86 | ) | (15 | ) | (174 | ) | (274 | ) | 100 | |||||||||||||
| Income before income taxes |
102 | 52 | 50 | 444 | 176 | 268 | ||||||||||||||||||
| Income taxes |
56 | 19 | 37 | 169 | 66 | 103 | ||||||||||||||||||
| Net income |
$ | 46 | $ | 33 | $ | 13 | $ | 275 | $ | 110 | $ | 165 | ||||||||||||
| (a) | Includes amounts for various legislative and/or regulatory programs that are recoverable from customers on a full and current basis through a reconcilable automatic adjustment clause. An equal and offsetting amount has been reflected in operating revenues during the period. |
3
EXELON CORPORATION
Business Segment Comparative Statements of Operations
(unaudited)
(in millions)
| PECO | ||||||||||||||||||||||||
| Three Months Ended September 30, | Nine Months Ended September 30, | |||||||||||||||||||||||
| 2009 | 2008 | Variance | 2009 | 2008 | Variance | |||||||||||||||||||
| Operating revenues |
$1,327 | $ | 1,441 | $ | (114 | ) | $ | 4,045 | $ | 4,195 | $ | (150 | ) | |||||||||||
| Operating expenses |
||||||||||||||||||||||||
| Purchased power |
625 | 693 | (68 | ) | 1,742 | 1,859 | (117 | ) | ||||||||||||||||
| Fuel |
26 | 50 | (24 | ) | 346 | 397 | (51 | ) | ||||||||||||||||
| Operating and maintenance |
154 | 192 | (38 | ) | 481 | 557 | (76 | ) | ||||||||||||||||
| Depreciation and amortization |
272 | 243 | 29 | 726 | 653 | 73 | ||||||||||||||||||
| Taxes other than income |
78 | 73 | 5 | 213 | 203 | 10 | ||||||||||||||||||
| Total operating expenses |
1,155 | 1,251 | (96 | ) | 3,508 | 3,669 | (161 | ) | ||||||||||||||||
| Operating income |
172 | 190 | (18 | ) | 537 | 526 | 11 | |||||||||||||||||
| Other income and deductions |
||||||||||||||||||||||||
| Interest expense, net |
(46 | ) | (55 | ) | 9 | (145 | ) | (171 | ) | 26 | ||||||||||||||
| Equity in losses of unconsolidated affiliates |
(6 | ) | (4 | ) | (2 | ) | (19 | ) | (11 | ) | (8 | ) | ||||||||||||
| Other, net |
2 | 2 | — | 8 | 13 | (5 | ) | |||||||||||||||||
| Total other income and deductions |
(50 | ) | (57 | ) | 7 | (156 | ) | (169 | ) | 13 | ||||||||||||||
| Income before income taxes |
122 | 133 | (11 | ) | 381 | 357 | 24 | |||||||||||||||||
| Income taxes |
30 | 43 | (13 | ) | 106 | 111 | (5 | ) | ||||||||||||||||
| Net income |
$ | 92 | $ | 90 | $ | 2 | $ | 275 | $ | 246 | $ | 29 | ||||||||||||
| Other (a) | ||||||||||||||||||||||||
| Three Months Ended September 30, | Nine Months Ended September 30, | |||||||||||||||||||||||
| 2009 | 2008 | Variance | 2009 | 2008 | Variance | |||||||||||||||||||
| Operating revenues |
$ | (908 | ) | $ | (1,015 | ) | $ | 107 | $ | (2,684 | ) | $ | (2,734 | ) | $ | 50 | ||||||||
| Operating expenses |
||||||||||||||||||||||||
| Purchased power |
(908 | ) | (962 | ) | 54 | (2,677 | ) | (2,727 | ) | 50 | ||||||||||||||
| Fuel |
(1 | ) | (1 | ) | — | (1 | ) | — | (1 | ) | ||||||||||||||
| Operating and maintenance |
1 | (13 | ) | 14 | 5 | (25 | ) | 30 | ||||||||||||||||
| Depreciation and amortization |
14 | 11 | 3 | 40 | 32 | 8 | ||||||||||||||||||
| Taxes other than income |
4 | 5 | (1 | ) | 14 | 14 | — | |||||||||||||||||
| Total operating expenses |
(890 | ) | (960 | ) | 70 | (2,619 | ) | (2,706 | ) | 87 | ||||||||||||||
| Operating loss |
(18 | ) | (55 | ) | 37 | (65 | ) | (28 | ) | (37 | ) | |||||||||||||
| Other income and deductions |
||||||||||||||||||||||||
| Interest expense, net |
(36 | ) | (27 | ) | (9 | ) | (92 | ) | (80 | ) | (12 | ) | ||||||||||||
| Equity in losses of unconsolidated affiliates and investments |
(1 | ) | — | (1 | ) | — | — | — | ||||||||||||||||
| Other, net |
(27 | ) | 1 | (28 | ) | (33 | ) | 11 | (44 | ) | ||||||||||||||
| Total other income and deductions |
(64 | ) | (26 | ) | (38 | ) | (125 | ) | (69 | ) | (56 | ) | ||||||||||||
| Loss before income taxes |
(82 | ) | (81 | ) | (1 | ) | (190 | ) | (97 | ) | (93 | ) | ||||||||||||
| Income taxes |
(44 | ) | (23 | ) | (21 | ) | (69 | ) | (46 | ) | (23 | ) | ||||||||||||
| Net loss |
$ | (38 | ) | $ | (58 | ) | $ | 20 | $ | (121 | ) | $ | (51 | ) | $ | (70 | ) | |||||||
| (a) | Other primarily includes eliminating and consolidating adjustments, Exelon’s corporate operations, shared service entities and other financing and investment activities, including investments in synthetic fuel-producing facilities. |
4
EXELON CORPORATION
Consolidated Balance Sheets
(unaudited)
(in millions)
| September 30, 2009 |
December 31, 2008 |
|||||||
| Current assets |
||||||||
| Cash and cash equivalents |
$ | 2,374 | $ | 1,271 | ||||
| Restricted cash and investments |
43 | 75 | ||||||
| Accounts receivable, net |
||||||||
| Customer |
1,418 | 1,928 | ||||||
| Other |
442 | 324 | ||||||
| Mark-to-market derivative assets |
467 | 410 | ||||||
| Inventories, net |
||||||||
| Fossil fuel |
216 | 315 | ||||||
| Materials and supplies |
568 | 528 | ||||||
| Other |
367 | 517 | ||||||
| Total current assets |
5,895 | 5,368 | ||||||
| Property, plant and equipment, net |
26,653 | 25,813 | ||||||
| Deferred debits and other assets |
||||||||
| Regulatory assets |
5,137 | 5,940 | ||||||
| Nuclear decommissioning trust (NDT) funds |
6,502 | 5,500 | ||||||
| Investments |
732 | 715 | ||||||
| Goodwill |
2,625 | 2,625 | ||||||
| Mark-to-market derivative assets |
482 | 507 | ||||||
| Other |
1,476 | 1,349 | ||||||
| Total deferred debits and other assets |
16,954 | 16,636 | ||||||
| Total assets |
$ | 49,502 | $ | 47,817 | ||||
| Liabilities and equity |
||||||||
| Current liabilities |
||||||||
| Short-term borrowings |
$ | 140 | $ | 211 | ||||
| Long-term debt due within one year |
873 | 29 | ||||||
| Long-term debt to PECO Energy Transition Trust (PETT) due within one year |
591 | 319 | ||||||
| Accounts payable |
1,075 | 1,416 | ||||||
| Mark-to-market derivative liabilities |
206 | 214 | ||||||
| Accrued expenses |
888 | 1,151 | ||||||
| Deferred income taxes |
117 | 77 | ||||||
| Other |
554 | 663 | ||||||
| Total current liabilities |
4,444 | 4,080 | ||||||
| Long-term debt |
11,021 | 11,397 | ||||||
| Long-term debt to PECO Energy Transition Trust |
— | 805 | ||||||
| Long-term debt to other financing trusts |
390 | 390 | ||||||
| Deferred credits and other liabilities |
||||||||
| Deferred income taxes and unamortized investment tax credits |
5,858 | 4,939 | ||||||
| Asset retirement obligations |
3,381 | 3,734 | ||||||
| Pension obligations |
3,782 | 4,111 | ||||||
| Non-pension postretirement benefits obligations |
2,248 | 2,255 | ||||||
| Spent nuclear fuel obligation |
1,017 | 1,015 | ||||||
| Regulatory liabilities |
3,395 | 2,520 | ||||||
| Mark-to-market derivative liabilities |
72 | 24 | ||||||
| Other |
1,317 | 1,413 | ||||||
| Total deferred credits and other liabilities |
21,070 | 20,011 | ||||||
| Total liabilities |
36,925 | 36,683 | ||||||
| Preferred securities of subsidiary |
87 | 87 | ||||||
| Shareholders’ equity |
||||||||
| Common stock |
8,896 | 8,816 | ||||||
| Treasury stock, at cost |
(2,338 | ) | (2,338 | ) | ||||
| Retained earnings |
7,905 | 6,820 | ||||||
| Accumulated other comprehensive loss, net |
(1,973 | ) | (2,251 | ) | ||||
| Total shareholders’ equity |
12,490 | 11,047 | ||||||
| Total liabilities and shareholders’ equity |
$ | 49,502 | $ | 47,817 | ||||
5
EXELON CORPORATION
Consolidated Statements of Cash Flows
(unaudited)
(in millions)
| Nine Months Ended September 30, |
||||||||
| 2009 | 2008 | |||||||
| Cash flows from operating activities |
||||||||
| Net income |
$ | 2,126 | $ | 2,030 | ||||
| Adjustments to reconcile net income to net cash flows provided by operating activities: |
||||||||
| Depreciation, amortization and accretion, including nuclear fuel amortization |
1,935 | 1,725 | ||||||
| Impairment of long-lived assets |
223 | — | ||||||
| Deferred income taxes and amortization of investment tax credits |
740 | 111 | ||||||
| Net fair value changes related to derivatives and NDT funds |
(257 | ) | (115 | ) | ||||
| Other non-cash operating activities |
464 | 658 | ||||||
| Changes in assets and liabilities: |
||||||||
| Accounts receivable |
335 | 226 | ||||||
| Inventories |
41 | (158 | ) | |||||
| Accounts payable, accrued expenses and other current liabilities |
(463 | ) | (261 | ) | ||||
| Counterparty collateral received, net |
380 | 245 | ||||||
| Income taxes |
(176 | ) | 457 | |||||
| Pension and non-pension postretirement benefit contributions |
(456 | ) | (103 | ) | ||||
| Other assets and liabilities |
(263 | ) | (448 | ) | ||||
| Net cash flows provided by operating activities |
4,629 | 4,367 | ||||||
| Cash flows from investing activities |
||||||||
| Capital expenditures |
(2,252 | ) | (2,282 | ) | ||||
| Proceeds from NDT fund sales |
18,769 | 14,392 | ||||||
| Investment in NDT funds |
(18,949 | ) | (14,621 | ) | ||||
| Change in restricted cash |
32 | 28 | ||||||
| Other investing activities |
16 | 6 | ||||||
| Net cash flows used in investing activities |
(2,384 | ) | (2,477 | ) | ||||
| Cash flows from financing activities |
||||||||
| Changes in short-term debt |
(71 | ) | (431 | ) | ||||
| Issuance of long-term debt |
1,987 | 1,969 | ||||||
| Retirement of long-term debt |
(1,515 | ) | (1,397 | ) | ||||
| Retirement of long-term debt to financing affiliates |
(533 | ) | (862 | ) | ||||
| Dividends paid on common stock |
(1,038 | ) | (989 | ) | ||||
| Proceeds from employee stock plans |
28 | 122 | ||||||
| Purchase of treasury stock |
— | (436 | ) | |||||
| Purchase of forward contract in relation to certain treasury stock |
— | (64 | ) | |||||
| Other financing activities |
— | 69 | ||||||
| Net cash flows used in financing activities |
(1,142 | ) | (2,019 | ) | ||||
| Increase (decrease) in cash and cash equivalents |
1,103 | (129 | ) | |||||
| Cash and cash equivalents at beginning of period |
1,271 | 311 | ||||||
| Cash and cash equivalents at end of period |
$ | 2,374 | $ | 182 | ||||
6
EXELON CORPORATION
Reconciliation of Adjusted (non-GAAP) Operating Earnings to GAAP Consolidated Statements of Operations
(unaudited)
(in millions, except per share data)
| Three Months Ended September 30, 2009 | Three Months Ended September 30, 2008 | |||||||||||||||||||||||||||
| GAAP (a) | Adjustments | Adjusted Non-GAAP |
GAAP (a) | Adjustments | Adjusted Non-GAAP |
|||||||||||||||||||||||
| Operating revenues |
$ | 4,339 | $ | 16 | (c) | $ | 4,355 | $ | 5,228 | $ | 43 | (c) | $ | 5,271 | ||||||||||||||
| Operating expenses |
||||||||||||||||||||||||||||
| Purchased power |
796 | 89 | (d) | 885 | 1,327 | 305 | (d) | 1,632 | ||||||||||||||||||||
| Fuel |
404 | 37 | (d) | 441 | 718 | (198 | )(d) | 520 | ||||||||||||||||||||
| Operating and maintenance |
1,020 | 46 | (c),(e),(f),(g) | 1,066 | 1,110 | 26 | (c),(g) | 1,136 | ||||||||||||||||||||
| Operating and maintenance for regulatory required programs (b) |
19 | — | 19 | 11 | — | 11 | ||||||||||||||||||||||
| Depreciation and amortization |
485 | — | 485 | 431 | — | 431 | ||||||||||||||||||||||
| Taxes other than income |
212 | — | 212 | 218 | — | 218 | ||||||||||||||||||||||
| Total operating expenses |
2,936 | 172 | 3,108 | 3,815 | 133 | 3,948 | ||||||||||||||||||||||
| Operating income |
1,403 | (156 | ) | 1,247 | 1,413 | (90 | ) | 1,323 | ||||||||||||||||||||
| Other income and deductions |
||||||||||||||||||||||||||||
| Interest expense, net |
(188 | ) | 3 | (h) | (185 | ) | (203 | ) | — | (203 | ) | |||||||||||||||||
| Equity in losses of unconsolidated affiliates and investments |
(8 | ) | — | (8 | ) | (6 | ) | — | (6 | ) | ||||||||||||||||||
| Other, net |
148 | (152 | )(h),(i) | (4 | ) | (158 | ) | 170 | (i) | 12 | ||||||||||||||||||
| Total other income and deductions |
(48 | ) | (149 | ) | (197 | ) | (367 | ) | 170 | (197 | ) | |||||||||||||||||
| Income before income taxes |
1,355 | (305 | ) | 1,050 | 1,046 | 80 | 1,126 | |||||||||||||||||||||
| Income taxes |
598 | (181 | )(c),(d),(e),(f),(g),(h),(i) | 417 | 346 | 74 | (c),(d),(g),(i) | 420 | ||||||||||||||||||||
| Net income |
$ | 757 | $ | (124 | ) | $ | 633 | $ | 700 | $ | 6 | $ | 706 | |||||||||||||||
| Effective tax rate |
44.1 | % | 39.7 | % | 33.1 | % | 37.3 | % | ||||||||||||||||||||
| Earnings per average common share |
||||||||||||||||||||||||||||
| Basic: |
||||||||||||||||||||||||||||
| Income from continuing operations |
$ | 1.15 | $ | (0.19 | ) | $ | 0.96 | $ | 1.06 | $ | 0.01 | $ | 1.07 | |||||||||||||||
| Income from discontinued operations |
— | — | — | — | — | — | ||||||||||||||||||||||
| Net income |
$ | 1.15 | $ | (0.19 | ) | $ | 0.96 | $ | 1.06 | $ | 0.01 | $ | 1.07 | |||||||||||||||
| Diluted: |
||||||||||||||||||||||||||||
| Income from continuing operations |
$ | 1.14 | $ | (0.18 | ) | $ | 0.96 | $ | 1.06 | $ | 0.01 | $ | 1.07 | |||||||||||||||
| Income from discontinued operations |
— | — | — | — | — | — | ||||||||||||||||||||||
| Net income |
$ | 1.14 | $ | (0.18 | ) | $ | 0.96 | $ | 1.06 | $ | 0.01 | $ | 1.07 | |||||||||||||||
| Average common shares outstanding |
||||||||||||||||||||||||||||
| Basic |
660 | 660 | 658 | 658 | ||||||||||||||||||||||||
| Diluted |
662 | 662 | 662 | 662 | ||||||||||||||||||||||||
| Effect of adjustments on earnings per average diluted common share recorded in accordance with GAAP: |
||||||||||||||||||||||||||||
| 2007 Illinois electric rate settlement (c) |
$ | 0.02 | $ | 0.04 | ||||||||||||||||||||||||
| Mark-to-market impact of economic hedging activities (d) |
(0.12 | ) | (0.10 | ) | ||||||||||||||||||||||||
| NRG acquisition costs (e) |
0.01 | — | ||||||||||||||||||||||||||
| 2009 severance charges (f) |
— | — | ||||||||||||||||||||||||||
| Decommissioning obligation reduction (g) |
(0.05 | ) | (0.02 | ) | ||||||||||||||||||||||||
| Costs associated with early debt retirements (h) |
0.09 | — | ||||||||||||||||||||||||||
| Unrealized gains and losses related to NDT fund investments (i) |
(0.13 | ) | 0.09 | |||||||||||||||||||||||||
| Total adjustments |
$ | (0.18 | ) | $ | 0.01 | |||||||||||||||||||||||
| (a) | Results reported in accordance with accounting principles generally accepted in the United States (GAAP). |
| (b) | Includes amounts for various legislative and/or regulatory programs that are recoverable from customers on a full and current basis through a reconcilable automatic adjustment clause. An equal and offsetting amount has been reflected in operating revenues during the period. |
| (c) | Adjustment to exclude the impact of the 2007 Illinois electric rate settlement. |
| (d) | Adjustment to exclude the mark-to-market impact of Exelon's economic hedging activities. |
| (e) | Adjustment to exclude external costs in 2009 associated with Exelon’s proposed acquisition of NRG Energy, Inc. (NRG), which was terminated in July 2009. |
| (f) | Adjustment to exclude 2009 severance charges. |
| (g) | Adjustment to exclude the reduction in Generation's decommissioning obligation. |
| (h) | Adjustment to exclude 2009 costs associated with early debt retirements. |
| (i) | Adjustment to exclude the unrealized gains in 2009 and unrealized losses in 2008 associated with Generation's NDT fund investments and the associated contractual accounting relating to income taxes. |
7
EXELON CORPORATION
Reconciliation of Adjusted (non-GAAP) Operating Earnings to GAAP Consolidated Statements of Operations
(unaudited)
(in millions, except per share data)
| Nine Months Ended September 30, 2009 |
Nine Months Ended September 30, 2008 |
|||||||||||||||||||||||
| GAAP (a) |
Adjustments | Adjusted Non-GAAP |
GAAP (a) |
Adjustments | Adjusted Non-GAAP |
|||||||||||||||||||
| Operating revenues |
$ | 13,202 | $ | 82 | (c) | $ | 13,284 | $ | 14,366 | $ | 189 | (c) | $ | 14,555 | ||||||||||
| Operating expenses |
||||||||||||||||||||||||
| Purchased power |
2,400 | 129 | (d) | 2,529 | 3,565 | 210 | (d) | 3,775 | ||||||||||||||||
| Fuel |
1,640 | 9 | (d) | 1,649 | 1,608 | 88 | (d) | 1,696 | ||||||||||||||||
| Operating and maintenance |
3,492 | (241 | )(c),(e),(f),(g),(h) | 3,251 | 3,383 | 22 | (c),(h) | 3,405 | ||||||||||||||||
| Operating and maintenance for regulatory required programs (b) |
44 | — | 44 | 17 | — | 17 | ||||||||||||||||||
| Depreciation and amortization |
1,360 | — | 1,360 | 1,230 | — | 1,230 | ||||||||||||||||||
| Taxes other than income |
592 | — | 592 | 597 | — | 597 | ||||||||||||||||||
| Total operating expenses |
9,528 | (103 | ) | 9,425 | 10,400 | 320 | 10,720 | |||||||||||||||||
| Operating income |
3,674 | 185 | 3,859 | 3,966 | (131 | ) | 3,835 | |||||||||||||||||
| Other income and deductions |
||||||||||||||||||||||||
| Interest expense, net |
(555 | ) | 12 | (i),(j) | (543 | ) | (638 | ) | — | (638 | ) | |||||||||||||
| Equity in losses of unconsolidated affiliates and investments |
(21 | ) | — | (21 | ) | (19 | ) | — | (19 | ) | ||||||||||||||
| Other, net |
367 | (308 | )(i),(j),(k) | 59 | (256 | ) | |
335 |
(k) |
79 | ||||||||||||||
| Total other income and deductions |
(209 | ) | (296 | ) | (505 | ) | (913 | ) | 335 | (578 | ) | |||||||||||||
| Income before income taxes |
3,465 | (111 | ) | 3,354 | 3,053 | 204 | 3,257 | |||||||||||||||||
| Income taxes |
1,339 | (97 | )(c),(d),(e),(f),(g),(h),(i),(j),(k) | 1,242 | 1,022 | 162 | (c),(d),(h),(k) | 1,184 | ||||||||||||||||
| Income from continuing operations |
2,126 | (14 | ) | 2,112 | 2,031 | 42 | 2,073 | |||||||||||||||||
| Loss from discontinued operations |
— | — | — | (1 | ) | — | (1 | ) | ||||||||||||||||
| Net Income |
$ | 2,126 | $ | (14 | ) | $ | 2,112 | $ | 2,030 | $ | 42 | $ | 2,072 | |||||||||||
| Effective tax rate |
38.6 | % | 37.0 | % | 33.5 | % | 36.4 | % | ||||||||||||||||
| Earnings per average common share |
||||||||||||||||||||||||
| Basic: |
||||||||||||||||||||||||
| Income from continuing operations |
$ | 3.22 | $ | (0.02 | ) | $ | 3.20 | $ | 3.09 | $ | 0.07 | $ | 3.16 | |||||||||||
| Income from discontinued operations |
— | — | — | — | — | — | ||||||||||||||||||
| Net income |
$ | 3.22 | $ | (0.02 | ) | $ | 3.20 | $ | 3.09 | $ | 0.07 | $ | 3.16 | |||||||||||
| Diluted: |
||||||||||||||||||||||||
| Income from continuing operations |
$ | 3.21 | $ | (0.02 | ) | $ | 3.19 | $ | 3.06 | $ | 0.07 | $ | 3.13 | |||||||||||
| Income from discontinued operations |
— | — | — | — | — | — | ||||||||||||||||||
| Net income |
$ | 3.21 | $ | (0.02 | ) | $ | 3.19 | $ | 3.06 | $ | 0.07 | $ | 3.13 | |||||||||||
| Average common shares outstanding |
||||||||||||||||||||||||
| Basic |
659 | 659 | 658 | 658 | ||||||||||||||||||||
| Diluted |
661 | 661 | 663 | 663 | ||||||||||||||||||||
| Effect of adjustments on earnings per average diluted common share recorded in accordance with GAAP: |
||||||||||||||||||||||||
| 2007 Illinois electric rate settlement (c) |
$ | 0.08 | $ | 0.18 | ||||||||||||||||||||
| Mark-to-market impact of economic hedging activities (d) |
(0.12 | ) | (0.27 | ) | ||||||||||||||||||||
| NRG acquisition costs (e) |
0.03 | — | ||||||||||||||||||||||
| Impairment of certain generating assets (f) |
0.20 | — | ||||||||||||||||||||||
| 2009 severance charges (g) |
0.03 | — | ||||||||||||||||||||||
| Decommissioning obligation reduction (h) |
(0.05 | ) | (0.02 | ) | ||||||||||||||||||||
| Non-cash income tax matters and state taxes (i) |
(0.10 | ) | — | |||||||||||||||||||||
| Costs associated with early debt retirements (j) |
0.09 | — | ||||||||||||||||||||||
| Unrealized gains and losses related to NDT fund investments (k) |
(0.18 | ) | 0.18 | |||||||||||||||||||||
| Total adjustments |
$ | (0.02 | ) | $ | 0.07 | |||||||||||||||||||
| (a) | Results reported in accordance with GAAP. |
| (b) | Includes amounts for various legislative and/or regulatory programs that are recoverable from customers on a full and current basis through a reconcilable automatic adjustment clause. An equal and offsetting amount has been reflected in operating revenues during the period. |
| (c) | Adjustment to exclude the impact of the 2007 Illinois electric rate settlement. |
| (d) | Adjustment to exclude the mark-to-market impact of Exelon’s economic hedging activities. |
| (e) | Adjustment to exclude external costs in 2009 associated with Exelon’s proposed acquisition of NRG, which was terminated in July 2009. |
| (f) | Adjustment to exclude the impairment of certain of Generation’s Texas plants recorded during the first quarter of 2009. |
| (g) | Adjustment to exclude 2009 severance charges. |
| (h) | Adjustment to exclude the reduction in Generation's decommissioning obligation. |
| (i) | Adjustment to exclude 2009 remeasurements of tax uncertainties and a change in state deferred income taxes. |
| (j) | Adjustment to exclude 2009 costs associated with early debt retirements. |
| (k) | Adjustment to exclude the unrealized gains in 2009 and unrealized losses in 2008 associated with Generation's NDT fund investments and the associated contractual accounting relating to income taxes. |
8
EXELON CORPORATION
Reconciliation of Adjusted (non-GAAP) Operating Earnings
to GAAP Earnings By Business Segment (in millions)
Three Months Ended September 30, 2009 and 2008
| Exelon Earnings per Diluted Share |
Generation | ComEd | PECO | Other | Exelon | |||||||||||||||||||
| 2008 GAAP Earnings (Loss) |
$ | 1.06 | $ | 635 | $ | 33 | $ | 90 | $ | (58 | ) | $ | 700 | |||||||||||
| 2008 Adjusted (non-GAAP) Operating Earnings (Loss) Adjustments: |
||||||||||||||||||||||||
| 2007 Illinois Electric Rate Settlement |
0.04 | 25 | 1 | — | — | 26 | ||||||||||||||||||
| Mark-to-Market Impact of Economic Hedging Activities |
(0.10 | ) | (96 | ) | — | — | 31 | (65 | ) | |||||||||||||||
| Unrealized Losses Related to NDT Fund Investments |
0.09 | 60 | — | — | — | 60 | ||||||||||||||||||
| Decommissioning Obligation Reduction (1) |
(0.02 | ) | (15 | ) | — | — | — | (15 | ) | |||||||||||||||
| 2008 Adjusted (non-GAAP) Operating Earnings (Loss) |
1.07 | 609 | 34 | 90 | (27 | ) | 706 | |||||||||||||||||
| Year Over Year Effects on Earnings: |
||||||||||||||||||||||||
| Generation Energy Margins, Excluding Mark-to-Market (2) |
(0.10 | ) | (64 | ) | — | — | — | (64 | ) | |||||||||||||||
| ComEd and PECO Margins: |
||||||||||||||||||||||||
| Weather (3) |
(0.04 | ) | — | (18 | ) | (9 | ) | — | (27 | ) | ||||||||||||||
| Other Energy Delivery (4) |
0.05 | — | 36 | (6 | ) | — | 30 | |||||||||||||||||
| Operating and Maintenance Expense: |
||||||||||||||||||||||||
| Bad Debt (5) |
0.05 | 14 | (7 | ) | 29 | — | 36 | |||||||||||||||||
| Labor, Contracting and Materials (6) |
0.02 | 15 | 5 | (6 | ) | — | 14 | |||||||||||||||||
| Other Operating and Maintenance Expense (7) |
0.04 | — | 19 | 4 | 3 | 26 | ||||||||||||||||||
| Pension and Non-Pension Postretirement Benefits Expense (8) |
(0.04 | ) | (12 | ) | (9 | ) | (1 | ) | (5 | ) | (27 | ) | ||||||||||||
| Planned Nuclear Refueling Outages (9) |
(0.02 | ) | (15 | ) | — | — | — | (15 | ) | |||||||||||||||
| Discrete Items Resulting From the Distribution Rate Case (10) |
0.02 | — | 15 | — | — | 15 | ||||||||||||||||||
| Depreciation and Amortization (11) |
(0.06 | ) | (10 | ) | (6 | ) | (21 | ) | (1 | ) | (38 | ) | ||||||||||||
| Reversal of Benefit From Tax Ruling (12) |
(0.06 | ) | (8 | ) | (35 | ) | — | 1 | (42 | ) | ||||||||||||||
| Income Taxes (13) |
— | (25 | ) | 1 | 10 | 17 | 3 | |||||||||||||||||
| Other (14) |
0.03 | — | 13 | 1 | 2 | 16 | ||||||||||||||||||
| 2009 Adjusted (non-GAAP) Operating Earnings (Loss) |
0.96 | 504 | 48 | 91 | (10 | ) | 633 | |||||||||||||||||
| 2009 Adjusted (non-GAAP) Operating Earnings (Loss) Adjustments: |
||||||||||||||||||||||||
| 2007 Illinois Electric Rate Settlement |
(0.02 | ) | (9 | ) | (2 | ) | — | — | (11 | ) | ||||||||||||||
| Mark-to-Market Impact of Economic Hedging Activities |
0.12 | 77 | — | — | — | 77 | ||||||||||||||||||
| Unrealized Gains Related to NDT Fund Investments |
0.13 | 87 | — | — | — | 87 | ||||||||||||||||||
| Decommissioning Obligation Reduction (1) |
0.05 | 32 | — | — | — | 32 | ||||||||||||||||||
| NRG Acquisition Costs (15) |
(0.01 | ) | — | — | — | (6 | ) | (6 | ) | |||||||||||||||
| 2009 Severance Charges (16) |
— | 2 | — | 1 | — | 3 | ||||||||||||||||||
| Costs Associated with Early Debt Retirements (17) |
(0.09 | ) | (36 | ) | — | — | (22 | ) | (58 | ) | ||||||||||||||
| 2009 GAAP Earnings (Loss) |
$ | 1.14 | $ | 657 | $ | 46 | $ | 92 | $ | (38 | ) | $ | 757 | |||||||||||
| (1) | Reflects a decrease in Generation’s decommissioning obligation liability primarily related to the former AmerGen nuclear plants. |
| (2) | Primarily reflects in 2009 unfavorable portfolio and market conditions, decreased nuclear output as a result of more planned and unplanned nuclear outage days and higher nuclear fuel costs. |
| (3) | Primarily reflects the impact of unfavorable 2009 weather conditions, compared to 2008, in the ComEd and PECO service territories. |
| (4) | For ComEd, reflects the impact of increased distribution rates effective September 2008, partially offset by reduced load. For PECO, reflects reduced load, partially offset by increased gas distribution rates effective January 2009. |
| (5) | For Generation, reflects the impact of a reserve recorded in 2008 for counterparty exposure to Lehman Brothers Holdings, Inc. For ComEd, reflects an increase in uncollectible accounts, in part as a result of the current overall negative economic conditions, partially mitigated by ComEd’s increased collection activities in 2009. For PECO, reflects the impact of improved accounts receivable aging as a result of enhancements to its credit processes and increased termination and collection activities in late 2008 and 2009. |
| (6) | Primarily reflects Exelon’s ongoing cost savings initiative, partially offset by inflation related to labor, contracting and materials expenses (exclusive of planned nuclear refueling outages as disclosed in number 9 below). |
| (7) | Primarily reflects decreased storm costs in 2009 in the ComEd and PECO service territories. |
| (8) | Reflects increased pension and non-pension postretirement benefits expense primarily due to lower than expected asset returns in 2008. |
| (9) | Reflects increased operating and maintenance expense related to nuclear refueling outage costs associated with a higher number of planned refueling outage days during 2009 as compared to 2008, excluding Salem Generating Station (Salem). |
| (10) | Reflects the 2008 impact of discrete disallowances, net of allowed regulatory assets, mandated by the September 2008 Illinois Commerce Commission (ICC) rate order. |
| (11) | Reflects increased scheduled competitive transition charge (CTC) amortization at PECO and increased depreciation across the operating companies due to ongoing capital expenditures. |
| (12) | Reflects the reversal of benefits associated with Investment Tax Credits as a result of the modified opinion issued by the Illinois Supreme Court in July 2009. |
| (13) | Primarily reflects the 2008 impact at PECO of an IRS settlement related to prior tax years, partially offset by a decrease in Generation’s manufacturing deduction. |
| (14) | Primarily reflects decreased interest expense across the operating companies and decreased taxes other than income at ComEd, partially offset by realized NDT fund losses related to market conditions in 2009. |
| (15) | Reflects external costs incurred in 2009 associated with Exelon’s proposed acquisition of NRG, which was terminated in July 2009. |
| (16) | Reflects a true-up of expenses associated with the elimination of management and staff positions pursuant to Exelon’s 2009 cost management plan to achieve sustainable cost savings. |
| (17) | Reflects 2009 costs associated with early debt retirements at Generation and Exelon Corporate. |
9
EXELON CORPORATION
Reconciliation of Adjusted (non-GAAP) Operating Earnings to
GAAP Earnings By Business Segment (in millions)
Nine Months Ended September 30, 2009 and 2008
| Exelon Earnings per Diluted Share |
Generation | ComEd | PECO | Other | Exelon | |||||||||||||||||||
| 2008 GAAP Earnings (Loss) |
$ | 3.06 | $ | 1,725 | $ | 110 | $ | 246 | $ | (51 | ) | $ | 2,030 | |||||||||||
| 2008 Adjusted (non-GAAP) Operating Earnings (Loss) Adjustments: |
||||||||||||||||||||||||
| 2007 Illinois Electric Rate Settlement |
0.18 | 115 | 5 | — | — | 120 | ||||||||||||||||||
| Mark-to-Market Impact of Economic Hedging Activities |
(0.27 | ) | (180 | ) | — | — | — | (180 | ) | |||||||||||||||
| Unrealized Losses Related to NDT Fund Investments |
0.18 | 117 | — | — | — | 117 | ||||||||||||||||||
| Decommissioning Obligation Reduction (1) |
(0.02 | ) | (15 | ) | — | — | — | (15 | ) | |||||||||||||||
| 2008 Adjusted (non-GAAP) Operating Earnings (Loss) |
3.13 | 1,762 | 115 | 246 | (51 | ) | 2,072 | |||||||||||||||||
| Year Over Year Effects on Earnings: |
||||||||||||||||||||||||
| Generation Energy Margins, Excluding Mark-to-Market (2) |
(0.16 | ) | (108 | ) | — | — | — | (108 | ) | |||||||||||||||
| ComEd and PECO Margins: |
||||||||||||||||||||||||
| Weather (3) |
(0.04 | ) | — | (21 | ) | (8 | ) | — | (29 | ) | ||||||||||||||
| Other Energy Delivery (4) |
0.21 | — | 115 | 21 | — | 136 | ||||||||||||||||||
| Operating and Maintenance Expense: |
||||||||||||||||||||||||
| Bad Debt (5) |
0.10 | 15 | (9 | ) | 59 | — | 65 | |||||||||||||||||
| Labor, Contracting and Materials (6) |
0.02 | 5 | 17 | (9 | ) | — | 13 | |||||||||||||||||
| Other Operating and Maintenance Expense (7) |
0.10 | 15 | 33 | 12 | 10 | 70 | ||||||||||||||||||
| Pension and Non-Pension Postretirement Benefits Expense (8) |
(0.11 | ) | (38 | ) | (25 | ) | (5 | ) | (6 | ) | (74 | ) | ||||||||||||
| Planned Nuclear Refueling Outages (9) |
0.02 | 15 | — | — | — | 15 | ||||||||||||||||||
| Discrete Items Resulting From the Distribution Rate Case (10) |
0.02 | — | 15 | — | — | 15 | ||||||||||||||||||
| Depreciation and Amortization (11) |
(0.14 | ) | (13 | ) | (19 | ) | (53 | ) | (5 | ) | (90 | ) | ||||||||||||
| Income Taxes (12) |
(0.03 | ) | (26 | ) | 10 | 13 | (18 | ) | (21 | ) | ||||||||||||||
| Other (13) |
0.07 | 24 | 20 | — | 4 | 48 | ||||||||||||||||||
| 2009 Adjusted (non-GAAP) Operating Earnings (Loss) |
3.19 | 1,651 | 251 | 276 | (66 | ) | 2,112 | |||||||||||||||||
| 2009 Adjusted (non-GAAP) Operating Earnings (Loss) Adjustments: |
||||||||||||||||||||||||
| 2007 Illinois Electric Rate Settlement |
(0.08 | ) | (49 | ) | (3 | ) | — | — | (52 | ) | ||||||||||||||
| Mark-to-Market Impact of Economic Hedging Activities |
0.12 | 84 | — | — | — | 84 | ||||||||||||||||||
| Unrealized Gains Related to NDT Fund Investments |
0.18 | 119 | — | — | — | 119 | ||||||||||||||||||
| Decommissioning Obligation Reduction (1) |
0.05 | 32 | — | — | — | 32 | ||||||||||||||||||
| NRG Acquisition Costs (14) |
(0.03 | ) | — | — | — | (20 | ) | (20 | ) | |||||||||||||||
| Impairment of Certain Generating Assets (15) |
(0.20 | ) | (135 | ) | — | — | — | (135 | ) | |||||||||||||||
| 2009 Severance Charges (16) |
(0.03 | ) | (7 | ) | (13 | ) | (1 | ) | (1 | ) | (22 | ) | ||||||||||||
| Non-Cash Remeasurement of Income Tax Uncertainties and Reassessment of State Deferred Income Taxes (17) |
0.10 | 38 | 40 | — | (12 | ) | 66 | |||||||||||||||||
| Costs Associated with Early Debt Retirements (18) |
(0.09 | ) | (36 | ) | — | — | (22 | ) | (58 | ) | ||||||||||||||
| 2009 GAAP Earnings (Loss) |
$ | 3.21 | $ | 1,697 | $ | 275 | $ | 275 | $ | (121 | ) | $ | 2,126 | |||||||||||
| (1) | Reflects a decrease in Generation’s decommissioning obligation liability primarily related to the former AmerGen nuclear plants. |
| (2) | Primarily reflects the impact of revenue from certain long options in Generation’s proprietary trading portfolio in 2008, the impact of gains related to the settlement of uranium supply agreements in 2008 and higher nuclear fuel costs, partially offset by increased nuclear output as a result of fewer planned refueling outage days in 2009. |
| (3) | Primarily reflects the impact of unfavorable 2009 weather conditions, compared to 2008, in the ComEd and PECO service territories. |
| (4) | Primarily reflects the impact of increased distribution rates at ComEd effective September 2008 and increased gas distribution rates at PECO effective January 2009, partially offset by reduced load at ComEd and PECO. |
| (5) | For Generation, reflects the impact of a reserve recorded in 2008 for counterparty exposure to Lehman Brothers Holdings, Inc. For ComEd, reflects an increase in uncollectible accounts, in part as a result of the current overall negative economic conditions, partially mitigated by ComEd’s increased collection activities in 2009. For PECO, reflects the impact of improved accounts receivable aging as a result of enhancements to its credit processes and increased termination and collection activities in late 2008 and 2009. |
| (6) | Primarily reflects Exelon’s ongoing cost savings initiative and lower planned outage costs at Generation’s non-nuclear generating plants, partially offset by inflation related to labor, contracting and materials expenses (exclusive of planned nuclear refueling outages as disclosed in number 9 below). |
| (7) | Primarily reflects the impact of decreased storm costs in 2009 in the ComEd and PECO service territories, decreased nuclear refueling outage costs related to Generation’s ownership interest in Salem and decreased costs associated with the possible construction of a new nuclear plant in Texas. |
| (8) | Reflects increased pension and non-pension postretirement benefits expense primarily due to lower than expected asset returns in 2008. |
| (9) | Reflects decreased operating and maintenance expense related to nuclear refueling outage costs associated with a lower number of planned refueling outage days during 2009 as compared to 2008, excluding Salem. |
| (10) | Reflects the 2008 impact of discrete disallowances, net of allowed regulatory assets, mandated by the September 2008 ICC rate order. |
| (11) | Primarily reflects increased scheduled CTC amortization at PECO and increased depreciation across the operating companies due to ongoing capital expenditures. |
| (12) | Primarily reflects a decrease in Generation’s manufacturing deduction and the 2008 impact of income from state tax settlements, partially offset by a decrease in PECO’s 2009 state income tax expense due to higher deductible interest expense. |
| (13) | Primarily reflects decreased interest expense due to lower outstanding debt at ComEd and PECO (including to PETT) and lower interest rates on Generation’s spent nuclear fuel obligation, partially offset by the impact of income in 2008 related to the termination of a gas supply guarantee at Generation and the impact of 2008 income tax benefits associated with Exelon’s tax method of capitalizing overhead costs. |
| (14) | Reflects external costs incurred in 2009 associated with Exelon’s proposed acquisition of NRG, which was terminated in July 2009. |
| (15) | Reflects the impairment of certain of Generation’s Texas plants recorded during the first quarter of 2009. |
| (16) | Reflects expenses associated with the elimination of management and staff positions pursuant to Exelon’s 2009 cost management plan to achieve sustainable cost savings. |
| (17) | Reflects the impacts of the 2009 remeasurement of tax uncertainties related to ComEd’s 1999 sale of fossil generating assets and a change in state deferred tax rates resulting from a reassessment of anticipated apportionment of Exelon’s income. |
| (18) | Reflects 2009 costs associated with early debt retirements at Generation and Exelon Corporate. |
10
EXELON CORPORATION
Reconciliation of Adjusted (non-GAAP) Operating Earnings to
GAAP Consolidated Statements of Operations
(unaudited)
(in millions)
| Generation
|
||||||||||||||||||||||||
| Three Months Ended September 30, 2009 | Three Months Ended September 30, 2008 | |||||||||||||||||||||||
| GAAP (a) | Adjustments | Adjusted Non-GAAP |
GAAP (a) | Adjustments | Adjusted Non-GAAP |
|||||||||||||||||||
| Operating revenues |
$ | 2,445 | $ | 14 | (b) | $ | 2,459 | $ | 3,073 | $ | 41 | (b) | $ | 3,114 | ||||||||||
| Operating expenses |
||||||||||||||||||||||||
| Purchased power |
303 | 89 | (c) | 392 | 528 | 356 | (c) | 884 | ||||||||||||||||
| Fuel |
379 | 37 | (c) | 416 | 669 | (198 | )(c) | 471 | ||||||||||||||||
| Operating and maintenance |
592 | 55 | (d),(e) | 647 | 625 | 25 | (e) | 650 | ||||||||||||||||
| Depreciation and amortization |
74 | — | 74 | 58 | — | 58 | ||||||||||||||||||
| Taxes other than income |
51 | — | 51 | 53 | — | 53 | ||||||||||||||||||
| Total operating expenses |
1,399 | 181 | 1,580 | 1,933 | 183 | 2,116 | ||||||||||||||||||
| Operating income |
1,046 | (167 | ) | 879 | 1,140 | (142 | ) | 998 | ||||||||||||||||
| Other income and deductions |
||||||||||||||||||||||||
| Interest expense, net |
(24 | ) | 2 | (f) | (22 | ) | (34 | ) | — | (34 | ) | |||||||||||||
| Equity in losses of investments |
(1 | ) | — | (1 | ) | — | — | — | ||||||||||||||||
| Other, net |
192 | (188 | )(f),(g) | 4 | (164 | ) | 170 | (g) | 6 | |||||||||||||||
| Total other income and deductions |
167 | (186 | ) | (19 | ) | (198 | ) | 170 | (28 | ) | ||||||||||||||
| Income before income taxes |
1,213 | (353 | ) | 860 | 942 | 28 | 970 | |||||||||||||||||
| Income taxes |
556 | (200 | )(b),(c),(d),(e),(f),(g) | 356 | 307 | 54 | (b),(c),(e),(g) | 361 | ||||||||||||||||
| Net Income |
$ | 657 | $ | (153 | ) | $ | 504 | $ | 635 | $ | (26 | ) | $ | 609 | ||||||||||
| Nine Months Ended September 30, 2009 | Nine Months Ended September 30, 2008 | |||||||||||||||||||||||
| GAAP (a) | Adjustments | Adjusted Non-GAAP |
GAAP (a) | Adjustments | Adjusted Non-GAAP |
|||||||||||||||||||
| Operating revenues |
$ | 7,424 | $ | 78 | (b) | $ | 7,502 | $ | 8,311 | $ | 184 | (b) | $ | 8,495 | ||||||||||
| Operating expenses |
||||||||||||||||||||||||
| Purchased power |
962 | 129 | (c) | 1,091 | 1,704 | 210 | (c) | 1,914 | ||||||||||||||||
| Fuel |
1,295 | 9 | (c) | 1,304 | 1,211 | 88 | (c) | 1,299 | ||||||||||||||||
| Operating and maintenance |
2,210 | (181 | )(d),(e),(h) | 2,029 | 2,023 | 25 | (e) | 2,048 | ||||||||||||||||
| Depreciation and amortization |
223 | — | 223 | 202 | — | 202 | ||||||||||||||||||
| Taxes other than income |
150 | — | 150 | 153 | — | 153 | ||||||||||||||||||
| Total operating expenses |
4,840 | (43 | ) | 4,797 | 5,293 | 323 | 5,616 | |||||||||||||||||
| Operating income |
2,584 | 121 | 2,705 | 3,018 | (139 | ) | 2,879 | |||||||||||||||||
| Other income and deductions |
||||||||||||||||||||||||
| Interest expense, net |
(77 | ) | 2 | (f) | (75 | ) | (108 | ) | — | (108 | ) | |||||||||||||
| Equity in losses of investments |
(2 | ) | — | (2 | ) | (1 | ) | — | (1 | ) | ||||||||||||||
| Other, net |
325 | (294 | )(f),(g),(i) | 31 | (292 | ) | 335 | (g) | 43 | |||||||||||||||
| Total other income and deductions |
246 | (292 | ) | (46 | ) | (401 | ) | 335 | (66 | ) | ||||||||||||||
| Income from continuing operations before income taxes |
2,830 | (171 | ) | 2,659 | 2,617 | 196 | 2,813 | |||||||||||||||||
| Income taxes |
1,133 | (125 | )(b),(c),(d),(e),(f),(g),(h),(i) | 1,008 | 891 | 159 | (b),(c),(e),(g) | 1,050 | ||||||||||||||||
| Income from continuing operations |
1,697 | (46 | ) | 1,651 | 1,726 | 37 | 1,763 | |||||||||||||||||
| Loss from discontinued operations |
— | — | — | (1 | ) | — | (1 | ) | ||||||||||||||||
| Net income |
$ | 1,697 | $ | (46 | ) | $ | 1,651 | $ | 1,725 | $ | 37 | $ | 1,762 | |||||||||||
| (a) | Results reported in accordance with GAAP. |
| (b) | Adjustment to exclude the impact of the 2007 Illinois electric rate settlement. |
| (c) | Adjustment to exclude the mark-to-market impact of Generation’s economic hedging activities. |
| (d) | Adjustment to exclude 2009 severance charges. |
| (e) | Adjustment to exclude the reduction in Generation’s decommissioning obligation. |
| (f) | Adjustment to exclude 2009 costs associated with early debt retirements. |
| (g) | Adjustment to exclude the unrealized gains in 2009 and unrealized losses in 2008 associated with Generation’s NDT fund investments and the associated contractual accounting relating to income taxes. |
| (h) | Adjustment to exclude the impairment of certain of Generation’s Texas plants recorded during the first quarter of 2009. |
| (i) | Adjustment to exclude a change in state deferred income taxes. |
11
EXELON CORPORATION
Reconciliation of Adjusted (non-GAAP) Operating Earnings to
GAAP Consolidated Statements of Operations
(unaudited)
(in millions)
| ComEd
|
||||||||||||||||||||||||
| Three Months Ended September 30, 2009 | Three Months Ended September 30, 2008 | |||||||||||||||||||||||
| GAAP (a) | Adjustments | Adjusted Non-GAAP |
GAAP (a) | Adjustments | Adjusted Non-GAAP |
|||||||||||||||||||
| Operating revenues |
$ | 1,475 | $ | 2 | (c) | $ | 1,477 | $ | 1,729 | $ | 2 | (c) | $ | 1,731 | ||||||||||
| Operating expenses |
||||||||||||||||||||||||
| Purchased power |
776 | — | 776 | 1,068 | — | 1,068 | ||||||||||||||||||
| Operating and maintenance |
273 | (2 | )(c),(d) | 271 | 306 | — | 306 | |||||||||||||||||
| Operating and maintenance for regulatory required programs (b) |
19 | — | 19 | 11 | — | 11 | ||||||||||||||||||
| Depreciation and amortization |
125 | — | 125 | 119 | — | 119 | ||||||||||||||||||
| Taxes other than income |
79 | — | 79 | 87 | — | 87 | ||||||||||||||||||
| Total operating expenses |
1,272 | (2 | ) | 1,270 | 1,591 | — | 1,591 | |||||||||||||||||
| Operating income |
203 | 4 | 207 | 138 | 2 | 140 | ||||||||||||||||||
| Other income and deductions |
||||||||||||||||||||||||
| Interest expense, net |
(82 | ) | — | (82 | ) | (87 | ) | — | (87 | ) | ||||||||||||||
| Equity in losses of unconsolidated affiliates |
— | — | — | (2 | ) | — | (2 | ) | ||||||||||||||||
| Other, net |
(19 | ) | — | (19 | ) | 3 | — | 3 | ||||||||||||||||
| Total other income and deductions |
(101 | ) | — | (101 | ) | (86 | ) | — | (86 | ) | ||||||||||||||
| Income before income taxes |
102 | 4 | 106 | 52 | 2 | 54 | ||||||||||||||||||
| Income taxes |
56 | 2 | (c),(d) | 58 | 19 | 1 | (c) | 20 | ||||||||||||||||
| Net income |
$ | 46 | $ | 2 | $ | 48 | $ | 33 | $ | 1 | $ | 34 | ||||||||||||
| Nine Months Ended September 30, 2009 | Nine Months Ended September 30, 2008 | |||||||||||||||||||||||
| GAAP (a) | Adjustments | Adjusted Non-GAAP |
GAAP (a) | Adjustments | Adjusted Non-GAAP |
|||||||||||||||||||
| Operating revenues |
$ | 4,417 | $ | 4 | (c) | $ | 4,421 | $ | 4,594 | $ | 5 | (c) | $ | 4,599 | ||||||||||
| Operating expenses |
||||||||||||||||||||||||
| Purchased power |
2,373 | — | 2,373 | 2,729 | — | 2,729 | ||||||||||||||||||
| Operating and maintenance |
796 | (21 | )(c),(d) | 775 | 828 | (4 | )(c) | 824 | ||||||||||||||||
| Operating and maintenance for regulatory required programs (b) |
44 | — | 44 | 17 | 17 | |||||||||||||||||||
| Depreciation and amortization |
371 | — | 371 | 343 | — | 343 | ||||||||||||||||||
| Taxes other than income |
215 | — | 215 | 227 | — | 227 | ||||||||||||||||||
| Total operating expenses |
3,799 | (21 | ) | 3,778 | 4,144 | (4 | ) | 4,140 | ||||||||||||||||
| Operating income |
618 | 25 | 643 | 450 | 9 | 459 | ||||||||||||||||||
| Other income and deductions |
||||||||||||||||||||||||
| Interest expense, net |
(241 | ) | (6 | )(e) | (247 | ) | (279 | ) | — | (279 | ) | |||||||||||||
| Equity in losses of unconsolidated affiliates |
— | — | — | (7 | ) | — | (7 | ) | ||||||||||||||||
| Other, net |
67 | (60 | )(e) | 7 | 12 | — | 12 | |||||||||||||||||
| Total other income and deductions |
(174 | ) | (66 | ) | (240 | ) | (274 | ) | — | (274 | ) | |||||||||||||
| Income before income taxes |
444 | (41 | ) | 403 | 176 | 9 | 185 | |||||||||||||||||
| Income taxes |
169 | (17 | )(c),(d),(e) | 152 | 66 | 4 | (c) | 70 | ||||||||||||||||
| Net income |
$ | 275 | $ | (24 | ) | $ | 251 | $ | 110 | $ | 5 | $ | 115 | |||||||||||
| (a) | Results reported in accordance with GAAP. |
| (b) | Includes amounts for various legislative and/or regulatory programs that are recoverable from customers on a full and current basis through a reconcilable automatic adjustment clause. An equal and offsetting amount has been reflected in operating revenues during the period. |
| (c) | Adjustment to exclude the impact of the 2007 Illinois electric rate settlement. |
| (d) | Adjustment to exclude 2009 severance charges. |
| (e) | Adjustment to exclude 2009 remeasurements of income tax uncertainties. |
12
EXELON CORPORATION
Reconciliation of Adjusted (non-GAAP) Operating Earnings to
GAAP Consolidated Statements of Operations
(unaudited)
(in millions)
| PECO
|
|||||||||||||||||||||||
| Three Months Ended September 30, 2009 | Three Months Ended September 30, 2008 | ||||||||||||||||||||||
| GAAP (a) | Adjustments | Adjusted Non-GAAP |
GAAP (a) | Adjustments | Adjusted Non-GAAP |
||||||||||||||||||
| Operating revenues |
$ | 1,327 | $ | — | $ | 1,327 | $ | 1,441 | $ | — | $ | 1,441 | |||||||||||
| Operating expenses |
|||||||||||||||||||||||
| Purchased power |
625 | — | 625 | 693 | — | 693 | |||||||||||||||||
| Fuel |
26 | — | 26 | 50 | — | 50 | |||||||||||||||||
| Operating and maintenance |
154 | 2 | (b) | 156 | 192 | — | 192 | ||||||||||||||||
| Depreciation and amortization |
272 | — | 272 | 243 | — | 243 | |||||||||||||||||
| Taxes other than income |
78 | — | 78 | 73 | — | 73 | |||||||||||||||||
| Total operating expenses |
1,155 | 2 | 1,157 | 1,251 | — | 1,251 | |||||||||||||||||
| Operating income |
172 | (2 | ) | 170 | 190 | — | 190 | ||||||||||||||||
| Other income and deductions |
|||||||||||||||||||||||
| Interest expense, net |
(46 | ) | — | (46 | ) | (55 | ) | — | (55 | ) | |||||||||||||
| Equity in losses of unconsolidated affiliates |
(6 | ) | — | (6 | ) | (4 | ) | — | (4 | ) | |||||||||||||
| Other, net |
2 | — | 2 | 2 | — | 2 | |||||||||||||||||
| Total other income and deductions |
(50 | ) | — | (50 | ) | (57 | ) | — | (57 | ) | |||||||||||||
| Income before income taxes |
122 | (2 | ) | 120 | 133 | — | 133 | ||||||||||||||||
| Income taxes |
30 | (1 | )(b) | 29 | 43 | — | 43 | ||||||||||||||||
| Net income |
$ | 92 | $ | (1 | ) | $ | 91 | $ | 90 | $ | — | $ | 90 | ||||||||||
| Nine Months Ended September 30, 2009 | Nine Months Ended September 30, 2008 | ||||||||||||||||||||||
| GAAP (a) | Adjustments | Adjusted Non-GAAP |
GAAP (a) | Adjustments | Adjusted Non-GAAP |
||||||||||||||||||
| Operating revenues |
$ | 4,045 | $ | — | $ | 4,045 | $ | 4,195 | $ | — | $ | 4,195 | |||||||||||
| Operating expenses |
|||||||||||||||||||||||
| Purchased power |
1,742 | — | 1,742 | 1,859 | — | 1,859 | |||||||||||||||||
| Fuel |
346 | — | 346 | 397 | 397 | ||||||||||||||||||
| Operating and maintenance |
481 | (3 | )(b) | 478 | 557 | — | 557 | ||||||||||||||||
| Depreciation and amortization |
726 | — | 726 | 653 | — | 653 | |||||||||||||||||
| Taxes other than income |
213 | — | 213 | 203 | — | 203 | |||||||||||||||||
| Total operating expenses |
3,508 | (3 | ) | 3,505 | 3,669 | — | 3,669 | ||||||||||||||||
| Operating income |
537 | 3 | 540 | 526 | — | 526 | |||||||||||||||||
| Other income and deductions |
|||||||||||||||||||||||
| Interest expense, net |
(145 | ) | — | (145 | ) | (171 | ) | — | (171 | ) | |||||||||||||
| Equity in losses of unconsolidated affiliates |
(19 | ) | — | (19 | ) | (11 | ) | — | (11 | ) | |||||||||||||
| Other, net |
8 | — | 8 | 13 | — | 13 | |||||||||||||||||
| Total other income and deductions |
(156 | ) | — | (156 | ) | (169 | ) | — | (169 | ) | |||||||||||||
| Income before income taxes |
381 | 3 | 384 | 357 | — | 357 | |||||||||||||||||
| Income taxes |
106 | 2 | (b) | 108 | 111 | — | 111 | ||||||||||||||||
| Net income |
$ | 275 | $ | 1 | $ | 276 | $ | 246 | $ | — | $ | 246 | |||||||||||
| (a) | Results reported in accordance with GAAP. |
| (b) | Adjustment to exclude 2009 severance charges. |
13
EXELON CORPORATION
Reconciliation of Adjusted (non-GAAP) Operating Earnings to
GAAP Consolidated Statements of Operations
(unaudited)
(in millions)
| Other | ||||||||||||||||||||||||
| Three Months Ended September 30, 2009 | Three Months Ended September 30, 2008 | |||||||||||||||||||||||
| GAAP (a) | Adjustments | Adjusted Non-GAAP |
GAAP (a) | Adjustments | Adjusted Non-GAAP |
|||||||||||||||||||
| Operating revenues |
$ | (908 | ) | $ | — | $ | (908 | ) | $ | (1,015 | ) | $ | — | $ | (1,015 | ) | ||||||||
| Operating expenses |
||||||||||||||||||||||||
| Purchased power |
(908 | ) | — | (908 | ) | (962 | ) | (51 | )(d) | (1,013 | ) | |||||||||||||
| Fuel |
(1 | ) | — | (1 | ) | (1 | ) | — | (1 | ) | ||||||||||||||
| Operating and maintenance |
1 | (9 | )(b) | (8 | ) | (13 | ) | — | (13 | ) | ||||||||||||||
| Depreciation and amortization |
14 | — | 14 | 11 | — | 11 | ||||||||||||||||||
| Taxes other than income |
4 | — | 4 | 5 | — | 5 | ||||||||||||||||||
| Total operating expenses |
(890 | ) | (9 | ) | (899 | ) | (960 | ) | (51 | ) | (1,011 | ) | ||||||||||||
| Operating loss |
(18 | ) | 9 | (9 | ) | (55 | ) | 51 | (4 | ) | ||||||||||||||
| Other income and deductions |
||||||||||||||||||||||||
| Interest expense, net |
(36 | ) | 1 | (c) | (35 | ) | (27 | ) | — | (27 | ) | |||||||||||||
| Equity in losses of unconsolidated affiliates and investments |
(1 | ) | — | (1 | ) | — | — | — | ||||||||||||||||
| Other, net |
(27 | ) | 36 | (c) | 9 | 1 | — | 1 | ||||||||||||||||
| Total other income and deductions |
(64 | ) | 37 | (27 | ) | (26 | ) | — | (26 | ) | ||||||||||||||
| Loss before income taxes |
(82 | ) | 46 | (36 | ) | (81 | ) | 51 | (30 | ) | ||||||||||||||
| Income taxes |
(44 | ) | 18 | (b),(c) | (26 | ) | (23 | ) | 20 | (d) | (3 | ) | ||||||||||||
| Net loss |
$ | (38 | ) | $ | 28 | $ | (10 | ) | $ | (58 | ) | $ | 31 | $ | (27 | ) | ||||||||
| Nine Months Ended September 30, 2009 | Nine Months Ended September 30, 2008 | ||||||||||||||||||||||
| GAAP (a) | Adjustments | Adjusted Non-GAAP |
GAAP (a) | Adjustments | Adjusted Non-GAAP |
||||||||||||||||||
| Operating revenues |
$ | (2,684 | ) | $ | — | $ | (2,684 | ) | $ | (2,734 | ) | $ | — | $ | (2,734 | ) | |||||||
| Operating expenses |
|||||||||||||||||||||||
| Purchased power |
(2,677 | ) | — | (2,677 | ) | (2,727 | ) | — | (2,727 | ) | |||||||||||||
| Fuel |
(1 | ) | — | (1 | ) | — | — | — | |||||||||||||||
| Operating and maintenance |
5 | (36 | )(b),(e) | (31 | ) | (25 | ) | — | (25 | ) | |||||||||||||
| Depreciation and amortization |
40 | — | 40 | 32 | — | 32 | |||||||||||||||||
| Taxes other than income |
14 | — | 14 | 14 | — | 14 | |||||||||||||||||
| Total operating expenses |
(2,619 | ) | (36 | ) | (2,655 | ) | (2,706 | ) | — | (2,706 | ) | ||||||||||||
| Operating loss |
(65 | ) | 36 | (29 | ) | (28 | ) | — | (28 | ) | |||||||||||||
| Other income and deductions |
|||||||||||||||||||||||
| Interest expense, net |
(92 | ) | 16 | (c),(f) | (76 | ) | (80 | ) | — | (80 | ) | ||||||||||||
| Equity in losses of unconsolidated affiliates and investments |
— | — | — | — | — | — | |||||||||||||||||
| Other, net |
(33 | ) | 46 | (c),(f) | 13 | 11 | — | 11 | |||||||||||||||
| Total other income and deductions |
(125 | ) | 62 | (63 | ) | (69 | ) | — | (69 | ) | |||||||||||||
| Loss before income taxes |
(190 | ) | 98 | (92 | ) | (97 | ) | — | (97 | ) | |||||||||||||
| Income taxes |
(69 | ) | 43 | (b),(c),(d),(e),(f) | (26 | ) | (46 | ) | — | (46 | ) | ||||||||||||
| Net loss |
$ | (121 | ) | $ | 55 | $ | (66 | ) | $ | (51 | ) | $ | — | $ | (51 | ) | |||||||
| (a) | Results reported in accordance with GAAP. |
| (b) | Adjustment to exclude external costs associated with Exelon’s proposed acquisition of NRG, which was terminated in July 2009. |
| (c) | Adjustment to exclude 2009 costs associated with early debt retirements. |
| (d) | Adjustment to exclude the mark-to-market impact of Exelon’s economic hedging activities. |
| (e) | Adjustment to exclude 2009 severance charges. |
| (f) | Adjustment to exclude a change in state deferred income taxes. |
14
EXELON CORPORATION
Exelon Generation Statistics
| Three Months Ended | |||||||||||||||
| Sept. 30, 2009 | Jun. 30, 2009 | Mar. 31, 2009 | Dec. 31, 2008 | Sept. 30, 2008 | |||||||||||
| Supply (in GWhs) |
|||||||||||||||
| Nuclear |
35,684 | 34,995 | 35,382 | 34,887 | 36,451 | ||||||||||
| Purchased Power |
6,669 | 5,276 | 6,077 | 6,100 | 8,761 | ||||||||||
| Fossil and Hydro |
2,689 | 2,701 | 2,765 | 2,162 | 2,685 | ||||||||||
| Power Team Supply |
45,042 | 42,972 | 44,224 | 43,149 | 47,897 | ||||||||||
| Three Months Ended | |||||||||||||||
| Sept. 30, 2009 | Jun. 30, 2009 | Mar. 31, 2009 | Dec. 31, 2008 | Sept. 30, 2008 | |||||||||||
| Electric Sales (in GWhs) |
|||||||||||||||
| ComEd (a) |
3,639 | 4,215 | 5,537 | 5,261 | 6,629 | ||||||||||
| PECO (a) |
10,809 | 9,277 | 10,223 | 9,760 | 11,333 | ||||||||||
| Market and Retail (a) |
30,594 | 29,480 | 28,464 | 28,128 | 29,935 | ||||||||||
| Total Electric Sales (b) (c) |
45,042 | 42,972 | 44,224 | 43,149 | 47,897 | ||||||||||
| Average Margin ($/MWh) |
|||||||||||||||
| Average Realized Revenue |
|||||||||||||||
| ComEd (a) |
$ | 64.03 | $ | 63.58 | $ | 63.21 | $ | 63.30 | $ | 64.41 | |||||
| PECO (a) |
51.35 | 51.74 | 49.30 | 49.28 | 53.03 | ||||||||||
| Market and Retail (a) |
52.99 | 54.27 | 57.12 | 54.18 | 65.98 | ||||||||||
| Total Electric Sales |
53.48 | 54.64 | 56.08 | 54.18 | 62.70 | ||||||||||
| Average Purchased Power and Fuel Cost (d) |
$ | 17.16 | $ | 15.68 | $ | 16.82 | $ | 15.90 | $ | 26.16 | |||||
| Average Margin (d) |
$ | 36.32 | $ | 38.96 | $ | 39.25 | $ | 38.28 | $ | 36.54 | |||||
| Around-the-clock Market Prices ($/MWh) (e) |
|||||||||||||||
| PJM West Hub |
$ | 33.20 | $ | 33.70 | $ | 49.18 | $ | 52.62 | $ | 77.37 | |||||
| NiHub |
25.69 | 26.11 | 34.09 | 38.06 | 53.28 | ||||||||||
| (a) | $104 million, $69 million, $31 million and $20 million of pre-tax revenue, and $15 million of a pre-tax reduction in revenue, resulting from the settlement of the ComEd swap starting in June 2008, have been excluded from ComEd and included in Market and Retail sales for the quarters ended September 30, 2009, June 30, 2009, March 31, 2009, December 31, 2008 and September, 30, 2008, respectively. Additionally, $11 million (397 GWhs), $7 million (209 GWhs), $58 million (898 GWhs), and $29 million (486 GWhs) of pre-tax revenue, resulting from sales to ComEd under the RFP, which started in September 2008, have been excluded from ComEd and included in Market and Retail sales for the quarters ended September 30, 2009, June 30, 2009, March 31, 2009 and December 31, 2008, respectively. In addition, renewable energy credits sales to affiliates have been included within Market and Retail Sales. |
| (b) | Excludes retail gas activity, trading portfolio and other operating revenue. |
| (c) | Total sales do not include trading volume of 1,645 GWhs, 2,003 GWhs, 2,331 GWhs, 2,153 GWhs and 3,092 GWhs for the three months ended September 30, 2009, June 30, 2009, March 31, 2009, December 31, 2008 and September 30, 2008, respectively. |
| (d) | Excludes the mark-to-market impact of Generation’s economic hedging activities. |
| (e) | Represents the average for the quarter. |
15
EXELON CORPORATION
Exelon Generation Statistics
Nine Months Ended September 30, 2009 and 2008
| September 30, 2009 | September 30, 2008 | |||||
| Supply (in GWhs) |
||||||
| Nuclear |
106,061 | 104,454 | ||||
| Purchased Power |
18,022 | 20,164 | ||||
| Fossil and Hydro |
8,155 | 8,407 | ||||
| Power Team Supply |
132,238 | 133,025 | ||||
| September 30, 2009 | September 30, 2008 | |||||
| Electric Sales (in GWhs) |
||||||
| ComEd (a) |
13,391 | 17,939 | ||||
| PECO (a) |
30,309 | 31,206 | ||||
| Market and Retail (a) |
88,538 | 83,880 | ||||
| Total Electric Sales (b) (c) |
132,238 | 133,025 | ||||
| Average Margin ($/MWh) |
||||||
| Average Realized Revenue |
||||||
| ComEd (a) |
$ | 63.55 | $ | 63.83 | ||
| PECO (a) |
50.78 | 51.34 | ||||
| Market and Retail (a) |
54.74 | 61.93 | ||||
| Total Electric Sales |
54.70 | 59.70 | ||||
| Average Purchased Power and Fuel Cost (d) |
$ | 16.58 | $ | 21.16 | ||
| Average Margin (d) |
$ | 38.12 | $ | 38.54 | ||
| Around-the-clock Market Prices ($/MWh) (e) |
||||||
| PJM West Hub |
$ | 38.64 | $ | 73.86 | ||
| NiHub |
28.59 | 52.68 | ||||
| (a) | $204 million of pre-tax revenue, and $22 million of a pre-tax reduction in revenue, resulting from the settlement of the ComEd swap starting in June 2008, have been excluded from ComEd and included in Market and Retail sales for the nine months ended September 30, 2009 and September 30, 2008, respectively. Additionally, $76 million (1,504 GWhs) of pre-tax revenue, resulting from sales to ComEd under the RFP, which started in September 2008, have been excluded from ComEd and included in Market and Retail sales for the nine months ended September 30, 2009. In addition, renewable energy credits sales to affiliates have been included within Market and Retail Sales. |
| (b) | Excludes retail gas sales, trading portfolio and other operating revenue. |
| (c) | Total sales do not include trading volume of 5,979 GWhs and 6,738 GWhs for the nine months ended September 30, 2009 and 2008, respectively. |
| (d) | Excludes the mark-to-market impact of Generation’s economic hedging activities. |
| (e) | Represents the average for the year. |
16
EXELON CORPORATION
ComEd Statistics
Three Months Ended September 30, 2009 and 2008
| Electric Deliveries (in GWhs) | Revenue (in millions) | |||||||||||||||
| 2009 | 2008 | % Change | 2009 | 2008 | % Change | |||||||||||
| Full Service (a) |
||||||||||||||||
| Residential |
6,983 | 8,114 | (13.9 | )% | $ | 797 | $ | 950 | (16.1 | )% | ||||||
| Small Commercial & Industrial |
3,494 | 4,047 | (13.7 | )% | 333 | 428 | (22.2 | )% | ||||||||
| Large Commercial & Industrial |
295 | 319 | (7.5 | )% | 17 | 31 | (45.2 | )% | ||||||||
| Public Authorities & Electric Railroads |
98 | 168 | (41.7 | )% | 10 | 14 | (28.6 | )% | ||||||||
| Total Full Service |
10,870 | 12,648 | (14.1 | )% | 1,157 | 1,423 | (18.7 | )% | ||||||||
| Delivery Only (b) |
||||||||||||||||
| Residential (c) |
1 | — | n.m. | — | — | n.m. | ||||||||||
| Small Commercial & Industrial |
4,954 | 4,932 | 0.4 | % | 88 | 75 | 17.3 | % | ||||||||
| Large Commercial & Industrial |
6,627 | 7,379 | (10.2 | )% | 85 | 78 | 9.0 | % | ||||||||
| Public Authorities & Electric Railroads |
189 | 137 | 38.0 | % | 3 | 2 | 50.0 | % | ||||||||
| Total Delivery Only |
11,771 | 12,448 | (5.4 | )% | 176 | 155 | 13.5 | % | ||||||||
| Total Retail |
22,641 | 25,096 | (9.8 | )% | 1,333 | 1,578 | (15.5 | )% | ||||||||
| Other Revenue (d) |
142 | 151 | (6.0 | )% | ||||||||||||
| Total Revenues |
$ | 1,475 | $ | 1,729 | (14.7 | )% | ||||||||||
| Purchased Power |
$ | 776 | $ | 1,068 | (27.3 | )% | ||||||||||
| Heating and Cooling Degree-Days (e) |
2009 | 2008 | Normal | |||||||||||||
| Heating Degree-Days |
77 | 53 | 110 | |||||||||||||
| Cooling Degree-Days |
412 | 626 | 624 | |||||||||||||
| (a) | Reflects deliveries to customers purchasing electricity from ComEd. |
| (b) | Reflects customers electing to purchase electricity from an alternative electric generation supplier. |
| (c) | There were a minimal number of residential customers being served by alternative electric generation suppliers with total revenue of less than $1 million. |
| (d) | Other revenue primarily includes transmission revenue from PJM Interconnection, LLC (PJM). Other items include late payment charges and mutual assistance program revenues. |
| (e) | Reflects the impact of the leap year day in 2008. |
| n.m. | Not meaningful. |
Nine Months Ended September 30, 2009 and 2008
| Electric Deliveries (in GWhs) | Revenue (in millions) | |||||||||||||||
| 2009 | 2008 | % Change | 2009 | 2008 | % Change | |||||||||||
| Full Service (a) |
||||||||||||||||
| Residential |
20,078 | 21,521 | (6.7 | )% | $ | 2,374 | $ | 2,444 | (2.9 | )% | ||||||
| Small Commercial & Industrial |
10,445 | 11,392 | (8.3 | )% | 1,038 | 1,169 | (11.2 | )% | ||||||||
| Large Commercial & Industrial |
924 | 803 | 15.1 | % | 56 | 73 | (23.3 | )% | ||||||||
| Public Authorities & Electric Railroads |
305 | 481 | (36.6 | )% | 32 | 40 | (20.0 | )% | ||||||||
| Total Full Service |
31,752 | 34,197 | (7.1 | )% | 3,500 | 3,726 | (6.1 | )% | ||||||||
| Delivery Only (b) |
||||||||||||||||
| Residential (c) |
1 | — | n | .m. | — | — | n.m. | |||||||||
| Small Commercial & Industrial |
13,892 | 14,029 | (1.0 | )% | 244 | 211 | 15.6 | % | ||||||||
| Large Commercial & Industrial |
19,240 | 21,133 | (9.0 | )% | 238 | 215 | 10.7 | % | ||||||||
| Public Authorities & Electric Railroads |
603 | 423 | 42.6 | % | 10 | 5 | 100.0 | % | ||||||||
| Total Delivery Only |
33,736 | 35,585 | (5.2 | )% | 492 | 431 | 14.2 | % | ||||||||
| Total Retail |
65,488 | 69,782 | (6.2 | )% | 3,992 | 4,157 | (4.0 | )% | ||||||||
| Other Revenue (d) |
425 | 437 | (2.7 | )% | ||||||||||||
| Total Revenues |
$ | 4,417 | $ | 4,594 | (3.9 | )% | ||||||||||
| Purchased Power |
$ | 2,373 | $ | 2,729 | (13.0 | )% | ||||||||||
| Heating and Cooling Degree-Days (e) |
2009 | 2008 | Normal | |||||||||||||
| Heating Degree-Days |
4,165 | 4,225 | 4,084 | |||||||||||||
| Cooling Degree-Days |
589 | 818 | 848 | |||||||||||||
| (a) | Reflects deliveries to customers purchasing electricity from ComEd. |
| (b) | Reflects customers electing to purchase electricity from an alternative electric generation supplier. |
| (c) | There were a minimal number of residential customers being served by alternative electric generation suppliers with total revenue of less than $1 million. |
| (d) | Other revenue primarily includes transmission revenue from PJM Interconnection, LLC (PJM). Other items include late payment charges and mutual assistance program revenues. |
| (e) | Reflects the impact of the leap year day in 2008. |
| n.m. | Not meaningful. |
17
EXELON CORPORATION
PECO Statistics
Three Months Ended September 30, 2009 and 2008
| Electric and Gas Deliveries | Revenue (in millions) | |||||||||||||||
| 2009 | 2008 | % Change | 2009 | 2008 | % Change | |||||||||||
| Electric (in GWhs) |
||||||||||||||||
| Full Service (a) |
||||||||||||||||
| Residential |
3,501 | 3,802 | (7.9 | )% | $ | 547 | $ | 591 | (7.4 | )% | ||||||
| Small Commercial & Industrial |
2,128 | 2,258 | (5.8 | )% | 286 | 293 | (2.4 | )% | ||||||||
| Large Commercial & Industrial |
4,294 | 4,445 | (3.4 | )% | 339 | 376 | (9.8 | )% | ||||||||
| Public Authorities & Electric Railroads |
233 | 221 | 5.4 | % | 22 | 22 | 0.0 | % | ||||||||
| Total Full Service |
10,156 | 10,726 | (5.3 | )% | 1,194 | 1,282 | (6.9 | )% | ||||||||
| Delivery Only (b) |
||||||||||||||||
| Residential |
5 | 9 | (44.4 | )% | 1 | 1 | 0.0 | % | ||||||||
| Small Commercial & Industrial |
95 | 131 | (27.5 | )% | 5 | 7 | (28.6 | )% | ||||||||
| Large Commercial & Industrial |
7 | 1 | 600.0 | % | — | — | 0.0 | % | ||||||||
| Total Delivery Only |
107 | 141 | (24.1 | )% | 6 | 8 | (25.0 | )% | ||||||||
| Total Electric Retail |
10,263 | 10,867 | (5.6 | )% | 1,200 | 1,290 | (7.0 | )% | ||||||||
| Other Revenue (c) |
65 | 76 | (14.5 | )% | ||||||||||||
| Total Electric Revenue |
1,265 | 1,366 | (7.4 | )% | ||||||||||||
| Gas (in mmcfs) |
||||||||||||||||
| Retail Sales |
3,694 | 3,794 | (2.6 | )% | 55 | 70 | (21.4 | )% | ||||||||
| Transportation and Other |
6,145 | 6,455 | (4.8 | )% | 7 | 5 | 40.0 | % | ||||||||
| Total Gas |
9,839 | 10,249 | (4.0 | )% | 62 | 75 | (17.3 | )% | ||||||||
| Total Electric and Gas Revenues |
$ | 1,327 | $ | 1,441 | (7.9 | )% | ||||||||||
| Purchased Power |
$ | 625 | $ | 693 | (9.8 | )% | ||||||||||
| Fuel |
26 | 50 | (48.0 | )% | ||||||||||||
| Total Purchased Power and Fuel |
$ | 651 | $ | 743 | (12.4 | )% | ||||||||||
| Heating and Cooling Degree-Days |
2009 | 2008 | Normal | |||||||||||||
| Heating Degree-Days |
19 | 12 | 36 | |||||||||||||
| Cooling Degree-Days |
884 | 942 | 939 | |||||||||||||
Nine Months Ended September 30, 2009 and 2008
| Electric and Gas Deliveries | Revenue (in millions) | |||||||||||||||
| 2009 | 2008 | % Change | 2009 | 2008 | % Change | |||||||||||
| Electric (in GWhs) |
||||||||||||||||
| Full Service (a) |
||||||||||||||||
| Residential |
9,788 | 10,151 | (3.6 | )% | $ | 1,428 | $ | 1,485 | (3.8 | )% | ||||||
| Small Commercial & Industrial |
6,155 | 6,257 | (1.6 | )% | 787 | 793 | (0.8 | )% | ||||||||
| Large Commercial & Industrial |
11,961 | 12,520 | (4.5 | )% | 995 | 1,074 | (7.4 | )% | ||||||||
| Public Authorities & Electric Railroads |
702 | 681 | 3.1 | % | 68 | 66 | 3.0 | % | ||||||||
| Total Full Service |
28,606 | 29,609 | (3.4 | )% | 3,278 | 3,418 | (4.1 | )% | ||||||||
| Delivery Only (b) |
||||||||||||||||
| Residential |
17 | 24 | (29.2 | )% | 2 | 2 | 0.0 | % | ||||||||
| Small Commercial & Industrial |
277 | 370 | (25.1 | )% | 15 | 20 | (25.0 | )% | ||||||||
| Large Commercial & Industrial |
9 | 3 | 200.0 | % | — | — | 0.0 | % | ||||||||
| Total Delivery Only |
303 | 397 | (23.7 | )% | 17 | 22 | (22.7 | )% | ||||||||
| Total Electric Retail |
28,909 | 30,006 | (3.7 | )% | 3,295 | 3,440 | (4.2 | )% | ||||||||
| Other Revenue (c) |
200 | 212 | (5.7 | )% | ||||||||||||
| Total Electric Revenue |
3,495 | 3,652 | (4.3 | )% | ||||||||||||
| Gas (in mmcfs) |
||||||||||||||||
| Retail Sales |
39,444 | 36,979 | 6.7 | % | 530 | 522 | 1.5 | % | ||||||||
| Transportation and Other |
20,128 | 20,806 | (3.3 | )% | 20 | 21 | (4.8 | )% | ||||||||
| Total Gas |
59,572 | 57,785 | 3.1 | % | 550 | 543 | 1.3 | % | ||||||||
| Total Electric and Gas Revenues |
$ | 4,045 | $ | 4,195 | (3.6 | )% | ||||||||||
| Purchased Power |
$ | 1,742 | $ | 1,859 | (6.3 | )% | ||||||||||
| Fuel |
346 | 397 | (12.8 | )% | ||||||||||||
| Total Purchased Power and Fuel |
$ | 2,088 | $ | 2,256 | (7.4 | )% | ||||||||||
| Heating and Cooling Degree-Days (d) |
2009 | 2008 | Normal | |||||||||||||
| Heating Degree-Days |
2,967 | 2,744 | 3,004 | |||||||||||||
| Cooling Degree-Days |
1,236 | 1,335 | 1,271 | |||||||||||||
| (a) | Full service reflects deliveries to customers purchasing electricity directly from PECO. Revenue reflects the cost of energy, the cost of the transmission and the distribution of the energy and a CTC. |
| (b) | Delivery only service reflects deliveries to customers electing to receive electric generation service from a competitive electric generation supplier. Revenue reflects a distribution charge and a CTC. |
| (c) | Other revenue includes transmission revenue from PJM, wholesale revenue and other wholesale energy sales. |
| (d) | Reflects the impact of the leap year day in 2008. |
18
 Earnings Conference Call • 3 rd Quarter 2009 October 23, 2009 Exhibit 99.2 |
 2 Forward-Looking Statements This presentation includes 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 these forward-looking statements
include those discussed herein as well as those discussed in (1) Exelon’s 2008 Annual Report
on Form 10-K in (a) ITEM 1A. Risk Factors, (b) ITEM 7. Management’s Discussion and
Analysis of Financial Condition and Results of Operations and (c) ITEM 8. Financial Statements
and Supplementary Data: Note 18; (2) Exelon’s Third Quarter 2009 Quarterly Report on Form
10-Q (to be filed on October 23, 2009) in (a) Part II, Other Information, ITEM 1A. Risk
Factors and (b) Part I, Financial Information, ITEM 1. Financial Statements: Note 14 and (3) other
factors discussed in filings with the Securities and Exchange Commission (SEC) by Exelon
Corporation, Commonwealth Edison Company, PECO Energy Company and Exelon Generation Company,
LLC (Companies). Readers are cautioned not to place undue reliance on these forward-looking
statements, which apply only as of the date of this presentation. None of the Companies
undertakes any obligation to publicly release any revision to its forward-looking statements to
reflect events or circumstances after the date of this presentation. This presentation includes references to adjusted (non-GAAP) operating earnings and non-GAAP
cash flows that exclude the impact of certain factors. We believe that these adjusted operating
earnings and cash flows are representative of the underlying operational results of the Companies. Please refer to the attachments to the earnings release and the appendix to this presentation for a reconciliation of adjusted (non-GAAP) operating earnings to GAAP earnings.
Please refer to the footnotes of the following slides for a reconciliation non-GAAP cash
flows to GAAP cash flows. |
 3 Q3 Highlights Financial: • Delivering consistent operating performance • Exceeding 2009 cost savings target • Narrowing 2009 EPS guidance range Energy Markets: • Second PECO procurement completed • Illinois Power Agency procurement plan proposed Regulatory: • Focus on improved results for ComEd and PECO • Filed plans for Smart Grid and Smart Meter investments • Successful relicensing of TMI nuclear unit Climate Change: • Advocating for greenhouse gas-reduction legislation • Collaboration among industry and other key stakeholders |
 4 Key Financial Messages Q3 operating results of $0.96/share driven by: • Cost discipline – exceeded 2009 cost savings target with over $80 million of savings in third quarter • 94.7% nuclear capacity factor • Cooler than normal weather of $0.04/share at ComEd and $0.03/share at PECO Narrowing 2009 operating earnings guidance to $4.00-$4.10/share • Committed to an additional $100 million of one-time O&M savings in 2009
Well-positioned for continued financial strength and flexibility • Increased 2009 forecasted cash flow from operations (1) to $5.6 billion for 2009 - $850 million higher than original plan • $350 million discretionary pension contribution • $1.5 billion tender/make whole and refinancing at Exelon and Exelon Generation Refer to Earnings Release Attachments for additional details and to the Appendix for a reconciliation of adjusted (non-GAAP) operating EPS to GAAP EPS. (1) Cash Flow from Operations primarily includes net cash flows provided by operating
activities (excluding counterparty collateral activity) and net cash flows used in investing activities other than capital expenditures. Note: Data contained on this slide is rounded. |
 5 $0.92 $0.14 $0.76 $0.14 $0.05 $0.07 2008 2009 Operating EPS $2.66 $0.37 $2.50 $0.42 $0.17 $0.38 2008 2009 HoldCo/Other ExGen PECO ComEd 3 rd Quarter (Q3) (1) Exceeding cost savings target allowed Exelon to deliver results within our range
(1) Refer to Earnings Release Attachments for additional details and to the
Appendix for a reconciliation of adjusted (non-GAAP) operating EPS to GAAP EPS. $1.06 $1.14 GAAP EPS Year-to-Date (YTD) (1) $3.19 $3.13 $3.06 $3.21 $0.96 $1.07 |
 6 Exelon
Generation Operating EPS Contribution 2009 2008 Key Drivers – Q3 ’09 vs. Q3 ’08 (1) Unfavorable portfolio/market conditions: $(0.06) Lower nuclear volume and higher nuclear fuel costs: $(0.04) Higher income tax expense: $(0.04) Higher costs due to pension and OPEB expense and refueling outages, partially offset by cost savings initiatives: $(0.02) Reversal of Q1 IL tax ruling: $(0.01) ’08 reserve associated with Lehman bankruptcy: +$0.02 (1) Refer to the Earnings Release Attachments for additional details and to the Appendix
for a reconciliation of adjusted (non-GAAP) operating EPS to GAAP EPS (2) Outage days exclude Salem. 36 17 Refueling 21 8 Non-refueling Q3 2009 Q3 2008 Outage Days (2) 3Q YTD $0.92 $0.76 $2.50 $2.66 |
 7 Represents an approximate range of expected gross margin, taking into account hedges in place, between the
5th and 95th percentile confidence levels. Approximate gross margin ranges are based upon
an internal simulation model and are subject to change based upon market inputs, future transactions and potential modeling changes. These ranges of approximate gross margin in 2010 and 2011 do not represent earnings guidance or a forecast of future
results as Exelon has not completed its planning or optimization processes for those years.
The price distributions that generate this range are calibrated to market quotes for power, fuel, load following products and options as of September 30, 2009. Percent of expected generation hedged represents how many equivalent MW have been hedged at forward market
prices as of September 30, 2009; all hedge products used are converted to an equivalent
average MW volume and the calculation considers whether hedges are power sales or financial products. Hedging Update The primary objective of Exelon’s hedging program is to manage market risks and
protect the value of our generation and investment-grade balance sheet
while preserving our ability to participate in improving long-term
market fundamentals • We typically follow a 36-month ratable hedging program • As we execute our hedging program, our percent of expected generation hedged increases and our potential range of earnings outcomes narrows as we move closer to the delivery year 2009 2010 2011 Percentage of Expected Generation Hedged (2) 98-100% 88-91% 63-66% Midwest 98-100 88-91 67-70 Mid-Atlantic 97-99 91-94 56-59 South 98-100 90-93 52-55 • We employ natural gas and power put options within the portfolio to allow us to reduce market risk while preserving upside potential 95% case 5% case $6,700 $6,600 $6,100 $6,500 $6,000 $8,200 $4,000 $5,000 $6,000 $7,000 $8,000 $9,000 $10,000 2009 2010 2011 (1) (2) |
 8 Key Drivers – Q3 ’09 vs. Q3 ’08 (1) Higher electric distribution rates: +$0.06 Net impact of 2008 write-offs associated with final distribution rate order: +$0.02 Lower O&M due to cost savings initiatives and decreased storm costs partially offset by higher pension and OPEB expense and inflation: +$0.01 Reversal of Q1 IL tax ruling: $(0.05) Weather: $(0.03) Reduced load: $(0.01) ComEd Operating EPS Contribution (1) Refer to the Earnings Release Attachments for additional details and to the Appendix
for a reconciliation of adjusted (non-GAAP) operating EPS to GAAP EPS 2009 2008 3Q YTD $0.05 $0.07 $0.38 $0.17 Q3 Actual Normal Days >90 degrees 1 11 Cooling Degree Days 412 624 |
 9 -10.0% -7.5% -5.0% -2.5% 0.0% 2.5% 5.0% 7.5% 10.0% 09Q1 09Q2 09Q3 09Q4E 10Q1E 10Q2E 10Q3E 10Q4E -10.0% -7.5% -5.0% -2.5% 0.0% 2.5% 5.0% 7.5% 10.0% All Customer Classes Large C&I Residential Gross Metro Product (right axis) ComEd Load Trends Weather-Normalized Load Key Economic Indicators Note: C&I = Commercial & Industrial Weather-Normalized Load Year-over-Year (4) Chicago U.S. Unemployment rate (1) 10.5% 9.8% 2009 annualized growth in gross domestic/metro product (2) (3.7)% (2.6)% 7/09 Home price index (3) (14.2)% (13.3)% (1) Source: Illinois Dept. of Employment Security (October 2009) and U.S.
Dept. of Labor (October 2009) (2) Source: Moody’s Economy.com (September 2009) (3) Source: S&P Case-Shiller Index (4) Not adjusted for leap year effect Q309 Q409E 2009E (4) 2010E Customer Growth (0.5)% (0.6)% (0.4)% 0.1% Average Use-Per-Customer 0.1% (0.7)% (0.9)% (0.1)% Total Residential (0.4)% (1.3)% (1.3)% 0.0% Small C&I (2.9)% (0.8)% (2.4)% 1.0% Large C&I (8.6)% (4.1)% (6.7)% 1.5% All Customer Classes (3.8)% (1.9)% (3.4)% 0.8% |
 10 PECO Operating EPS Contribution Key Drivers – Q3 ’09 vs. Q3 ’08 (1) Lower bad debt expense: +$0.04 Higher other revenue net fuel, including gas distribution revenues: +$0.02 Competitive Transition Charge (CTC) amortization: $(0.03) Reduced load: $(0.03) Weather: $(0.01) 2009 2008 (1) Refer to the Earnings Release Attachments for additional details and to the Appendix
for a reconciliation of adjusted (non-GAAP) operating EPS to GAAP EPS. 3Q YTD $0.14 $0.14 $0.42 $0.37 Q3 Actual Normal Days >90 degrees 6 18 Cooling Degree Days 884 939 |
 11 PECO Load Trends Weather-Normalized Electric Load Key Economic Indicators Weather-Normalized Load Year-over-Year (3) Philadelphia U.S. Unemployment rate (1) 8.5%
9.8% 2009 annualized growth in gross domestic/metro product (2) (3.4)%
(2.6)% (1) Source: U.S Dept. of Labor (PHL August 2009, US – October 2009) (2) Source: Moody’s Economy.com (September 2009) (3) Not adjusted for leap year effect -10.0% -7.5% -5.0% -2.5% 0.0% 2.5% 5.0% 7.5% 10.0% 09Q1 09Q2 09Q3 09Q4E 10Q1E 10Q2E 10Q3E 10Q4E -10.0% -7.5% -5.0% -2.5% 0.0% 2.5% 5.0% 7.5% 10.0% All Customer Classes Large C&I Residential Gross Metro Product (right axis) Note: C&I = Commercial & Industrial Q309 Q409E 2009E (3) 2010E Customer Growth (0.4)% (0.4)% (0.3)% (0.0)% Average Use-Per-Customer (5.1)% (0.4)% (2.2)% (0.5)% Total Residential (5.5)% (0.8)% (2.5)% (0.6)% Small C&I (5.1)% (3.4)% (2.7)% (0.8)% Large C&I (2.2)% (1.7)% (3.0)% (2.3)% All Customer Classes (3.9)% (1.8)% (2.7)% (1.3)% |
 12 Delivering on Cost Savings Commitments • On track to exceed promised cost savings in 2009 – Identified $100 million of additional one-time cost saving opportunities for 2009 Projected to exceed cost management goal in 2009 by $100 million Note: Data contained on this slide is rounded. $4.5B (2)(3) $4.5B (2) $4.4B (2)(3) (1) Reflects operating O&M data and excludes decommissioning effect. ComEd and PECO operating
O&M exclude energy efficiency costs recoverable under a rider. (2) Exelon
Consolidated includes operating O&M expense from Holding Company. (3) Reflects ~$175
million increase in operating O&M expense from 2008A to 2009E due to higher pension and OPEB expense. O&M Expense (1) 2008A 2009 Original Commitment 2009 Revised Forecast |
 13 Financial Flexibility Increased Future Cash Flexibility Lowered Cost of Debt In the third quarter, Exelon capitalized on strategic opportunities to create future financial flexibility • $350 million discretionary 2008 pension contribution • Lowered estimated 2011 contribution by $1 billion • Smoothing election (1) lowers volatility in future contributions • Used cash on hand • Successfully executed $1.5 billion tender/make whole and refinancing • Expected to lower annual interest expense by approximately $12 million • Extended average maturity of Generation/Corporate debt portfolio by 6.6 years (1) Contributions reflect the impact of electing the option to smooth asset returns provided
under the Worker, Retiree and Employer Recovery Act of 2008, which allows the use of average assets, including expected returns (subject to certain limitations) for a 24-month period prior to the measurement date, in the determination of funding requirements. |
 14 Appendix |
    15 2009 Operating Earnings Guidance 2009E 2008A $0.49 $3.46 $4.20 ComEd PECO Exelon Generation 2009 Earnings Drivers ComEd PECO Exelon Generation Holdco Holdco Exelon $0.33 Exelon $4.00 - $4.10 (1) $0.50 - $0.55 $0.45 - $0.50 $3.10 - $3.15 (1) Adjusted (non-GAAP) Operating Earnings Guidance. Excludes the earnings effect of certain items as disclosed in the Appendix. Note: A = Actual; E = Estimate Narrowing 2009 operating earnings guidance to $4.00-$4.10/share (1) O&M and other Pension/OPEB Inflation Cost reduction initiatives Bad debt expense ComEd distribution revenue PECO gas revenue Weather Load Nuclear fuel costs Depreciation and amortization PECO CTC |
 16 ComEd Smart Grid/Smart Meter • Smart Meter (or Advanced Metering Infrastructure - AMI) Pilot – ICC approved on October 14, 2009 – 1-year pilot program for 131,000 smart meters and related programs (~$70 million in 2009-2010) – Recovery with regulated return for capital investment expected to begin in 2010 through
a rider • Federal Stimulus Funding – Request for $175 million in matching funds made on August 4, 2009 – Investment would occur through 2011 Projected Spend $ millions $350 $23 $78 $107 $139 Total $92 $6 -- $84 -- Transmission $78 Distribution Automation $23 Communication Support Systems $139 AMI & Customer Applications $258 $17 Distribution TOTAL Intelligent Substation Project Note: Totals may not add due to rounding. ComEd includes approximately $4 million
of unallocated contract expense that will be distributed to specific
projects upon finalization of scope. ComEd’s Smart Grid project expands
the AMI pilot and provides for regulated returns on our investments
|
 17 PECO Smart Grid/Smart Meter • PECO intends to invest up to $650 million in its Smart Grid/Smart Meter Infrastructure (1) – $550 million Advanced Metering Infrastructure over 10 – 15 years – $100 million for Smart Grid over 3 years subject to stimulus funding • Federal Stimulus Grant application for $200 million of matching funds filed August 6,
2009 – Amount and timing of spend will depend on approval of Federal Stimulus Grant and supplier RFPs • Smart Meter investment required by Act 129, which provides for recovery through
surcharge including a return on capital investment • Smart Grid investment to be recovered through transmission and distribution rates
($ millions pre-tax) 2010 2011 2012 Total Act 129 Smart Meter Deployment (over 10-15 years) 45 $ 125 $ 45 $ 215 $ Smart Grid Base Case 15 20 15 50 60 $ 145 $ 60 $ 265 $ ($ millions pre-tax) 2010 2011 2012 Total Act 129 Smart Meter Expanded Initial Deployment (600K meters by 2012) 40 $ 150 $ 100 $ 290 $ Smart Grid Stimulus Case 50 45 15 110 Total Stimulus Case 90 195 115 400 Stimulus Grant Request (45) (100) (55) (200) Total Expenditures net of Stimulus grant 45 $ 95 $ 60 $ 200 $ (1) Does not include $100 million for potential replacement of gas meters and
wind-down of legacy Automated Meter Reading system. (2) Amounts included
in base case assumptions for capital spend. (3) Assumes 100% of matching
funds requested by DOE. Data contained in this slide is rounded 2010-2012 Spend Without Federal Stimulus Grant (2) : 2010-2012 Spend With Federal Stimulus Grant (3) : |
 18 Illinois Power Agency RFP Procurement • On September 30, 2009, the IPA submitted an Updated Procurement Plan for the 2010/11 planning period • Similar to 2009, the Procurement Plan for the 2010/11 planning period includes the
procurement of monthly peak and off-peak standard wholesale block energy
products • The IPA’s Plan also calls for the procurement of 1,887,014 MWh of Renewable Energy
Credits NOTE: Chart is for illustrative purposes only. Data on this slide is rounded
Next RFP to be held in Spring 2010 Delivery Period Peak Off-Peak June 2010 - May 2011 5,390 4,538 June 2011 - May 2012 1,858 668 Volumes to be secured in 2010 IPA Procurement Event (GWh) 2009 RFP 2009 RFP 2010 RFP 2010 RFP 2011 RFP 2011 RFP 2012 RFP 2009 2010 2011 2012 Financial Swap Auction Contract |
 19 PECO Procurement Results PECO has completed two of the four procurements for the power needed to serve its
residential customers beginning in 2011 • On September 23, 2009, the PAPUC approved the bids from PECO’s second RFP
(1) See PECO Procurement website (http://www.pecoprocurement.com) for additional details
regarding PECO’s procurement plan and RFP results. (2) Wholesale prices; no Small/Medium Commercial products were procured in the June
RFP. Residential Sept RFP average price of $79.96/MWh (2) June RFP average price of $88.61/MWh (2) 49% of full requirements product procured 80 MW of block energy procured Small and Medium Commercial Sept RFP average blended price of $85.85/MWh (2) 24% of Small Commercial full requirements product procured 16% of Medium Commercial full requirements product procured 85% full requirements 15% full requirements spot Medium Commercial & Industrial (peak demand >100 kW but <= 500 kW) 100% full requirements spot Large Commercial & Industrial (peak demand >500 kW) 90% full requirements 10% full requirements spot 75% full requirements 20% block energy 5% energy only spot Products Small Commercial (peak demand <100 kW) Residential Customer Class PECO Procurement Plan (1) Total Procured (including June and September RFPs) Residential 23% of planned full requirements contracts (17 and 29-mo terms) 140 MW of baseload (24x7) block energy products (12, 24 and 60-mo duration) 40 MW of Jan-Feb 2011 on-peak block energy Small Commercial 36% of planned full requirements contracts (17 and 29-mo term) Medium Commercial & Industrial 42% of planned full requirements contracts (17-mo term) May 24, 2010 RFP |
 20 5.03 5.03 0.51 0.51 6.26 2.57 9.41 PECO Average Residential Electric Rates (1) Average of PECO’s residential rates. (2) Provided for illustration only. Represents 49% of PECO’s full requirements
residential procurement for 2011. (3) Average wholesale price for full requirements products. Full requirements product
includes load following energy, capacity, ancillary transmission services and Alternative Energy Portfolio Standard requirements. (4) Does not include energy efficiency or changes in distribution rates. 2011 2010 Energy / Capacity Competitive Transition Charge (CTC) Transmission Distribution 14.37¢ (1) Unit Rates (¢/kWh) Electric Restructuring Settlement ~4% (4) 14.95¢ (1) Assumptions Illustrative Rate Increase Based on Average PECO Residential Full Requirements Procurement Results (2) • 2011 illustrative residential rate based on Spring and Fall 2009 RFPs full requirements product prices • Actual 2011 default service residential rate will reflect associated full requirements costs, block energy costs, and spot market purchases, all of which will be acquired through multiple procurements • Rates will vary by customer class • Retail rate components include line losses and gross receipts taxes Spring 2009 $88.61 / MWH PECO Residential Procurement Results (3) Effect of Spring and Fall 2009 Procurements Fall 2009 $79.96 / MWH Wholesale Results |
 21 Estimated Build-Up of PECO Average Residential Full Requirements Price $91.60/MWh $28.50- $29.50 $50.50 - $51.50 Full Requirements Costs ($/MWh) Average Full
Requirements Retail Sales Price (1) Load Shape & Ancillary Services $7.50 Capacity $12.00 Transmission & Congestion $7.00 - $8.00 Renewable Energy Credits $1.00 Migration, Volumetric Risk & Other $1.00 ~$6.50 ~$5.50 Average Wholesale Energy Price $79.96 (2) 21 (1) As provided by Exelon Generation (2) On Oct 21, 2009 the Independent Evaluator (NERA) announced a wholesale winning bid average price of
$79.96/MWh for PECO’s Fall 2009 RFP (reflecting 17 & 29-month residential full requirements’ products with delivery beginning Jan 1, 2011).
|
 22 Q3 07 Q3 08 Q3 09 ComEd and PECO Accounts Receivable ComEd Accounts Receivable (1) Through the third quarter of 2009, both ComEd and PECO have experienced an improvement in accounts receivable aging Q3 07 Q3 08 Q3 09 PECO Accounts Receivable (1) % of AR $862M $710M $789M $782M $779M $714M (1) Accounts receivable amounts include unbilled receivables and are gross
of allowance for uncollectible accounts at ComEd and PECO and long-term receivables at PECO. >60 days 31-60 days 0-30 days Note: Data contained on this slide is rounded. |
 23 23 2009 Projected Sources and Uses of Cash (250) n/a (50) (200) Utility Growth CapEx (4) (925) (925) n/a n/a Nuclear Fuel (200) (200) n/a n/a Nuclear Uprates and Solar Project (1,400) Dividend (3) $ (in millions) Exelon (8) Beginning Cash Balance (1) $500 Cash Flow from Operations (1)(2) 1,125 1,000 3,400 5,600 CapEx (excluding Nuclear Fuel, Nuclear Uprates and Solar Project, Utility Growth CapEx) (675) (350) (925) (2,000) Net Financing (excluding Dividend): Planned Debt Issuances (5) 0 250 1,500 1,750 Planned Debt Retirements (6) 0 (750) (1,000) (2,250) Other (7) 50 250 50 (100) Ending Cash Balance (1) $725 Note: Data contained on this slide is rounded. (1) Excludes counterparty collateral activity. (2) Cash Flow from Operations primarily includes net cash flows provided by operating activities and net cash
flows used in investing activities other than capital expenditures. Cash Flow from Operations
reflects the $350M pre-tax discretionary pension contribution. Cash Flow from Operations for PECO and Exelon includes $500M for Competitive Transition Charges. (3) Assumes 2009 Dividend of $2.10 per share. Dividends are subject to
declaration by the Board of Directors. (4) Represents new business and smart grid/meter investment. (5) Excludes ComEd tax-exempt bonds that are backed by letters of credit (LOCs). ComEd reissued
$191M of tax exempt debt in May backed by LOCs. Excludes PECO’s Accounts Receivable
(A/R) Agreement with Bank of Tokyo. (6) Planned Debt Retirements at ComEd and Exelon Corporate are $17M and $500M, respectively. Includes
securitized debt at PECO and $307M repurchase of tax exempt debt at Exelon Generation.
(7) “Other” includes PECO Parent Receivable, proceeds from options and expected changes in
short-term debt. (8) Includes cash flow activity from Holding Company, eliminations, and other corporate entities.
|
 24 Sufficient Liquidity (1) Excludes previous commitment from Lehman Brothers Bank and excludes $66
million of bank commitments from Exelon’s Community and Minority Bank Credit Facility. (2) Available Capacity Under Facilities represents the unused bank commitments
under the borrower’s credit agreements net of outstanding letters of credit and facility draws. The amount of commercial paper outstanding does not reduce the available
capacity under the credit agreements. (3) Includes other corporate
entities. (35) -- -- (35) Outstanding Facility Draws (409) (154) (10) (241) Outstanding Letters of Credit $7,317 $4,834 $574 $952 Aggregate Bank Commitments (1) 6,873 4,680 564 676 Available Capacity Under Facilities (2) -- -- -- -- Outstanding Commercial Paper $6,873 $4,680 $564 $676 Available Capacity Less Outstanding Commercial Paper Exelon (3) ($ in Millions) Exelon has no commercial paper outstanding and its bank facilities are largely
untapped Available Capacity Under Bank Facilities as of October 15, 2009
|
 25 Projected 2009 Key Credit Measures BBB A- A- BBB- S&P Credit Ratings (3) BBB+ A BBB BBB+ Fitch Credit Ratings (3) A3 A2 Baa1 Baa1 Moody’s Credit Ratings (3) 4.5x 4.5x FFO / Interest ComEd: 23% 17% FFO / Debt 42% 49% Rating Agency Debt Ratio 3.4x 3.2x FFO / Interest PECO: 14% 12% FFO / Debt 48% 53% Rating Agency Debt Ratio 30% 50% Rating Agency Debt Ratio 125% 55% FFO / Debt 36.5x 12.5x FFO / Interest Exelon Generation: 49% 43% 8.7x Without PPA & Pension / OPEB (2) 60% Rating Agency Debt Ratio 28% FFO / Debt 6.8x FFO / Interest Exelon Consolidated: With PPA & Pension / OPEB (1) Notes: Exelon and PECO metrics exclude securitization debt. See following slide for FFO (Funds from Operations)/Interest, FFO/Debt and Adjusted Book Debt Ratio reconciliations to GAAP. (1) FFO/Debt metrics include the following standard adjustments: imputed debt and
interest related to purchased power agreements (PPA), unfunded pension and other postretirement benefits (OPEB) obligations, capital adequacy for energy trading, operating lease
obligations, and other off-balance sheet debt. Debt is imputed for estimated pension and OPEB obligations by operating company. (2) Excludes items listed in note (1) above. (3) Current senior unsecured ratings for Exelon and Exelon Generation and senior secured
ratings for ComEd and PECO as of October 15, 2009. On August 3, 2009, Moody’s upgraded ComEd’s senior secured credit rating to Baa1 from Baa2 due to a change in Moody’s rating methodology. |
 26 FFO Calculation and Ratios FFO Calculation = FFO - PECO Transition Bond Principal Paydown + Gain on Sale, Extraordinary Items and Other Non-Cash Items (3) + Change in Deferred Taxes + Depreciation, amortization (including nucl fuel amortization), AFUDC/Cap. Interest Add back non-cash items: Net Income Adjusted Interest FFO + Adjusted Interest = Adjusted Interest + 7% of Present Value (PV) of Operating Leases + Interest on imputed debt related to PV of Purchased Power Agreements (PPA), unfunded Pension and Other Postretirement Benefits (OPEB) obligations, and Capital Adequacy for Energy Trading (2) , as applicable - PECO Transition Bond Interest Expense Net Interest Expense (Before AFUDC & Cap. Interest) FFO Interest Coverage + Capital Adequacy for Energy Trading (2) FFO = Adjusted Debt + PV of Operating Leases + 100% of PV of Purchased Power Agreements (2) + Unfunded Pension and OPEB obligations (2) + A/R Financing Add off-balance sheet debt equivalents: - PECO Transition Bond Principal Balance + STD + LTD Debt: Adjusted Debt (1) FFO Debt Coverage Rating Agency Capitalization Rating Agency Debt Total Adjusted Capitalization Adjusted Book Debt = Total Rating Agency Capitalization + Off-balance sheet debt equivalents (2) Total Adjusted Capitalization = Rating Agency Debt + Off-balance sheet debt equivalents (2) Adjusted Book Debt = Total Adjusted Capitalization + Adjusted Book Debt + Preferred Securities of Subsidiaries + Total Shareholders' Equity Capitalization: = Adjusted Book Debt - Transition Bond Principal Balance + STD + LTD Debt: Debt to Total Cap (1) Uses current year-end adjusted debt balance. (2) Metrics are calculated in presentation unadjusted and adjusted for debt equivalents and
related interest for PPAs, unfunded Pension and OPEB obligations, and Capital Adequacy for Energy Trading. (3) Reflects depreciation adjustment for PPAs and decommissioning interest income and
contributions. |
 27 Q3 GAAP EPS Reconciliation (0.02) - - - (0.02) 2007 Illinois electric rate settlement (0.09) (0.04) - - (0.05) Costs associated with early debt retirements 0.05 - - - 0.05 Nuclear decommissioning obligation reduction (0.01) (0.01) - - - NRG acquisition costs 0.13 - - - 0.13 Unrealized gains related to nuclear decommissioning trust funds 0.12 - - - 0.12 Mark-to-market adjustments from economic hedging activities $1.14 $(0.06) $0.14 $0.07 $0.99 Q3 2009 GAAP Earnings (Loss) Per Share $0.96 $(0.01) $0.14 $0.07 $0.76 2009 Adjusted (non-GAAP) Operating Earnings (Loss) Per Share Exelon Other PECO ComEd ExGen Three Months Ended September 30, 2009 (0.04) - - - (0.04) 2007 Illinois electric rate settlement 0.02 - - - 0.02 Nuclear decommissioning obligation reduction $1.06 $(0.09) $0.14 $0.05 $0.96 Q3 2008 GAAP Earnings (Loss) Per Share $1.07 $(0.04) $0.14 $0.05 $0.92 2008 Adjusted (non-GAAP) Operating Earnings (Loss) Per Share 0.10 (0.05) - - 0.15 Mark-to-market adjustments from economic hedging activities (0.09) - - - (0.09) Unrealized losses related to nuclear decommissioning trust funds Exelon Other PECO ComEd ExGen Three Months Ended September 30, 2008 NOTE: All amounts shown are per Exelon share and represent contributions to
Exelon's EPS. Amounts may not add due to rounding. |
 28 YTD GAAP EPS Reconciliation NOTE: All amounts shown are per Exelon share and represent contributions to
Exelon's EPS. Amounts may not add due to rounding. (0.18) - - (0.01) (0.17) 2007 Illinois electric rate settlement 0.02 - - - 0.02 Nuclear decommissioning obligation reduction $3.06 $(0.07) $0.37 $0.16 $2.60 YTD 2008 GAAP Earnings (Loss) Per Share $3.13 $(0.07) $0.37 $0.17 $2.66 2008 Adjusted (non-GAAP) Operating Earnings (Loss) Per Share 0.27 - - - 0.27 Mark-to-market adjustments from economic hedging activities (0.18) - - - (0.18) Unrealized losses related to nuclear decommissioning trust funds Exelon Other PECO ComEd ExGen Nine Months Ended September 30, 2008 (0.08) - - - (0.08) 2007 Illinois electric rate settlement (0.09) (0.04) - - (0.05) Costs associated with early debt retirements (0.20) - - - (0.20) Impairment of certain generating assets (0.03) - - (0.02) (0.01) 2009 severance charges 0.05 - - - 0.05 Nuclear decommissioning obligation reduction (0.03) (0.03) - - - NRG acquisition costs 0.18 - - - 0.18 Unrealized gains related to nuclear decommissioning trust funds 0.12 - - - 0.12 Mark-to-market adjustments from economic hedging activities 0.10 (0.02) - 0.06 0.06 Non-cash remeasurement of income tax uncertainties and reassessment of state deferred income taxes $3.21 $(0.19) $0.42 $0.42 $2.57 YTD 2009 GAAP Earnings (Loss) Per Share $3.19 $(0.10) $0.42 $0.38 $2.50 2009 Adjusted (non-GAAP) Operating Earnings (Loss) Per Share Exelon Other PECO ComEd ExGen Nine Months Ended September 30, 2009 |
 29 2009 Earnings Outlook • Exelon’s 2009 adjusted (non-GAAP) operating earnings outlook excludes the earnings effects of the following: • Mark-to-market adjustments from economic hedging activities • Unrealized gains and losses from nuclear decommissioning trust fund investments
primarily related to the Clinton, Oyster Creek, and Three Mile Island nuclear plants (the former AmerGen Energy Company, LLC units) • Any significant impairments of assets, including goodwill • Any changes in decommissioning obligation estimates • Costs associated with the 2007 Illinois electric rate settlement agreement, including ComEd’s previously announced customer rate relief programs • Costs associated with ComEd’s 2007 settlement with the City of Chicago • Costs incurred for employee severance related to the cost reduction program announced
in June 2009 • Costs associated with early debt retirements • External costs associated with the terminated offer to acquire NRG Energy, Inc.
• Non-cash remeasurement of income tax uncertainties and reassessment of state
deferred income taxes • Other unusual items • Significant future changes to GAAP • Operating earnings guidance assumes normal weather for the remainder of the year |
 30 Important Information The following slides are intended to provide additional information regarding the hedging program at Exelon Generation and to serve as an aid for the purposes of modeling Exelon Generation’s gross margin (operating revenues less purchased power and fuel expense). The information on the following slides is not intended to represent earnings guidance or a forecast of future events. In fact, many of the factors that ultimately will determine Exelon
Generation’s actual gross margin are based upon highly variable market factors outside of our
control. The information on the following slides is as of September 30, 2009. Exelon plans
to update these hedging disclosures on a quarterly basis. Certain information on the following slides is based upon an internal simulation model that incorporates assumptions regarding future market conditions, including power and commodity prices, heat rates, and demand conditions, in addition to operating performance and dispatch characteristics of our generating fleet. Our simulation model and the assumptions therein are subject to change. For example, actual market conditions and the dispatch profile of our generation fleet in future periods will likely differ – and may differ
significantly – from the assumptions underlying the simulation results included in the
slides. In addition, the forward-looking information included in the following slides
will likely change over time due to continued refinement of our simulation model and changes in
our views on future market conditions. |
 31 31 Portfolio Management Objective Align Hedging Activities with Financial Commitments • Power Team utilizes several product types and channels to market • Wholesale and retail sales • Block products • Load-following products and load auctions • Put/call options • Exelon’s hedging program is designed to protect the long-term value of our generating fleet and maintain an investment-grade balance sheet • Hedge enough commodity risk to meet future cash requirements if prices drop • Consider: financing policy (credit rating objectives, capital structure, liquidity); spending (capital and O&M); shareholder value return policy • Consider market, credit, operational risk • Approach to managing volatility • Increase hedging as delivery approaches • Have enough supply to meet peak load • Purchase fossil fuels as power is sold • Choose hedging products based on generation portfolio – sell what we own • Heat rate options • Fuel products • Capacity • Renewable credits By design, our hedging program allows us to weather short-term, adverse market
conditions while positioning us to participate in long-term
upside potential |
 32 32 32 Percentage of Expected Generation Hedged • How many equivalent MW have been hedged at forward market prices; all hedge products used are converted to an equivalent average MW volume • Takes ALL hedges into account whether they are power sales or financial products Equivalent MWs Sold Expected Generation = • Our normal practice is to hedge commodity risk on a ratable basis over the three years leading to the spot market • Carry operational length into spot market to manage forced outage and
load-following risks • By using the appropriate product mix, expected generation hedged approaches the mid-90s percentile as the delivery period approaches • Participation in larger procurement events, such as utility auctions, and some
flexibility in the timing of hedging may mean the hedge program is not
strictly ratable from quarter to quarter Exelon Generation Hedging Program |
 33 33 33 2009 2010 2011 Estimated Open Gross Margin (millions) (1) $4,850 $5,850 $5,950 Open gross margin assumes all expected generation is sold at the Reference Prices listed below Reference Prices Henry Hub Natural Gas ($/MMBtu) NI-Hub ATC Energy Price ($/MWh) PJM-W ATC Energy Price ($/MWh) ERCOT North ATC Spark Spread ($/MWh) (2) $4.04 $28.06 $38.23 $(0.01) $6.21 $32.57 $48.40 $(1.51) $6.87 $34.36 $51.50 $(1.94) Exelon Generation Open Gross Margin and Reference Prices Based on September 30, 2009 market conditions (1) Gross margin is defined as operating revenues less fuel expense and purchased power expense, excluding the
impact of decommissioning and other incidental revenues. Open gross margin is estimated based
upon an internal model that is developed by dispatching our expected generation to current market power and fossil fuel prices. Open gross margin assumes there is no hedging in place other than fixed assumptions for capacity cleared in
the RPM auctions and uranium costs for nuclear power plants. Open gross margin contains
assumptions for other gross margin line items such as various ISO bill and ancillary revenues and costs and PPA capacity payments. The estimation of open gross margin incorporates management discretion and modeling assumptions that are
subject to change. (2) ERCOT North ATC spark spread using Houston Ship Channel Gas, 7,200 heat rate, $2.50 variable O&M.
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 34 34 34 2009 2010 2011 Expected Generation (GWh) (1) 168,900 166,800 164,900 Midwest 99,500 98,600 98,200 Mid-Atlantic 57,900 59,900 59,100 South 11,500 8,300 7,600 Percentage of Expected Generation Hedged (2) 98-100% 88-91% 63-66% Midwest 98-100 88-91 67-70 Mid-Atlantic 97-99 91-94 56-59 South 98-100 90-93 52-55 Effective Realized Energy Price ($/MWh) (3) Midwest $47.00 $46.50 $44.50 Mid-Atlantic $36.00 $33.75 $60.50 ERCOT North ATC Spark Spread $5.25 $3.00 $4.25 Generation Profile (1) Expected generation represents the amount of energy estimated to be generated or purchased through owned or
contracted for capacity. Expected generation is based upon a simulated dispatch model
that makes assumptions regarding future market conditions, which are calibrated to market quotes for power, fuel, load following products, and options. Expected generation assumes 10 refueling outages in 2009 and 2010 and 11 refueling
outages in 2011 at Exelon-operated nuclear plants and Salem. Expected generation
assumes capacity factors of 93.6%, 93.5% and 92.8% in 2009, 2010 and 2011 at Exelon-operated nuclear plants. These estimates of expected generation in 2010 and 2011 do not represent guidance or a forecast of future results as Exelon has not
completed its planning or optimization processes for those years. (2) Percent of expected generation hedged is the amount of equivalent sales divided by the expected
generation. Includes all hedging products, such as wholesale and retail sales of power,
options, and swaps. Uses expected value on options. (3) Effective realized energy price is representative of an all-in hedged price, on a per MWh basis, at
which expected generation has been hedged. It is developed by considering the energy
revenues and costs associated with our hedges and by considering the fossil fuel that has been purchased to lock in margin. It excludes uranium costs and RPM capacity revenue, but includes the mark-to-market value of capacity contracted at
prices other than RPM clearing prices including our load obligations. It can be compared with the reference prices used to calculate open gross margin in order to
determine the mark-to-market value of Exelon Generation's energy hedges. |
 35 35 35 Gross Margin Sensitivities with Existing Hedges (millions) (1) Henry Hub Natural Gas + $1/MMBtu - $1/MMBtu NI-Hub ATC Energy Price +$5/MWH -$5/MWH PJM-W ATC Energy Price +$5/MWH -$5/MWH Nuclear Capacity Factor +1% / -1% 2009 $3 $(2) $3 $(1) $4 $(2) +/-$10 2010 $45 $(40) $40 $(35) $30 $(25) +/-$50 2011 $265 $(225) $185 $(175) $165 $(160) +/-$50 (1) Based on September 2009 market conditions and hedged position. Gas price sensitivities
are based on an assumed gas-power relationship derived from an internal model that is updated periodically. Power prices sensitivities are derived by adjusting the power price assumption while
keeping all other prices inputs constant. Due to correlation of the various assumptions, the hedged gross margin impact calculated by aggregating individual sensitivities may not be equal to the hedged gross margin impact calculated when correlations between the various assumptions are also
considered. Exelon Generation Gross Margin Sensitivities (with Existing Hedges) |
 36 36 36 Exelon Generation Gross Margin Upside / Risk (with Existing Hedges) 95% case 5% case $6,700 $6,600 $6,100 $6,500 $6,000 $8,200 $5,000 $6,000 $7,000 $8,000 $9,000 $10,000 2009 2010 2011 Represents an approximate range of expected gross margin, taking into account hedges in place, between the
5th and 95th percentile confidence levels. Approximate gross margin ranges are based upon
an internal simulation model and are subject to change based upon market inputs, future transactions and potential modeling changes. These ranges of approximate gross margin in 2010 and 2011 do not represent earnings guidance or a forecast of future
results as Exelon has not completed its planning or optimization processes for those years.
The price distributions that generate this range are calibrated to market quotes for power, fuel, load following products, and options as of September 30, 2009. (1) |
 37 37 37 Midwest Mid-Atlantic ERCOT Step 1 Start with fleetwide open gross margin $4.85 billion Step 2 Determine the mark-to-market value of energy hedges 99,550GWh * 99% * ($47.00/MWh-$28.06/MWh) = $1.87 billion 57,900GWh * 98% * ($36.00/MWh-$38.23/MWh) = $(0.13 billion) 11,500GWh * 99% * ($5.25/MWh-($0.01)/MWh) = $0.06 billion Step 3 Estimate hedged gross margin by adding open gross margin to mark-to- market value of energy hedges Open gross margin: $4.85 billion MTM value of energy hedges: $1.87 billion + $(0.13 billion) + $0.06 billion Estimated hedged gross margin: $6.65 billion Illustrative Example of Modeling Exelon Generation 2009 Gross Margin (with Existing Hedges) |
 38 38 38 38 45 55 65 75 85 95 105 115 10/08 11/08 12/08 1/09 2/09 3/09 4/09 5/09 6/09 7/09 8/09 9/09 10/09 20 25 30 35 40 45 50 55 60 65 10/08 11/08 12/08 1/09 2/09 3/09 4/09 5/09 6/09 7/09 8/09 9/09 10/09 35 45 55 65 75 85 95 105 10/08 11/08 12/08 1/09 2/09 3/09 4/09 5/09 6/09 7/09 8/09 9/09 10/09 5 6 7 8 9 10 11 10/08 11/08 12/08 1/09 2/09 3/09 4/09 5/09 6/09 7/09 8/09 9/09 10/09 38 Market Price Snapshot Forward NYMEX Natural Gas PJM-West and Ni-Hub On-Peak Forward Prices PJM-West and Ni-Hub Wrap Forward Prices 2010 $6.04 2011 $6.82 Rolling 12 months, as of October 15, 2009. Source: OTC quotes and electronic trading
system. Quotes are daily. Forward NYMEX Coal 2010 $53.25 2011 $65.26 2010 Ni-Hub $43.06 2011 Ni-Hub $45.29 2011 PJM-West $63.88 2010 PJM-West $59.37 2010 Ni-Hub $24.40 2011 Ni-Hub $26.00 2011 PJM-West $42.28 2010 PJM-West $39.79 |
 39 39 39 39 4.5 5.5 6.5 7.5 8.5 9.5 10/08 11/08 12/08 1/09 2/09 3/09 4/09 5/09 6/09 7/09 8/09 9/09 10/09 8 8.2 8.4 8.6 8.8 9 9.2 9.4 9.6 9.8 10 10/08 11/08 12/08 1/09 2/09 3/09 4/09 5/09 6/09 7/09 8/09 9/09 10/09 35 40 45 50 55 60 65 70 75 80 85 10/08 11/08 12/08 1/09 2/09 3/09 4/09 5/09 6/09 7/09 8/09 9/09 10/09 5 6 7 8 9 10 11 10/08 11/08 12/08 1/09 2/09 3/09 4/09 5/09 6/09 7/09 8/09 9/09 10/09 39 Market Price Snapshot 2011 $8.66 2010 $8.65 2010 $50.68 2011 $57.42 2010 $5.86 2011 $6.63 Houston Ship Channel Natural Gas Forward Prices ERCOT North On-Peak Forward Prices ERCOT North On-Peak v. Houston Ship Channel Implied Heat Rate 2010 $5.91 2011 $7.10 ERCOT North On Peak Spark Spread Assumes a 7.2 Heat Rate, $1.50 O&M, and $.15 adder Rolling 12 months, as of October 15, 2009. Source: OTC quotes and electronic trading
system. Quotes are daily. |