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
January 26, 2011
Date of Report (Date of earliest event reported)
| Commission File Number |
Exact Name of Registrant as Specified in Its Charter; State of Incorporation; Address of Principal Executive Offices; and Telephone Number |
IRS Employer Identification Number | ||
| 1-16169 | EXELON CORPORATION | 23-2990190 | ||
| (a Pennsylvania corporation) 10 South Dearborn Street P.O. Box 805379 Chicago, Illinois 60680-5379 (312) 394-7398 |
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| 333-85496 | EXELON GENERATION COMPANY, LLC | 23-3064219 | ||
| (a Pennsylvania limited liability company) 300 Exelon Way Kennett Square, Pennsylvania 19348-2473 (610) 765-5959 |
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| 1-1839 | COMMONWEALTH EDISON COMPANY | 36-0938600 | ||
| (an Illinois corporation) 440 South LaSalle Street Chicago, Illinois 60605-1028 (312) 394-4321 |
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| 000-16844 | PECO ENERGY COMPANY | 23-0970240 | ||
| (a Pennsylvania corporation) P.O. Box 8699 2301 Market Street Philadelphia, Pennsylvania 19101-8699 (215) 841-4000 |
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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 January 26, 2011, Exelon Corporation (Exelon) announced via press release its results for the fourth quarter ended December 31, 2010. 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 fourth quarter 2010 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.
Exelon has scheduled the conference call for 11:00 AM ET (10:00 AM CT) on January 26, 2011. 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 34838808. 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 Investors page.)
Telephone replays will be available until February 9th. 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 34838808.
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 2009 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 2010 Quarterly Report on Form 10-Q in (a) Part II, Other Information, ITEM 1A. Risk Factors, (b) Part 1, Financial Information, ITEM 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations and (c) Part I, Financial Information, ITEM 1. Financial Statements: Note 13; 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, Chief Financial Officer and Treasurer |
| 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 |
January 26, 2011
EXHIBIT INDEX
| Exhibit No. |
Description | |
| 99.1 | Press release and earnings release attachments | |
| 99.2 | Earnings conference call presentation slides | |
Exhibit 99.1
| Contact: | Stacie Frank | FOR IMMEDIATE RELEASE | ||
| Investor Relations | ||||
| 312-394-3094 | ||||
| Kathleen Cantillon | ||||
| Corporate Communications | ||||
| 312-394-7417 | ||||
Exelon Announces Fourth Quarter and Full Year 2010 Results;
Introduces Guidance Range for Full Year 2011 Earnings
Company projects 2011 operating earnings of $3.90 to $4.20 per share.
CHICAGO (January 26, 2011) – Exelon Corporation (NYSE: EXC) announced fourth quarter and full year 2010 consolidated earnings as follows:
Exelon Consolidated Earnings (unaudited)
| Full Year | Fourth Quarter | |||||||||||||||
| 2010 | 2009 | 2010 | 2009 | |||||||||||||
| Adjusted (non-GAAP) Operating Results: |
||||||||||||||||
| Net Income ($ millions) |
$ | 2,689 | $ | 2,723 | $ | 631 | $ | 610 | ||||||||
| Diluted Earnings per Share |
$ | 4.06 | $ | 4.12 | $ | 0.96 | $ | 0.92 | ||||||||
| GAAP Results: |
||||||||||||||||
| Net Income ($ millions) |
$ | 2,563 | $ | 2,707 | $ | 524 | $ | 581 | ||||||||
| Diluted Earnings per Share |
$ | 3.87 | $ | 4.09 | $ | 0.79 | $ | 0.88 | ||||||||
“We delivered another exceptional year of financial and operating performance in 2010,” said John W. Rowe, chairman and chief executive officer. “We accomplished this with a keen focus on controlling operating and maintenance expenses across our businesses. At the same time, Exelon Generation attained its eighth consecutive year of nuclear fleet capacity factors that exceeded 93 percent, and ComEd and PECO demonstrated strong service reliability despite severe storms.”
Rowe added, “In 2011, Pennsylvania has fully transitioned to a competitive energy market, and along with our continued diligent focus on cost control and financial discipline, we are introducing full year operating earnings guidance of $3.90 to $4.20 per share.”
Fourth Quarter Operating Results
As shown in the table above, Exelon’s adjusted (non-GAAP) operating earnings increased to $0.96 per share in the fourth quarter of 2010 from $0.92 per share in the fourth quarter of 2009, primarily due to:
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| • | The impact at Exelon Generation Company, LLC (Generation) of favorable capacity pricing related to the Reliability Pricing Model (RPM) for the PJM Interconnection, LLC (PJM) market; |
| • | Increased nuclear output at Generation primarily reflecting the effect of fewer nuclear outage days in 2010; and |
| • | Decreased scheduled competitive transition charge (CTC) amortization expense at PECO Energy Company (PECO). |
Higher fourth quarter 2010 earnings were partially offset by:
| • | Unfavorable market/portfolio conditions and higher nuclear fuel costs at Generation; and |
| • | Increased depreciation expense across the operating companies largely due to ongoing capital expenditures. |
Adjusted (non-GAAP) operating earnings for the fourth quarter of 2010 do not include the following items (after tax) that were included in reported GAAP earnings:
| (in millions) | (per diluted share) | |||||||
| Mark-to-market losses primarily from Generation’s economic hedging activities |
$ | (113 | ) | $ | (0.17 | ) | ||
| Unrealized gains related to nuclear decommissioning trust (NDT) fund investments to the extent not offset by contractual accounting |
$ | 26 | $ | 0.04 | ||||
| Costs associated with the planned retirement of certain Generation fossil generating units |
$ | (17 | ) | $ | (0.03 | ) | ||
| Decrease in costs related to adjustments to asset retirement obligations of Commonwealth Edison Company (ComEd) and PECO |
$ | 7 | $ | 0.01 | ||||
| External costs related to Exelon’s acquisition of John Deere Renewables, LLC (now known as Exelon Wind) |
$ | (6 | ) | $ | (0.01 | ) | ||
| Costs associated with the 2007 Illinois electric rate settlement agreement |
$ | (4 | ) | $ | (0.01 | ) | ||
Adjusted (non-GAAP) operating earnings for the fourth quarter of 2009 did not include the following items (after tax) that were included in reported GAAP earnings:
| (in millions) | (per diluted share) | |||||||
| Costs associated with the planned retirement of certain Generation fossil generating units |
$ | (34 | ) | $ | (0.05 | ) | ||
| Mark-to-market gains primarily from Generation’s economic hedging activities |
$ | 26 | $ | 0.04 | ||||
| Costs associated with the 2007 Illinois electric rate settlement agreement |
$ | (15 | ) | $ | (0.02 | ) | ||
| Costs associated with early debt retirement |
$ | (15 | ) | $ | (0.02 | ) | ||
| Unrealized gains related to NDT fund investments |
$ | 14 | $ | 0.02 | ||||
| Charge associated with ComEd’s 2007 settlement agreement with the City of Chicago |
$ | (5 | ) | $ | (0.01 | ) | ||
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2011 Earnings Outlook
Exelon introduced a guidance range for 2011 adjusted (non-GAAP) operating earnings of $3.90 to $4.20 per share. Operating earnings guidance is based on the assumption of normal weather.
The outlook for 2011 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 to the extent not offset by contractual accounting as described in the notes to the consolidated financial statements |
| • | Significant impairments of assets, including goodwill |
| • | Changes in decommissioning obligation estimates |
| • | Costs associated with ComEd’s 2007 settlement with the City of Chicago |
| • | Financial impacts associated with the planned retirement of fossil generating units |
| • | Other unusual items |
| • | Significant changes to GAAP |
Fourth Quarter and Recent Highlights
| • | Oyster Creek Nuclear Station Retirement: On December 8, 2010, Exelon announced that the company will operate the Oyster Creek Generating Station in New Jersey until 2019, after which the plant will retire. The 625-megawatt (MW) nuclear plant is federally licensed to operate until 2029. Oyster Creek faces a unique set of adverse economic factors and changing environmental regulations that make ending operations in 2019 the best option. Potential additional environmental compliance costs based on evolving water cooling regulatory requirements at both the federal and state government levels created significant regulatory and economic uncertainty. Due to Exelon’s decision to retire the plant early, the New Jersey Department of Environmental Protection will not require the company to install cooling towers at Oyster Creek. |
| • | John Deere Renewables (JDR) Acquisition: On December 9, 2010, Exelon completed its previously announced acquisition of JDR, a leading operator and developer of wind power, adding 735 MW of clean, renewable energy to Exelon’s generation portfolio. The acquisition of JDR marked Exelon’s entry into owning and operating wind projects. The 36 wind projects in eight states are now called Exelon Wind, a division of Exelon Power. The acquisition provides incremental earnings starting in 2012 and cash flows starting in 2013 and is a key part of Exelon 2020, the company’s business strategy to eliminate the equivalent of its 2001 carbon footprint by 2020. Exelon is now halfway to its goal and remains the least carbon-intensive of the large U.S. electric utilities. Approximately 75 percent of the Exelon Wind operating portfolio is already sold under long-term power purchase arrangements. In addition, Exelon has the opportunity to pursue approximately 1,400 MW of new wind projects that are in various stages of development, including 230 MW in advanced stages of development. |
| • | Nuclear Operations: Generation’s nuclear fleet, including its owned output from the Salem Generating Station, produced 35,115 gigawatt-hours (GWh) in the fourth quarter of 2010, compared with 33,609 GWh in the fourth quarter of 2009. The Exelon-operated nuclear plants achieved a 93.1 percent capacity factor for the fourth quarter of 2010 compared with 89.8 percent for the fourth quarter of 2009. The Exelon-operated nuclear plants completed four |
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| scheduled refueling outages in the fourth quarter of 2010, compared with completing four and beginning a fifth scheduled refueling outage in the fourth quarter of 2009. Three Mile Island (TMI) Unit 1 was shut down from late October 2009 for an extended refueling outage which included the replacement of steam generators. The steam generator replacement increased the number of refueling outage days in the fourth quarter of 2009. As a result, the number of refueling outage days totaled 97 in the fourth quarter of 2010 versus 136 days in the fourth quarter of 2009. The number of non-refueling outage days at the Exelon-operated plants totaled 18 days in the fourth quarter of 2010 compared with 23 days in the fourth quarter of 2009. |
For the full year 2010, the Exelon-operated nuclear plants achieved an average capacity factor of 93.9 percent, as compared with 93.6 percent for 2009. The average annual capacity factor for the Exelon-operated plants during the five years ended 2010 was 94.0 percent.
| • | Fossil and Hydro Operations: The equivalent demand forced outage rate for Generation’s fossil fleet was 4.6 percent in the fourth quarter of 2010, compared with 12.9 percent in the fourth quarter of 2009. The improvement was largely due to the impact of extended maintenance outages in 2009. The equivalent availability factor for the hydroelectric facilities was 99.8 percent in the fourth quarter of 2010, compared with 99.6 percent in the fourth quarter of 2009. |
| • | 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 December 31, 2010 is 90 to 93 percent for 2011, 67 to 70 percent for 2012 and 32 to 35 percent for 2013. The primary objectives of Exelon’s hedging program are 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 Electric Distribution Rate Case: On June 30, 2010, ComEd filed a rate increase request with the Illinois Commerce Commission (ICC) to allow the utility to continue modernizing its electric delivery system and recover the cost of substantial investments made since the last rate filing in 2007. In testimony submitted on January 3, 2011, ComEd revised its requested revenue increase to $326 million, reflecting certain adjustments made subsequent to its original request of $396 million. The ICC will determine any increase in rates after an 11-month proceeding with input from all stakeholders. The ICC is expected to issue its decision in late May 2011. |
| • | PECO Electric and Gas Distribution Rate Cases: On December 16, 2010, the Pennsylvania Public Utility Commission (PAPUC) approved PECO’s settlements with all interested parties regarding the increase in electric and natural gas distribution rates for customers, which became effective on January 1, 2011. The PAPUC approved an increase of $20 million in annual natural gas distribution revenue, which is approximately 46 percent of the $44 million originally requested, and a $225 million increase in annual electric distribution revenue, which is approximately 71 percent of the $316 million originally requested. Reflecting this and the results of the company’s four competitive electric supply procurements, residential electric customer bills will increase on average about 5 percent, or about $5 a month, |
beginning in
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| January 2011. Overall bills for PECO residential natural gas customers will increase on average about 1 percent, or about $1 a month. |
| • | Pension Plan Funding: As a result of accelerated cash benefits associated with recent Federal tax legislation, on January 3, 2011, Exelon announced that its board of directors had authorized contributions to the Exelon pension plans in the first quarter of 2011 totaling $2.1 billion. This amount includes contributions that Exelon was previously expected to make in 2011. Exelon expects to fund the contributions with $500 million from cash from operations, $850 million from the accelerated cash tax benefits, and $750 million from the tax benefits of making the pension contributions. Exelon expects that the pension funded status will increase from 71 percent at December 31, 2010, to 89 percent projected at December 31, 2011, subject to actual 2011 asset returns and final actuarial valuations. |
| • | Financing Activities: On January 18, 2011, ComEd issued $600 million of 1.625 percent first mortgage bonds due 2014. The net proceeds of the bonds will be used as an interim source of liquidity for the contribution in the first quarter to the pension plans in which ComEd participates. ComEd anticipates receiving tax refunds as a result of both the pension contribution and the recent Federal tax legislation. As a result, the immediate use of the net proceeds to fund the planned contribution will allow those future cash receipts to be available to fund capital investment and for general corporate purposes. |
On October 25, 2010, Exelon announced that it had entered into new credit agreements totaling $94 million with 29 minority and community banks located in the regions the company serves. The lead arranger banks for the credit agreements are Seaway Bank and Trust Company in Chicago, Riverside Community Bank in Rockford, Ill., and United Bank of Philadelphia. The new credit agreements replace a 2009 arrangement for $67 million. Exelon’s minority and community banking program – the only one of its kind in the energy industry – aims to increase the company’s business with local and diverse banks in its key markets.
OPERATING COMPANY RESULTS
Generation consists of owned and contracted electric generating facilities, wholesale energy marketing operations and competitive retail sales operations.
Fourth quarter 2010 net income was $424 million compared with $425 million in the fourth quarter of 2009. Fourth quarter 2010 net income included (all after tax) mark-to-market losses of $113 million from economic hedging activities, unrealized gains of $26 million related to NDT fund investments, costs of $17 million associated with the planned retirement of certain fossil generating units, a charge of $6 million for external costs associated with the acquisition of JDR and a charge of $4 million for costs associated with the 2007 Illinois electric rate settlement. Fourth quarter 2009 net income included (all after-tax) costs of $34 million associated with the retirement of the fossil generating units, mark-to-market gains of $26 million from economic hedging activities before the elimination of intercompany transactions, unrealized gains of $14 million related to NDT fund investments, costs of $13 million associated with the 2007 Illinois electric rate settlement and costs of $9 million associated with early debt retirements. Excluding the effects of these items, Generation’s net income in the fourth quarter of 2010 increased $97 million compared with the same quarter in 2009 primarily due to:
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| • | The impact on energy gross margin of higher energy prices under the power purchase agreement with PECO, favorable capacity pricing related to RPM and increased nuclear output largely reflecting fewer outage days. |
The increase in net income was partially offset by:
| • | The impact on energy gross margin of unfavorable market/portfolio conditions and higher nuclear fuel costs; and |
| • | Increased depreciation expense. |
Generation’s average realized margin on all electric sales, including sales to affiliates and excluding trading activity, was $41.45 per MWh in the fourth quarter of 2010 compared with $38.36 per MWh in the fourth quarter of 2009.
ComEd consists of the electricity transmission and distribution operations in northern Illinois.
ComEd recorded net income of $91 million in the fourth quarter of 2010, compared with net income of $98 million in the fourth quarter of 2009. Fourth quarter net income in 2010 included an after-tax decrease in costs of $6 million associated with an adjustment to ComEd’s asset retirement obligation. Fourth quarter net income in 2009 included after-tax costs of $5 million for the City of Chicago settlement agreement and after-tax costs of $2 million associated with the 2007 Illinois electric rate settlement. Excluding the effects of these items, ComEd’s net income in the fourth quarter of 2010 was down $20 million from the same quarter in 2009 primarily reflecting:
| • | The effect of the September 2010 Illinois Appellate Court ruling; |
| • | Increased operating and maintenance expense; and |
| • | Lower load, partially offset by the effects of favorable weather conditions. |
The decrease in net income was partially offset by lower uncollectible accounts expense.
In the fourth quarter of 2010, heating degree-days in the ComEd service territory were up 1.2 percent relative to the same period in 2009 and were 0.6 percent above normal. ComEd’s total retail electric deliveries increased by 0.6 percent quarter over quarter, primarily due to gains in deliveries to large commercial and industrial customers.
Weather-normalized retail electric deliveries decreased by 1.2 percent from the fourth quarter of 2009, primarily reflecting a decrease in deliveries to residential customers. For ComEd, weather had a favorable after-tax effect of $4 million on fourth quarter 2010 earnings relative to 2009 and a favorable after-tax effect of $1 million relative to normal weather that is incorporated in Exelon’s 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 fourth quarter of 2010 was $21 million, down from $78 million in the fourth quarter of 2009. Fourth quarter net income in 2010 included an after-tax decrease in costs of $1 million associated with an adjustment to PECO’s asset retirement obligation. Excluding the effect of this item,
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PECO’s net income in the fourth quarter of 2010 was down $58 million from the same quarter in 2009 primarily reflecting:
| • | Decreased CTC revenue, as stranded costs were substantially recovered as of the end of the third quarter 2010, resulting in higher energy prices paid to Generation under the power purchase agreement; and |
| • | Increased operating and maintenance expense, primarily reflecting higher contracting and employee benefits expenses. |
The decrease in net income was partially offset by:
| • | Lower CTC amortization expense as scheduled in accordance with PECO’s 1998 Restructuring Settlement with the PAPUC; |
| • | The effects of favorable weather conditions; and |
| • | Lower interest expense on long-term debt. |
In the fourth quarter of 2010, heating degree-days in the PECO service territory were up 7.6 percent from 2009 and were 3.2 percent above normal. Total retail electric deliveries were up 1.4 percent from last year, reflecting an increase in deliveries to residential and large commercial and industrial customers. On the retail gas side, deliveries in the fourth quarter of 2010 were up 11.7 percent from the fourth quarter of 2009, primarily driven by the effects of colder weather conditions.
Weather-normalized retail electric deliveries were flat to the fourth quarter of 2009, reflecting a decline in residential and small commercial and industrial deliveries, offset by an increase in large commercial and industrial deliveries. For PECO, weather had a favorable after-tax effect of $6 million on fourth quarter 2010 earnings relative to 2009 and a favorable after-tax effect of $2 million relative to normal weather that is incorporated in Exelon’s 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-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 reconciliations on pages 7 and 8, are posted on Exelon’s Web site: www.exeloncorp.com and have been furnished to the Securities and Exchange Commission on Form 8-K on January 26, 2011.
Conference call information: Exelon has scheduled a conference call for 11:00 AM ET (10:00 AM CT) on January 26, 2011. 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 34838808. 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 Investors page.)
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Telephone replays will be available until February 9. 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 34838808.
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 2009 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 2010 Quarterly Report on Form 10-Q in (a) Part II, Other Information, ITEM 1A. Risk Factors, (b) Part 1, Financial Information, ITEM 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations and (c) Part I, Financial Information, ITEM 1. Financial Statements: Note 13 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.
###
Exelon Corporation is one of the nation’s largest electric utilities with more than $18 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 northern Illinois and southeastern Pennsylvania and natural gas to approximately 486,000 customers in the Philadelphia area. Exelon is headquartered in Chicago and trades on the NYSE under the ticker EXC.
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Earnings Release Attachments
Table of Contents
| Consolidating Statements of Operations - Three Months Ended December 31, 2010 and 2009 |
1 | |||
| Consolidating Statements of Operations - Twelve Months Ended December 31, 2010 and 2009 |
2 | |||
| Business Segment Comparative Statements of Operations - Generation and ComEd - Three and Twelve Months Ended December 31, 2010 and 2009 |
3 | |||
| Business Segment Comparative Statements of Operations - PECO and Other - Three and Twelve Months Ended December 31, 2010 and 2009 |
4 | |||
| Consolidated Balance Sheets - December 31, 2010 and December 31, 2009 |
5 | |||
| Consolidated Statements of Cash Flows - Twelve Months Ended December 31, 2010 and 2009 |
6 | |||
| Reconciliation of Adjusted (non-GAAP) Operating Earnings to GAAP Consolidated Statements of Operations - Exelon - Three Months Ended December 31, 2010 and 2009 |
7 | |||
| Reconciliation of Adjusted (non-GAAP) Operating Earnings to GAAP Consolidated Statements of Operations - Exelon - Twelve Months Ended December 31, 2010 and 2009 |
8 | |||
| Reconciliation of Adjusted (non-GAAP) Operating Earnings to GAAP Earnings By Business Segment - Three Months Ended December 31, 2010 and 2009 |
9 | |||
| Reconciliation of Adjusted (non-GAAP) Operating Earnings to GAAP Earnings By Business Segment - Twelve Months Ended December 31, 2010 and 2009 |
10 | |||
| Reconciliation of Adjusted (non-GAAP) Operating Earnings to GAAP Consolidated Statements of Operations - Generation - Three and Twelve Months Ended December 31, 2010 and 2009 |
11 | |||
| Reconciliation of Adjusted (non-GAAP) Operating Earnings to GAAP Consolidated Statements of Operations - ComEd - Three and Twelve Months Ended December 31, 2010 and 2009 |
12 | |||
| Reconciliation of Adjusted (non-GAAP) Operating Earnings to GAAP Consolidated Statements of Operations - PECO - Three and Twelve Months Ended December 31, 2010 and 2009 |
13 | |||
| Reconciliation of Adjusted (non-GAAP) Operating Earnings to GAAP Consolidated Statements of Operations - Other - Three and Twelve Months Ended December 31, 2010 and 2009 |
14 | |||
| Exelon Generation Statistics - Three Months Ended December 31, 2010, September 30, 2010, June 30, 2010, March 31, 2010 and December 31, 2009 |
15 | |||
| Exelon Generation Statistics - Twelve Months Ended December 31, 2010 and 2009 |
16 | |||
| ComEd Statistics - Three and Twelve Months Ended December 31, 2010 and 2009 |
17 | |||
| PECO Statistics - Three and Twelve Months Ended December 31, 2010 and 2009 |
18 | |||
EXELON CORPORATION
Consolidating Statements of Operations
(unaudited)
(in millions)
| Three Months Ended December 31, 2010 | ||||||||||||||||||||
| Generation | ComEd | PECO | Other | Exelon Consolidated | ||||||||||||||||
| Operating revenues |
$ | 2,596 | $ | 1,372 | $ | 1,299 | $ | (773 | ) | $ | 4,494 | |||||||||
| Operating expenses |
||||||||||||||||||||
| Purchased power |
602 | 671 | 652 | (773 | ) | 1,152 | ||||||||||||||
| Fuel |
418 | — | 123 | — | 541 | |||||||||||||||
| Operating and maintenance |
731 | 247 | 172 | 10 | 1,160 | |||||||||||||||
| Operating and maintenance for regulatory required programs (a) |
— | 27 | 17 | — | 44 | |||||||||||||||
| Depreciation and amortization |
129 | 130 | 201 | 5 | 465 | |||||||||||||||
| Taxes other than income |
56 | 68 | 64 | 5 | 193 | |||||||||||||||
| Total operating expenses |
1,936 | 1,143 | 1,229 | (753 | ) | 3,555 | ||||||||||||||
| Operating income (loss) |
660 | 229 | 70 | (20 | ) | 939 | ||||||||||||||
| Other income and deductions |
||||||||||||||||||||
| Interest expense |
(44 | ) | (86 | ) | (34 | ) | (19 | ) | (183 | ) | ||||||||||
| Other, net |
118 | 10 | 2 | 5 | 135 | |||||||||||||||
| Total other income and deductions |
74 | (76 | ) | (32 | ) | (14 | ) | (48 | ) | |||||||||||
| Income (loss) before income taxes |
734 | 153 | 38 | (34 | ) | 891 | ||||||||||||||
| Income taxes |
310 | 62 | 17 | (22 | ) | 367 | ||||||||||||||
| Net income (loss) |
$ | 424 | $ | 91 | $ | 21 | $ | (12 | ) | $ | 524 | |||||||||
| Three Months Ended December 31, 2009 | ||||||||||||||||||||
| Generation | ComEd | PECO | Other | Exelon Consolidated | ||||||||||||||||
| Operating revenues |
$ | 2,278 | $ | 1,357 | $ | 1,266 | $ | (785 | ) | $ | 4,116 | |||||||||
| Operating expenses |
||||||||||||||||||||
| Purchased power |
375 | 692 | 532 | (784 | ) | 815 | ||||||||||||||
| Fuel |
300 | — | 126 | (1 | ) | 425 | ||||||||||||||
| Operating and maintenance |
727 | 232 | 159 | 2 | 1,120 | |||||||||||||||
| Operating and maintenance for regulatory required programs (a) |
— | 19 | — | — | 19 | |||||||||||||||
| Depreciation and amortization |
110 | 123 | 225 | 16 | 474 | |||||||||||||||
| Taxes other than income |
55 | 67 | 64 | 1 | 187 | |||||||||||||||
| Total operating expenses |
1,567 | 1,133 | 1,106 | (766 | ) | 3,040 | ||||||||||||||
| Operating income (loss) |
711 | 224 | 160 | (19 | ) | 1,076 | ||||||||||||||
| Other income and deductions |
||||||||||||||||||||
| Interest expense |
(36 | ) | (78 | ) | (42 | ) | (20 | ) | (176 | ) | ||||||||||
| Loss in equity method investments |
— | — | (5 | ) | (1 | ) | (6 | ) | ||||||||||||
| Other, net |
50 | 11 | 5 | (6 | ) | 60 | ||||||||||||||
| Total other income and deductions |
14 | (67 | ) | (42 | ) | (27 | ) | (122 | ) | |||||||||||
| Income (loss) before income taxes |
725 | 157 | 118 | (46 | ) | 954 | ||||||||||||||
| Income taxes |
300 | 59 | 40 | (26 | ) | 373 | ||||||||||||||
| Net income (loss) |
$ | 425 | $ | 98 | $ | 78 | $ | (20 | ) | $ | 581 | |||||||||
| (a) | Includes amounts for various legislative and/or regulatory programs that are recoverable from customers on a full and current basis through a rider. An equal and offsetting amount has been reflected in operating revenues. |
1
EXELON CORPORATION
Consolidating Statements of Operations
(unaudited)
(in millions)
| Twelve Months Ended December 31, 2010 | ||||||||||||||||||||
| Generation | ComEd | PECO | Other | Exelon Consolidated | ||||||||||||||||
| Operating revenues |
$ | 10,025 | $ | 6,204 | $ | 5,519 | $ | (3,104 | ) | $ | 18,644 | |||||||||
| Operating expenses |
||||||||||||||||||||
| Purchased power |
1,853 | 3,307 | 2,361 | (3,096 | ) | 4,425 | ||||||||||||||
| Fuel |
1,610 | — | 401 | (1 | ) | 2,010 | ||||||||||||||
| Operating and maintenance |
2,812 | 975 | 680 | (14 | ) | 4,453 | ||||||||||||||
| Operating and maintenance for regulatory required programs (a) |
— | 94 | 53 | — | 147 | |||||||||||||||
| Depreciation and amortization |
474 | 516 | 1,060 | 25 | 2,075 | |||||||||||||||
| Taxes other than income |
230 | 256 | 303 | 19 | 808 | |||||||||||||||
| Total operating expenses |
6,979 | 5,148 | 4,858 | (3,067 | ) | 13,918 | ||||||||||||||
| Operating income (loss) |
3,046 | 1,056 | 661 | (37 | ) | 4,726 | ||||||||||||||
| Other income and deductions |
||||||||||||||||||||
| Interest expense |
(153 | ) | (386 | ) | (193 | ) | (85 | ) | (817 | ) | ||||||||||
| Other, net |
257 | 24 | 8 | 23 | 312 | |||||||||||||||
| Total other income and deductions |
104 | (362 | ) | (185 | ) | (62 | ) | (505 | ) | |||||||||||
| Income (loss) before income taxes |
3,150 | 694 | 476 | (99 | ) | 4,221 | ||||||||||||||
| Income taxes |
1,178 | 357 | 152 | (29 | ) | 1,658 | ||||||||||||||
| Net income (loss) |
$ | 1,972 | $ | 337 | $ | 324 | $ | (70 | ) | $ | 2,563 | |||||||||
| Twelve Months Ended December 31, 2009 | ||||||||||||||||||||
| Generation | ComEd | PECO | Other | Exelon Consolidated | ||||||||||||||||
| Operating revenues |
$ | 9,703 | $ | 5,774 | $ | 5,311 | $ | (3,470 | ) | $ | 17,318 | |||||||||
| Operating expenses |
||||||||||||||||||||
| Purchased power |
1,338 | 3,065 | 2,274 | (3,462 | ) | 3,215 | ||||||||||||||
| Fuel |
1,594 | — | 472 | — | 2,066 | |||||||||||||||
| Operating and maintenance |
2,938 | 1,028 | 640 | 6 | 4,612 | |||||||||||||||
| Operating and maintenance for regulatory required programs (a) |
— | 63 | — | — | 63 | |||||||||||||||
| Depreciation and amortization |
333 | 494 | 952 | 55 | 1,834 | |||||||||||||||
| Taxes other than income |
205 | 281 | 276 | 16 | 778 | |||||||||||||||
| Total operating expenses |
6,408 | 4,931 | 4,614 | (3,385 | ) | 12,568 | ||||||||||||||
| Operating income (loss) |
3,295 | 843 | 697 | (85 | ) | 4,750 | ||||||||||||||
| Other income and deductions |
||||||||||||||||||||
| Interest expense |
(113 | ) | (319 | ) | (187 | ) | (112 | ) | (731 | ) | ||||||||||
| Loss in equity method investments |
(3 | ) | — | (24 | ) | — | (27 | ) | ||||||||||||
| Other, net |
376 | 79 | 13 | (41 | ) | 427 | ||||||||||||||
| Total other income and deductions |
260 | (240 | ) | (198 | ) | (153 | ) | (331 | ) | |||||||||||
| Income (loss) before income taxes |
3,555 | 603 | 499 | (238 | ) | 4,419 | ||||||||||||||
| Income taxes |
1,433 | 229 | 146 | (96 | ) | 1,712 | ||||||||||||||
| Net income (loss) |
$ | 2,122 | $ | 374 | $ | 353 | $ | (142 | ) | $ | 2,707 | |||||||||
| (a) | Includes amounts for various legislative and/or regulatory programs that are recoverable from customers on a full and current basis through a rider. An equal and offsetting amount has been reflected in operating revenues. |
2
EXELON CORPORATION
Business Segment Comparative Statements of Operations
(unaudited)
(in millions)
| Generation | ||||||||||||||||||||||||
| Three Months Ended December 31, | Twelve Months Ended December 31, | |||||||||||||||||||||||
| 2010 | 2009 | Variance | 2010 | 2009 | Variance | |||||||||||||||||||
| Operating revenues |
$ | 2,596 | $ | 2,278 | $ | 318 | $ | 10,025 | $ | 9,703 | $ | 322 | ||||||||||||
| Operating expenses |
||||||||||||||||||||||||
| Purchased power |
602 | 375 | 227 | 1,853 | 1,338 | 515 | ||||||||||||||||||
| Fuel |
418 | 300 | 118 | 1,610 | 1,594 | 16 | ||||||||||||||||||
| Operating and maintenance |
731 | 727 | 4 | 2,812 | 2,938 | (126 | ) | |||||||||||||||||
| Depreciation and amortization |
129 | 110 | 19 | 474 | 333 | 141 | ||||||||||||||||||
| Taxes other than income |
56 | 55 | 1 | 230 | 205 | 25 | ||||||||||||||||||
| Total operating expenses |
1,936 | 1,567 | 369 | 6,979 | 6,408 | 571 | ||||||||||||||||||
| Operating income |
660 | 711 | (51 | ) | 3,046 | 3,295 | (249 | ) | ||||||||||||||||
| Other income and deductions |
||||||||||||||||||||||||
| Interest expense |
(44 | ) | (36 | ) | (8 | ) | (153 | ) | (113 | ) | (40 | ) | ||||||||||||
| Loss in equity method investments |
— | — | — | — | (3 | ) | 3 | |||||||||||||||||
| Other, net |
118 | 50 | 68 | 257 | 376 | (119 | ) | |||||||||||||||||
| Total other income and deductions |
74 | 14 | 60 | 104 | 260 | (156 | ) | |||||||||||||||||
| Income before income taxes |
734 | 725 | 9 | 3,150 | 3,555 | (405 | ) | |||||||||||||||||
| Income taxes |
310 | 300 | 10 | 1,178 | 1,433 | (255 | ) | |||||||||||||||||
| Net income |
$ | 424 | $ | 425 | $ | (1 | ) | $ | 1,972 | $ | 2,122 | $ | (150 | ) | ||||||||||
| ComEd | ||||||||||||||||||||||||
| Three Months Ended December 31, | Twelve Months Ended December 31, | |||||||||||||||||||||||
| 2010 | 2009 | Variance | 2010 | 2009 | Variance | |||||||||||||||||||
| Operating revenues |
$ | 1,372 | $ | 1,357 | $ | 15 | $ | 6,204 | $ | 5,774 | $ | 430 | ||||||||||||
| Operating expenses |
||||||||||||||||||||||||
| Purchased power |
671 | 692 | (21 | ) | 3,307 | 3,065 | 242 | |||||||||||||||||
| Operating and maintenance |
247 | 232 | 15 | 975 | 1,028 | (53 | ) | |||||||||||||||||
| Operating and maintenance for regulatory required programs (a) |
27 | 19 | 8 | 94 | 63 | 31 | ||||||||||||||||||
| Depreciation and amortization |
130 | 123 | 7 | 516 | 494 | 22 | ||||||||||||||||||
| Taxes other than income |
68 | 67 | 1 | 256 | 281 | (25 | ) | |||||||||||||||||
| Total operating expenses |
1,143 | 1,133 | 10 | 5,148 | 4,931 | 217 | ||||||||||||||||||
| Operating income |
229 | 224 | 5 | 1,056 | 843 | 213 | ||||||||||||||||||
| Other income and deductions |
||||||||||||||||||||||||
| Interest expense |
(86 | ) | (78 | ) | (8 | ) | (386 | ) | (319 | ) | (67 | ) | ||||||||||||
| Other, net |
10 | 11 | (1 | ) | 24 | 79 | (55 | ) | ||||||||||||||||
| Total other income and deductions |
(76 | ) | (67 | ) | (9 | ) | (362 | ) | (240 | ) | (122 | ) | ||||||||||||
| Income before income taxes |
153 | 157 | (4 | ) | 694 | 603 | 91 | |||||||||||||||||
| Income taxes |
62 | 59 | 3 | 357 | 229 | 128 | ||||||||||||||||||
| Net income |
$ | 91 | $ | 98 | $ | (7 | ) | $ | 337 | $ | 374 | $ | (37 | ) | ||||||||||
| (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. |
3
EXELON CORPORATION
Business Segment Comparative Statements of Operations
(unaudited)
(in millions)
| PECO | ||||||||||||||||||||||||
| Three Months Ended December 31, | Twelve Months Ended December 31, | |||||||||||||||||||||||
| 2010 | 2009 | Variance | 2010 | 2009 | Variance | |||||||||||||||||||
| Operating revenues |
$ | 1,299 | $ | 1,266 | $ | 33 | $ | 5,519 | $ | 5,311 | $ | 208 | ||||||||||||
| Operating expenses |
||||||||||||||||||||||||
| Purchased power |
652 | 532 | 120 | 2,361 | 2,274 | 87 | ||||||||||||||||||
| Fuel |
123 | 126 | (3 | ) | 401 | 472 | (71 | ) | ||||||||||||||||
| Operating and maintenance |
172 | 159 | 13 | 680 | 640 | 40 | ||||||||||||||||||
| Operating and maintenance for regulatory required programs (a) |
17 | — | 17 | 53 | — | 53 | ||||||||||||||||||
| Depreciation and amortization |
201 | 225 | (24 | ) | 1,060 | 952 | 108 | |||||||||||||||||
| Taxes other than income |
64 | 64 | — | 303 | 276 | 27 | ||||||||||||||||||
| Total operating expenses |
1,229 | 1,106 | 123 | 4,858 | 4,614 | 244 | ||||||||||||||||||
| Operating income |
70 | 160 | (90 | ) | 661 | 697 | (36 | ) | ||||||||||||||||
| Other income and deductions |
||||||||||||||||||||||||
| Interest expense |
(34 | ) | (42 | ) | 8 | (193 | ) | (187 | ) | (6 | ) | |||||||||||||
| Loss in equity method investments |
— | (5 | ) | 5 | — | (24 | ) | 24 | ||||||||||||||||
| Other, net |
2 | 5 | (3 | ) | 8 | 13 | (5 | ) | ||||||||||||||||
| Total other income and deductions |
(32 | ) | (42 | ) | 10 | (185 | ) | (198 | ) | 13 | ||||||||||||||
| Income before income taxes |
38 | 118 | (80 | ) | 476 | 499 | (23 | ) | ||||||||||||||||
| Income taxes |
17 | 40 | (23 | ) | 152 | 146 | 6 | |||||||||||||||||
| Net income |
$ | 21 | $ | 78 | $ | (57 | ) | $ | 324 | $ | 353 | $ | (29 | ) | ||||||||||
| Other (b) | ||||||||||||||||||||||||
| Three Months Ended December 31, | Twelve Months Ended December 31, | |||||||||||||||||||||||
| 2010 | 2009 | Variance | 2010 | 2009 | Variance | |||||||||||||||||||
| Operating revenues |
$ | (773 | ) | $ | (785 | ) | $ | 12 | $ | (3,104 | ) | $ | (3,470 | ) | $ | 366 | ||||||||
| Operating expenses |
||||||||||||||||||||||||
| Purchased power |
(773 | ) | (784 | ) | 11 | (3,096 | ) | (3,462 | ) | 366 | ||||||||||||||
| Fuel |
— | (1 | ) | 1 | (1 | ) | — | (1 | ) | |||||||||||||||
| Operating and maintenance |
10 | 2 | 8 | (14 | ) | 6 | (20 | ) | ||||||||||||||||
| Depreciation and amortization |
5 | 16 | (11 | ) | 25 | 55 | (30 | ) | ||||||||||||||||
| Taxes other than income |
5 | 1 | 4 | 19 | 16 | 3 | ||||||||||||||||||
| Total operating expenses |
(753 | ) | (766 | ) | 13 | (3,067 | ) | (3,385 | ) | 318 | ||||||||||||||
| Operating loss |
(20 | ) | (19 | ) | (1 | ) | (37 | ) | (85 | ) | 48 | |||||||||||||
| Other income and deductions |
||||||||||||||||||||||||
| Interest expense |
(19 | ) | (20 | ) | 1 | (85 | ) | (112 | ) | 27 | ||||||||||||||
| Loss in equity method investments |
— | (1 | ) | 1 | — | — | — | |||||||||||||||||
| Other, net |
5 | (6 | ) | 11 | 23 | (41 | ) | 64 | ||||||||||||||||
| Total other income and deductions |
(14 | ) | (27 | ) | 13 | (62 | ) | (153 | ) | 91 | ||||||||||||||
| Loss before income taxes |
(34 | ) | (46 | ) | 12 | (99 | ) | (238 | ) | 139 | ||||||||||||||
| Income taxes |
(22 | ) | (26 | ) | 4 | (29 | ) | (96 | ) | 67 | ||||||||||||||
| Net loss |
$ | (12 | ) | $ | (20 | ) | $ | 8 | $ | (70 | ) | $ | (142 | ) | $ | 72 | ||||||||
| (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. |
| (b) | Other primarily includes eliminating and consolidating adjustments, Exelon’s corporate operations, shared service entities and other financing and investment activities. |
4
EXELON CORPORATION
Consolidated Balance Sheets
(unaudited)
(in millions)
| December 31, 2010 |
December 31, 2009 |
|||||||
| ASSETS |
||||||||
| Current assets |
||||||||
| Cash and cash equivalents |
$ | 1,612 | $ | 2,010 | ||||
| Restricted cash and investments |
30 | 40 | ||||||
| Accounts receivable, net |
||||||||
| Customer |
1,932 | 1,563 | ||||||
| Other |
1,196 | 486 | ||||||
| Mark-to-market derivative assets |
487 | 376 | ||||||
| Inventories, net |
||||||||
| Fossil fuel |
216 | 198 | ||||||
| Materials and supplies |
590 | 559 | ||||||
| Other |
335 | 209 | ||||||
| Total current assets |
6,398 | 5,441 | ||||||
| Property, plant and equipment, net |
29,941 | 27,341 | ||||||
| Deferred debits and other assets |
||||||||
| Regulatory assets |
4,140 | 4,872 | ||||||
| Nuclear decommissioning trust (NDT) funds |
6,408 | 6,669 | ||||||
| Investments |
732 | 724 | ||||||
| Goodwill |
2,625 | 2,625 | ||||||
| Mark-to-market derivative assets |
409 | 649 | ||||||
| Pledged assets for Zion Station decommissioning |
824 | — | ||||||
| Other |
763 | 859 | ||||||
| Total deferred debits and other assets |
15,901 | 16,398 | ||||||
| Total assets |
$ | 52,240 | $ | 49,180 | ||||
| Liabilities and shareholders’ equity |
||||||||
| Current liabilities |
||||||||
| Short-term borrowings |
$ | — | $ | 155 | ||||
| Short-term notes payable — accounts receivable agreement |
225 | — | ||||||
| Long-term debt due within one year |
599 | 639 | ||||||
| Long-term debt to PECO Energy Transition Trust due within one year |
— | 415 | ||||||
| Accounts payable |
1,373 | 1,345 | ||||||
| Mark-to-market derivative liabilities |
38 | 198 | ||||||
| Accrued expenses |
1,040 | 923 | ||||||
| Deferred income taxes |
85 | 152 | ||||||
| Other |
880 | 411 | ||||||
| Total current liabilities |
4,240 | 4,238 | ||||||
| Long-term debt |
11,614 | 10,995 | ||||||
| Long-term debt to financing trusts |
390 | 390 | ||||||
| Deferred credits and other liabilities |
||||||||
| Deferred income taxes and unamortized investment tax credits |
6,621 | 5,750 | ||||||
| Asset retirement obligations |
3,494 | 3,434 | ||||||
| Pension obligations |
3,658 | 3,625 | ||||||
| Non-pension postretirement benefit obligations |
2,218 | 2,180 | ||||||
| Spent nuclear fuel obligation |
1,018 | 1,017 | ||||||
| Regulatory liabilities |
3,555 | 3,492 | ||||||
| Mark-to-market derivative liabilities |
21 | 23 | ||||||
| Payable for Zion Station decommissioning |
659 | — | ||||||
| Other |
1,102 | 1,309 | ||||||
| Total deferred credits and other liabilities |
22,346 | 20,830 | ||||||
| Total liabilities |
38,590 | 36,453 | ||||||
| Preferred securities of subsidiary |
87 | 87 | ||||||
| Shareholders’ equity |
||||||||
| Common stock |
9,006 | 8,923 | ||||||
| Treasury stock, at cost |
(2,327 | ) | (2,328 | ) | ||||
| Retained earnings |
9,304 | 8,134 | ||||||
| Accumulated other comprehensive loss, net |
(2,423 | ) | (2,089 | ) | ||||
| Total shareholders’ equity |
13,560 | 12,640 | ||||||
| Noncontrolling interest |
3 | — | ||||||
| Total equity |
13,563 | 12,640 | ||||||
| Total liabilities and shareholders’ equity |
$ | 52,240 | $ | 49,180 | ||||
5
EXELON CORPORATION
Consolidated Statements of Cash Flows
(unaudited)
(in millions)
| Twelve Months Ended | ||||||||
| December 31, | ||||||||
| 2010 | 2009 | |||||||
| Cash flows from operating activities |
||||||||
| Net income |
$ | 2,563 | $ | 2,707 | ||||
| Adjustments to reconcile net income to net cash flows provided by operating activities: |
||||||||
| Depreciation, amortization and accretion, including nuclear fuel amortization |
2,943 | 2,601 | ||||||
| Impairment of long-lived assets |
— | 223 | ||||||
| Deferred income taxes and amortization of investment tax credits |
981 | 756 | ||||||
| Net fair value changes related to derivatives |
(88 | ) | (95 | ) | ||||
| Net realized and unrealized gains on NDT fund investments |
(105 | ) | (207 | ) | ||||
| Other non-cash operating activities |
609 | 652 | ||||||
| Changes in assets and liabilities: |
||||||||
| Accounts receivable |
(232 | ) | 234 | |||||
| Inventories |
(62 | ) | 51 | |||||
| Accounts payable, accrued expenses and other current liabilities |
472 | (254 | ) | |||||
| Options premiums paid, net |
(124 | ) | (40 | ) | ||||
| Counterparty collateral received (posted), net |
(155 | ) | 196 | |||||
| Income taxes |
(543 | ) | (29 | ) | ||||
| Pension and non-pension postretirement benefit contributions |
(959 | ) | (588 | ) | ||||
| Other assets and liabilities |
(56 | ) | (113 | ) | ||||
| Net cash flows provided by operating activities |
5,244 | 6,094 | ||||||
| Cash flows from investing activities |
||||||||
| Capital expenditures |
(3,326 | ) | (3,273 | ) | ||||
| Proceeds from nuclear decommissioning trust fund sales |
3,764 | 4,292 | ||||||
| Investment in nuclear decommissioning trust funds |
(3,907 | ) | (4,531 | ) | ||||
| Acquisition of Exelon Wind |
(893 | ) | — | |||||
| Proceeds from sales of investments |
28 | 41 | ||||||
| Purchases of investments |
(22 | ) | (28 | ) | ||||
| Change in restricted cash |
423 | 35 | ||||||
| Other investing activities |
39 | 6 | ||||||
| Net cash flows used in investing activities |
(3,894 | ) | (3,458 | ) | ||||
| Cash flows from financing activities |
||||||||
| Changes in short-term debt |
(155 | ) | (56 | ) | ||||
| Issuance of long-term debt |
1,398 | 1,987 | ||||||
| Retirement of long-term debt |
(828 | ) | (1,773 | ) | ||||
| Retirement of long-term debt of variable interest entity |
(806 | ) | — | |||||
| Retirement of long-term debt to financing affiliates |
— | (709 | ) | |||||
| Dividends paid on common stock |
(1,389 | ) | (1,385 | ) | ||||
| Proceeds from employee stock plans |
48 | 42 | ||||||
| Other financing activities |
(16 | ) | (3 | ) | ||||
| Net cash flows used in financing activities |
(1,748 | ) | (1,897 | ) | ||||
| Increase (decrease) in cash and cash equivalents |
(398 | ) | 739 | |||||
| Cash and cash equivalents at beginning of period |
2,010 | 1,271 | ||||||
| Cash and cash equivalents at end of period |
$ | 1,612 | $ | 2,010 | ||||
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 December 31, 2010 | Three Months Ended December 31, 2009 | |||||||||||||||||||||||
| GAAP (a) | Adjustments | Adjusted Non-GAAP |
GAAP (a) | Adjustments | Adjusted Non-GAAP |
|||||||||||||||||||
| Operating revenues |
$ | 4,494 | $ | 6 | (c) | $ | 4,500 | $ | 4,116 | $ | 32 | (c),(i) | $ | 4,148 | ||||||||||
| Operating expenses |
||||||||||||||||||||||||
| Purchased power |
1,152 | (145 | )(d) | 1,007 | 815 | (36 | )(d) | 779 | ||||||||||||||||
| Fuel |
541 | (41 | )(d) | 500 | 425 | 78 | (d) | 503 | ||||||||||||||||
| Operating and maintenance |
1,160 | (2 | )(e),(f),(g) | 1,158 | 1,120 | (24 | )(e) | 1,096 | ||||||||||||||||
| Operating and maintenance for regulatory required programs (b) |
44 | — | 44 | 19 | — | 19 | ||||||||||||||||||
| Depreciation and amortization |
465 | (23 | )(e) | 442 | 474 | (32 | )(e) | 442 | ||||||||||||||||
| Taxes other than income |
193 | — | 193 | 187 | — | 187 | ||||||||||||||||||
| Total operating expenses |
3,555 | (211 | ) | 3,344 | 3,040 | (14 | ) | 3,026 | ||||||||||||||||
| Operating income |
939 | 217 | 1,156 | 1,076 | 46 | 1,122 | ||||||||||||||||||
| Other income and deductions |
||||||||||||||||||||||||
| Interest expense |
(183 | ) | — | (183 | ) | (176 | ) | — | (176 | ) | ||||||||||||||
| Loss in equity method investments |
— | — | — | (6 | ) | — | (6 | ) | ||||||||||||||||
| Other, net |
135 | (83 | )(h) | 52 | 60 | (18 | )(h),(j) | 42 | ||||||||||||||||
| Total other income and deductions |
(48 | ) | (83 | ) | (131 | ) | (122 | ) | (18 | ) | (140 | ) | ||||||||||||
| Income before income taxes |
891 | 134 | 1,025 | 954 | 28 | 982 | ||||||||||||||||||
| Income taxes |
367 |
|
27 |
(c),(d),(e), (f),(g),(h) |
394 | 373 | |
(1) |
(c),(d),(e), (h),(i),(j) |
372 | ||||||||||||||
| Net income |
$ | 524 | $ | 107 | $ | 631 | $ | 581 | $ | 29 | $ | 610 | ||||||||||||
| Effective tax rate |
41.2 | % | 38.4 | % | 39.1 | % | 37.9 | % | ||||||||||||||||
| Earnings per average common share |
||||||||||||||||||||||||
| Basic |
$ | 0.79 | $ | 0.17 | $ | 0.96 | $ | 0.88 | $ | 0.04 | $ | 0.92 | ||||||||||||
| Diluted |
$ | 0.79 | $ | 0.17 | $ | 0.96 | $ | 0.88 | $ | 0.04 | $ | 0.92 | ||||||||||||
| Average common shares outstanding |
||||||||||||||||||||||||
| Basic |
662 | 662 | 660 | 660 | ||||||||||||||||||||
| Diluted |
663 | 663 | 662 | 662 | ||||||||||||||||||||
| Effect of adjustments on earnings per average diluted common share recorded in accordance with GAAP: | ||||||||||||||||||||||||
| 2007 Illinois electric rate settlement (c) |
$ | 0.01 | $ | 0.02 | ||||||||||||||||||||
| Mark-to-market impact of economic hedging activities (d) |
0.17 | (0.04 | ) | |||||||||||||||||||||
| Retirement of fossil generating units (e) |
0.03 | 0.05 | ||||||||||||||||||||||
| Acquisition costs (f) |
0.01 | — | ||||||||||||||||||||||
| Asset retirement obligation reduction (g) |
(0.01 | ) | — | |||||||||||||||||||||
| Unrealized gains related to NDT fund investments (h) |
(0.04 | ) | (0.02 | ) | ||||||||||||||||||||
| City of Chicago Settlement with ComEd (i) |
— | 0.01 | ||||||||||||||||||||||
| Costs associated with early debt retirements (j) |
— | 0.02 | ||||||||||||||||||||||
| Total adjustments |
$ | 0.17 | $ | 0.04 | ||||||||||||||||||||
| (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. |
| (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 costs associated with the planned retirement of fossil generating units. |
| (f) | Adjustment to exclude external costs associated with Exelon’s acquisition of John Deere Renewables, LLC (JDR) (now known as Exelon Wind). |
| (g) | Adjustment to exclude a decrease in 2010 in ComEd and PECO’s asset retirement obligations. |
| (h) | Adjustment to exclude unrealized gains in 2010 and 2009 associated with Generation’s NDT fund investments and the associated contractual accounting relating to income taxes. |
| (i) | Adjustment to exclude costs associated with ComEd’s 2007 settlement agreement with the City of Chicago. |
| (j) | Adjustment to exclude costs associated with early debt retirements. |
7
EXELON CORPORATION
Reconciliation of Adjusted (non-GAAP) Operating Earnings to GAAP Consolidated Statements of Operations
(unaudited)
(in millions, except per share data)
| Twelve Months Ended December 31, 2010 | Twelve Months Ended December 31, 2009 | |||||||||||||||||||||||
| GAAP (a) | Adjustments | Adjusted Non-GAAP |
GAAP (a) | Adjustments | Adjusted Non-GAAP |
|||||||||||||||||||
| Operating revenues |
$ | 18,644 | $ | 25 | (c),(d) | $ | 18,669 | $ | 17,318 | $ | 114 | (c),(d) | $ | 17,432 | ||||||||||
| Operating expenses |
||||||||||||||||||||||||
| Purchased power |
4,425 | (3 | )(e) | 4,422 | 3,215 | 94 | (e) | 3,309 | ||||||||||||||||
| Fuel |
2,010 | 32 | (e),(f) | 2,042 | 2,066 | 87 | (e) | 2,153 | ||||||||||||||||
| Operating and maintenance |
4,453 | |
(4) |
(g),(h),(i), (j) |
4,449 | 4,612 | |
(265) |
(c),(h),(i),(j), (m),(n) |
4,347 | ||||||||||||||
| Operating and maintenance for regulatory required programs (b) |
147 | — | 147 | 63 | — | 63 | ||||||||||||||||||
| Depreciation and amortization |
2,075 | (80 | )(h) | 1,995 | 1,834 | (32 | )(h) | 1,802 | ||||||||||||||||
| Taxes other than income |
808 | — | 808 | 778 | — | 778 | ||||||||||||||||||
| Total operating expenses |
13,918 | (55 | ) | 13,863 | 12,568 | (116 | ) | 12,452 | ||||||||||||||||
| Operating income |
4,726 | 80 | 4,806 | 4,750 | 230 | 4,980 | ||||||||||||||||||
| Other income and deductions |
||||||||||||||||||||||||
| Interest expense |
(817 | ) | 103 | (k) | (714 | ) | (731 | ) | 12 | (k),(o) | (719 | ) | ||||||||||||
| Loss in equity method investments |
— | — | — | (27 | ) | — | (27 | ) | ||||||||||||||||
| Other, net |
312 | (153 | )(k),(l) | 159 | 427 | (324 | )(k),(l),(o) | 103 | ||||||||||||||||
| Total other income and deductions |
(505 | ) | (50 | ) | (555 | ) | (331 | ) | (312 | ) | (643 | ) | ||||||||||||
| Income before income taxes |
4,221 | 30 | 4,251 | 4,419 | (82 | ) | 4,337 | |||||||||||||||||
| Income taxes |
1,658 | |
(96) |
(c),(d),(e), (f),(g),(h), (i),(j),(k),(l) |
1,562 | 1,712 | |
(98) |
(c),(d),(e),(h), (i),(j),(k),(l), (m),(n),(o) |
1,614 | ||||||||||||||
| Net income |
$ | 2,563 | $ | 126 | $ | 2,689 | $ | 2,707 | $ | 16 | $ | 2,723 | ||||||||||||
| Effective tax rate |
39.3 | % | 36.7 | % | 38.7 | % | 37.2 | % | ||||||||||||||||
| Earnings per average common share |
||||||||||||||||||||||||
| Basic |
$ | 3.88 | $ | 0.19 | $ | 4.07 | $ | 4.10 | $ | 0.03 | $ | 4.13 | ||||||||||||
| Diluted |
$ | 3.87 | $ | 0.19 | $ | 4.06 | $ | 4.09 | $ | 0.03 | $ | 4.12 | ||||||||||||
| Average common shares outstanding |
||||||||||||||||||||||||
| Basic |
661 | 661 | 659 | 659 | ||||||||||||||||||||
| Diluted |
663 | 663 | 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 | $ | 0.10 | ||||||||||||||||||||
| City of Chicago settlement (d) |
— | 0.01 | ||||||||||||||||||||||
| Mark-to-market impact of economic hedging activities (e) |
(0.08 | ) | (0.16 | ) | ||||||||||||||||||||
| Impairment of certain emissions allowances (f) |
0.05 | — | ||||||||||||||||||||||
| Charge resulting from health care legislation (g) |
0.10 | — | ||||||||||||||||||||||
| Retirement of fossil generating units (h) |
0.08 | 0.05 | ||||||||||||||||||||||
| Acquisition costs (i) |
0.01 | 0.03 | ||||||||||||||||||||||
| Asset retirement obligation reduction (j) |
(0.01 | ) | (0.05 | ) | ||||||||||||||||||||
| Remeasurement of income tax uncertainties (k) |
0.10 | (0.10 | ) | |||||||||||||||||||||
| Unrealized gains related to NDT fund investments (l) |
(0.08 | ) | (0.19 | ) | ||||||||||||||||||||
| 2009 restructuring charges (m) |
— | 0.03 | ||||||||||||||||||||||
| Impairment of certain generating assets (n) |
— | 0.20 | ||||||||||||||||||||||
| Costs associated with early debt retirements (o) |
— | 0.11 | ||||||||||||||||||||||
| Total adjustments |
$ | 0.19 | $ | 0.03 | ||||||||||||||||||||
| (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. |
| (c) | Adjustment to exclude the impact of the 2007 Illinois electric rate settlement. |
| (d) | Adjustment to exclude costs associated with ComEd’s 2007 settlement agreement with the City of Chicago. |
| (e) | Adjustment to exclude the mark-to-market impact of Exelon’s economic hedging activities. |
| (f) | Adjustment to exclude a non-cash charge for the impairment of certain SO2 emission allowances as a result of declining market prices since the release of the EPA’s proposed Transport Rule in the third quarter of 2010. |
| (g) | Adjustment to exclude a non-cash charge related to the passage of Federal health care legislation that reduces the deductibility of retiree prescription drug benefits for Federal income tax purposes to the extent they are reimbursed under Medicare Part D. |
| (h) | Adjustment to exclude costs associated with the planned retirement of fossil generating units. |
| (i) | Adjustment to exclude external costs associated with Exelon’s acquisition of JDR (now known as Exelon Wind) and the proposed acquisition of NRG, which was terminated in July 2009. |
| (j) | Adjustment to exclude a decrease in 2010 in ComEd and PECO’s asset retirement obligations and a decrease in 2009 in Generation’s decomissioning obligation. |
| (k) | Adjustment to exclude 2010 and 2009 remeasurements of income tax uncertainties and a 2009 change in state deferred income taxes. |
| (l) | Adjustment to exclude unrealized gains in 2010 and 2009 associated with Generation’s NDT fund investments and the associated contractual accounting relating to income taxes. |
| (m) | Adjustment to exclude 2009 charges associated with the elimination of management and staff positions. |
| (n) | Adjustment to exclude a non-cash charge for the impairment of certain of Generation’s Texas plants. |
| (o) | Adjustment to exclude costs associated with early debt retirements. |
8
EXELON CORPORATION
Reconciliation of Adjusted (non-GAAP) Operating
Earnings to GAAP Earnings (in millions)
Three Months Ended December 31, 2010 and 2009
| Exelon Earnings per Diluted Share |
Generation | ComEd | PECO | Other | Exelon | |||||||||||||||||||
| 2009 GAAP Earnings (Loss) |
$ | 0.88 | $ | 425 | $ | 98 | $ | 78 | $ | (20 | ) | $ | 581 | |||||||||||
| 2009 Adjusted (non-GAAP) Operating Earnings (Loss) Adjustments: |
||||||||||||||||||||||||
| 2007 Illinois Electric Rate Settlement |
0.02 | 13 | 2 | — | — | 15 | ||||||||||||||||||
| Mark-to-Market Impact of Economic Hedging Activities |
(0.04 | ) | (26 | ) | — | — | — | (26 | ) | |||||||||||||||
| Unrealized Gains Related to NDT Fund Investments (1) |
(0.02 | ) | (14 | ) | — | — | — | (14 | ) | |||||||||||||||
| City of Chicago Settlement with ComEd |
0.01 | — | 5 | — | — | 5 | ||||||||||||||||||
| Costs Associated with Early Debt Retirements |
0.02 | 9 | — | — | 6 | 15 | ||||||||||||||||||
| Retirement of Fossil Generating Units (2) |
0.05 | 34 | — | — | — | 34 | ||||||||||||||||||
| 2009 Adjusted (non-GAAP) Operating Earnings (Loss) |
0.92 | 441 | 105 | 78 | (14 | ) | 610 | |||||||||||||||||
| Year Over Year Effects on Earnings: |
||||||||||||||||||||||||
| Generation Energy Margins, Excluding Mark-to-Market: |
||||||||||||||||||||||||
| Nuclear Output (3) |
0.04 | 27 | — | — | — | 27 | ||||||||||||||||||
| Nuclear Fuel Costs (4) |
(0.02 | ) | (15 | ) | — | — | — | (15 | ) | |||||||||||||||
| Reliability Pricing Model (RPM) Capacity Pricing |
0.07 | 48 | — | — | — | 48 | ||||||||||||||||||
| Market and Portfolio Conditions (5) |
(0.03 | ) | (22 | ) | — | — | — | (22 | ) | |||||||||||||||
| ComEd and PECO Margins: |
||||||||||||||||||||||||
| Weather |
0.02 | — | 4 | 6 | — | 10 | ||||||||||||||||||
| Load |
(0.01 | ) | — | (5 | ) | — | — | (5 | ) | |||||||||||||||
| Other Energy Delivery |
0.01 | — | — | 5 | — | 5 | ||||||||||||||||||
| Competitive Transition Charge (CTC) Recoveries (6) |
— | 75 | — | (68 | ) | (7 | ) | — | ||||||||||||||||
| Operating and Maintenance Expense: |
||||||||||||||||||||||||
| Bad Debt (7) |
0.01 | (2 | ) | 7 | (1 | ) | — | 4 | ||||||||||||||||
| Labor, Contracting and Materials (8) |
(0.04 | ) | (14 | ) | (7 | ) | (7 | ) | — | (28 | ) | |||||||||||||
| Planned Nuclear Refueling Outages |
— | 1 | — | — | — | 1 | ||||||||||||||||||
| Other Operating and Maintenance (9) |
— | 7 | (2 | ) | — | (3 | ) | 2 | ||||||||||||||||
| Pension and Non-Pension Postretirement Benefits (10) |
(0.01 | ) | (2 | ) | (2 | ) | — | (1 | ) | (5 | ) | |||||||||||||
| Depreciation and Amortization Expense (11) |
(0.03 | ) | (17 | ) | (4 | ) | (2 | ) | 5 | (18 | ) | |||||||||||||
| Scheduled CTC Amortization Expense (12) |
0.02 | — | — | 15 | — | 15 | ||||||||||||||||||
| Income Taxes |
— | 8 | (5 | ) | (13 | ) | 8 | (2 | ) | |||||||||||||||
| Interest Expense |
— | (5 | ) | (4 | ) | 7 | 1 | (1 | ) | |||||||||||||||
| Other (13) |
0.01 | 8 | (2 | ) | — | (1 | ) | 5 | ||||||||||||||||
| 2010 Adjusted (non-GAAP) Operating Earnings (Loss) |
0.96 | 538 | 85 | 20 | (12 | ) | 631 | |||||||||||||||||
| 2010 Adjusted (non-GAAP) Operating Earnings (Loss) Adjustments: |
||||||||||||||||||||||||
| 2007 Illinois Electric Rate Settlement |
(0.01 | ) | (4 | ) | — | — | — | (4 | ) | |||||||||||||||
| Mark-to-Market Impact of Economic Hedging Activities |
(0.17 | ) | (113 | ) | — | — | — | (113 | ) | |||||||||||||||
| Unrealized Gains Related to NDT Fund Investments (1) |
0.04 | 26 | — | — | — | 26 | ||||||||||||||||||
| Retirement of Fossil Generating Units (2) |
(0.03 | ) | (17 | ) | — | — | — | (17 | ) | |||||||||||||||
| JDR Acquisition Costs (14) |
(0.01 | ) | (6 | ) | — | — | — | (6 | ) | |||||||||||||||
| Asset Retirement Obligation Reduction (15) |
0.01 | — | 6 | 1 | — | 7 | ||||||||||||||||||
| 2010 GAAP Earnings (Loss) |
$ | 0.79 | $ | 424 | $ | 91 | $ | 21 | $ | (12 | ) | $ | 524 | |||||||||||
| (1) | Reflects the impact of unrealized gains in 2009 and 2010 on NDT fund investments to the extent not offset by contractual accounting as described in the notes to the consolidated financial statements. |
| (2) | Reflects incremental accelerated depreciation, inventory write-downs and severance costs associated with the planned retirement of four fossil generating units. |
| (3) | Primarily reflects the impact of decreased planned and unplanned nuclear outage days in 2010, including Salem. |
| (4) | Reflects the impact of higher nuclear fuel prices. |
| (5) | Primarily reflects the impact of a decrease in realized market prices for the sale of energy. |
| (6) | Reflects decreased CTC revenues at PECO as scheduled in connection with the end of the transition period, which resulted in higher energy prices paid to Generation under the PPA. Generation and PECO’s marginal tax rate differences are reflected at Exelon Corporate. |
| (7) | Primarily reflects increased collection activities at ComEd. |
| (8) | Primarily reflects the impact of increased wages and incentive compensation benefits, as well as the impact of inflation related to contracting and materials expense. |
| (9) | Primarily reflects the 2010 impact of a nuclear insurance credit at Generation. |
| (10) | Primarily reflects the impact of a lower assumed discount rate used in 2010 as compared to 2009 to calculate the pension and other postretirement benefit obligations and costs. |
| (11) | Primarily reflects increased depreciation expense across the operating companies due to ongoing capital expenditures and the impact of a first quarter 2010 depreciation study at Generation. |
| (12) | Reflects decreased amortization expense of CTCs at PECO as scheduled in connection with the end of the transition period. |
| (13) | Primarily reflects realized gains associated with NDT funds at Generation as a result of favorable market conditions in 2010. |
| (14) | Reflects external costs incurred associated with Exelon’s acquisition of JDR (now known as Exelon Wind). |
| (15) | Reflects a decrease in ComEd and PECO’s asset retirement obligations primarily related to transmission and distribution substation assets. |
9
EXELON CORPORATION
Reconciliation of Adjusted (non-GAAP) Operating
Earnings to GAAP Earnings (in millions)
Twelve Months Ended December 31, 2010 and 2009
| Exelon Earnings per Diluted Share |
Generation | ComEd | PECO | Other | Exelon | |||||||||||||||||||
| 2009 GAAP Earnings (Loss) |
$ | 4.09 | $ | 2,122 | $ | 374 | $ | 353 | $ | (142 | ) | $ | 2,707 | |||||||||||
| 2009 Adjusted (non-GAAP) Operating Earnings (Loss) |
||||||||||||||||||||||||
| 2007 Illinois Electric Rate Settlement |
0.10 | 62 | 4 | — | — | 66 | ||||||||||||||||||
| Mark-to-Market Impact of Economic Hedging Activities |
(0.16 | ) | (110 | ) | — | — | — | (110 | ) | |||||||||||||||
| Unrealized Gains Related to NDT Fund Investments (1) |
(0.19 | ) | (132 | ) | — | — | — | (132 | ) | |||||||||||||||
| Asset Retirement Obligation Reduction (2) |
(0.05 | ) | (32 | ) | — | — | — | (32 | ) | |||||||||||||||
| City of Chicago Settlement with ComEd |
0.01 | — | 5 | — | — | 5 | ||||||||||||||||||
| NRG Acquisition Costs (3) |
0.03 | — | — | — | 20 | 20 | ||||||||||||||||||
| Impairment of Certain Generating Assets (4) |
0.20 | 135 | — | — | — | 135 | ||||||||||||||||||
| 2009 Restructuring Charges (5) |
0.03 | 7 | 13 | 1 | 1 | 22 | ||||||||||||||||||
| Non-Cash Remeasurement of Income Tax Uncertainties and Reassessment of State Deferred Income Taxes (6) |
(0.10 | ) | (38 | ) | (40 | ) | — | 12 | (66 | ) | ||||||||||||||
| Costs Associated with Early Debt Retirements |
0.11 | 44 | — | — | 30 | 74 | ||||||||||||||||||
| Retirement of Fossil Generating Units (7) |
0.05 | 34 | — | — | — | 34 | ||||||||||||||||||
| 2009 Adjusted (non-GAAP) Operating Earnings (Loss) |
4.12 | 2,092 | 356 | 354 | (79 | ) | 2,723 | |||||||||||||||||
| Year Over Year Effects on Earnings: |
||||||||||||||||||||||||
| Generation Energy Margins, Excluding Mark-to-Market: |
||||||||||||||||||||||||
| Nuclear Output (8) |
(0.02 | ) | (11 | ) | — | — | — | (11 | ) | |||||||||||||||
| Nuclear Fuel Costs (9) |
(0.11 | ) | (70 | ) | — | — | — | (70 | ) | |||||||||||||||
| RPM Capacity Pricing |
0.19 | 125 | — | — | — | 125 | ||||||||||||||||||
| Market and Portfolio Conditions (10) |
(0.13 | ) | (86 | ) | — | — | — | (86 | ) | |||||||||||||||
| ComEd and PECO Margins: |
||||||||||||||||||||||||
| Weather |
0.16 | — | 54 | 54 | — | 108 | ||||||||||||||||||
| Load |
— | — | (2 | ) | 1 | — | (1 | ) | ||||||||||||||||
| Other Energy Delivery |
(0.02 | ) | — | (4 | ) | (10 | ) | — | (14 | ) | ||||||||||||||
| CTC Recoveries (11) |
— | (41 | ) | — | 45 | (4 | ) | — | ||||||||||||||||
| Operating and Maintenance Expense: |
||||||||||||||||||||||||
| Bad Debt (12) |
0.04 | — | 24 | 2 | — | 26 | ||||||||||||||||||
| Recovery of Prior Year Bad Debt Expense at ComEd (13) |
0.06 | — | 36 | — | — | 36 | ||||||||||||||||||
| Labor, Contracting and Materials (14) |
(0.07 | ) | (33 | ) | 5 | (19 | ) | — | (47 | ) | ||||||||||||||
| Planned Nuclear Refueling Outages |
(0.02 | ) | (11 | ) | — | — | — | (11 | ) | |||||||||||||||
| Other Operating and Maintenance (15) |
(0.03 | ) | 15 | (9 | ) | (11 | ) | (17 | ) | (22 | ) | |||||||||||||
| Pension and Non-Pension Postretirement Benefits (16) |
(0.03 | ) | (14 | ) | (4 | ) | — | 2 | (16 | ) | ||||||||||||||
| Depreciation and Amortization Expense (17) |
(0.09 | ) | (58 | ) | (12 | ) | (7 | ) | 18 | (59 | ) | |||||||||||||
| Scheduled CTC Amortization Expense (18) |
(0.10 | ) | — | — | (67 | ) | — | (67 | ) | |||||||||||||||
| Income Taxes (19) |
0.05 | 34 | (11 | ) | (8 | ) | 18 | 33 | ||||||||||||||||
| Interest Expense (20) |
0.03 | (30 | ) | (1 | ) | 36 | 15 | 20 | ||||||||||||||||
| Other (21) |
0.03 | 16 | 20 | (15 | ) | 1 | 22 | |||||||||||||||||
| 2010 Adjusted (non-GAAP) Operating Earnings (Loss) |
4.06 | 1,928 | 452 | 355 | (46 | ) | 2,689 | |||||||||||||||||
| 2010 Adjusted (non-GAAP) Operating Earnings (Loss) |
||||||||||||||||||||||||
| 2007 Illinois Electric Rate Settlement |
(0.02 | ) | (12 | ) | (1 | ) | — | — | (13 | ) | ||||||||||||||
| Mark-to-Market Impact of Economic Hedging Activities |
0.08 | 52 | — | — | — | 52 | ||||||||||||||||||
| Unrealized Gains Related to NDT Fund Investments (1) |
0.08 | 52 | — | — | — | 52 | ||||||||||||||||||
| City of Chicago Settlement with ComEd |
— | — | (2 | ) | — | — | (2 | ) | ||||||||||||||||
| Asset Retirement Obligation Reduction (2) |
0.01 | — | 6 | 1 | — | 7 | ||||||||||||||||||
| Retirement of Fossil Generating Units (7) |
(0.08 | ) | (50 | ) | — | — | — | (50 | ) | |||||||||||||||
| Non-Cash Charge Resulting From Health Care Legislation (22) |
(0.10 | ) | (26 | ) | (12 | ) | (10 | ) | (17 | ) | (65 | ) | ||||||||||||
| Non-Cash Remeasurement of Income Tax Uncertainties (6) |
(0.10 | ) | 70 | (106 | ) | (22 | ) | (7 | ) | (65 | ) | |||||||||||||
| Impairment of Certain Emissions Allowances (23) |
(0.05 | ) | (35 | ) | — | — | — | (35 | ) | |||||||||||||||
| JDR Acquisition Costs (24) |
(0.01 | ) | (7 | ) | — | — | — | (7 | ) | |||||||||||||||
| 2010 GAAP Earnings (Loss) |
$ | 3.87 | $ | 1,972 | $ | 337 | $ | 324 | $ | (70 | ) | $ | 2,563 | |||||||||||
| (1) | Reflects the impact of unrealized gains in 2009 and 2010 on NDT fund investments to the extent not offset by contractual accounting as described in the notes to the consolidated financial statements. |
| (2) | Reflects a decrease in 2009 of Generation’s decommissioning obligation liability primarily related to the former AmerGen nuclear plants and a decrease in 2010 of ComEd and PECO’s asset retirement obligations primarily related to transmission and distribution substation assets. |
| (3) | Reflects external costs incurred in 2009 associated with Exelon’s proposed acquisition of NRG, which was terminated in July 2009. |
| (4) | Reflects the impact of the impairment of certain of Generation’s Texas plants. |
| (5) | Reflects severance expense associated with the elimination of management and staff positions in 2009. |
| (6) | For 2009, reflects the impacts of a remeasurement of income tax uncertainties related to ComEd’s 1999 sale of fossil generating units and a reassessment of anticipated apportionment of Exelon’s income. For 2010, reflects the impact of a remeasurement of income tax uncertainties related to ComEd’s 1999 sale of fossil generating assets and related to CTCs received by PECO. |
| (7) | Reflects incremental accelerated depreciation, inventory write-downs and severance costs associated with the planned retirement of four fossil generating units. |
| (8) | Primarily reflects the impact of increased unplanned nuclear outage days in the Mid-Atlantic region in 2010, including Salem. |
| (9) | Reflects the impact of higher nuclear fuel prices. |
| (10) | Primarily reflects the impact of a decrease in realized market prices for the sale of energy. |
| (11) | Reflects increased CTC revenues at PECO resulting in lower energy prices paid to Generation under the PPA. Generation and PECO’s marginal tax rate differences are reflected at Exelon Corporate. |
| (12) | Primarily reflects increased collection activities at ComEd. |
| (13) | Reflects a credit for the recovery of 2008 and 2009 bad debt expense pursuant to the ICC’s February 2010 approval of a bad debt rider, partially offset by a contribution mandated by Illinois legislation. |
| (14) | Primarily reflects the impact of increased wages and incentive compensation, as well as the impact of inflation related to contracting and materials expense (exclusive of incremental storm costs as disclosed in number 15 below). |
| (15) | Primarily reflects increased storm costs in the ComEd and PECO service territories and increased costs associated with Exelon Transmission Company at Corporate, partially offset by reduced stock-based compensation costs across the operating companies and the 2010 impact of a nuclear insurance credit at Generation. |
| (16) | Primarily reflects the impact of a lower assumed discount rate used in 2010 as compared to 2009 to calculate the pension and other postretirement benefit obligations and costs. |
| (17) | Primarily reflects increased depreciation expense across the operating companies due to ongoing capital expenditures and the impact of a first quarter 2010 depreciation study at Generation. |
| (18) | Reflects increased scheduled amortization expense of CTCs at PECO, which became fully amortized at the end of the transition period on December 31, 2010. |
| (19) | Primarily reflects an increase in Generation’s tax benefits associated with an increase in the manufacturing deduction rate, partially offset by the incremental impact on the 2010 manufacturing tax deduction associated with the pension contribution to be made in the first quarter of 2011. |
| (20) | Primarily reflects lower interest expense at PECO and Exelon Corporate due to lower outstanding debt, partially offset by higher interest expense at Generation due to higher outstanding debt. |
| (21) | Primarily reflects realized gains associated with NDT funds at Generation as a result of favorable market conditions in 2010 and projected refunds related to Illinois electric distribution taxes at ComEd, partially offset by increased gross receipts tax at PECO. |
| (22) | Reflects a non-cash charge related to the passage of Federal health care legislation that reduces the deductibility of retiree prescription drug benefits for Federal income tax purposes to the extent they are reimbursed under Medicare Part D. |
| (23) | Reflects the impairment of certain SO2 emission allowances as a result of declining market prices since the release of the EPA’s proposed Transport Rule during the third quarter of 2010. |
| (24) | Reflects external costs incurred associated with Exelon’s acquisition of JDR (now known as Exelon Wind). |
10
EXELON CORPORATION
Reconciliation of Adjusted (non-GAAP) Operating Earnings to
GAAP Consolidated Statements of Operations
(unaudited)
(in millions)
| Generation | ||||||||||||||||||||||||
| Three Months Ended December 31, 2010 | Three Months Ended December 31, 2009 | |||||||||||||||||||||||
| GAAP (a) | Adjustments | Adjusted Non- GAAP |
GAAP (a) | Adjustments | Adjusted Non- GAAP |
|||||||||||||||||||
| Operating revenues |
$ | 2,596 | $ | 6 | (b) | $ | 2,602 | $ | 2,278 | $ | 20 | (b) | $ | 2,298 | ||||||||||
| Operating expenses |
||||||||||||||||||||||||
| Purchased power |
602 | (145 | )(c) | 457 | 375 | (36 | )(c) | 339 | ||||||||||||||||
| Fuel |
418 | (41 | )(c) | 377 | 300 | 78 | (c) | 378 | ||||||||||||||||
| Operating and maintenance |
731 | (13 | )(d),(e) | 718 | 727 | (24 | )(e) | 703 | ||||||||||||||||
| Depreciation and amortization |
129 | (23 | )(e) | 106 | 110 | (32 | )(e) | 78 | ||||||||||||||||
| Taxes other than income |
56 | — | 56 | 55 | — | 55 | ||||||||||||||||||
| Total operating expenses |
1,936 | (222 | ) | 1,714 | 1,567 | (14 | ) | 1,553 | ||||||||||||||||
| Operating income |
660 | 228 | 888 | 711 | 34 | 745 | ||||||||||||||||||
| Other income and deductions |
||||||||||||||||||||||||
| Interest expense |
(44 | ) | — | (44 | ) | (36 | ) | — | (36 | ) | ||||||||||||||
| Other, net |
118 | (83 | )(f) | 35 | 50 | (28 | )(f),(g) | 22 | ||||||||||||||||
| Total other income and deductions |
74 | (83 | ) | (9 | ) | 14 | (28 | ) | (14 | ) | ||||||||||||||
| Income before income taxes |
734 | 145 | 879 | 725 | 6 | 731 | ||||||||||||||||||
| Income taxes |
310 | |
31 |
(b),(c),(d), (e),(f) |
341 | 300 | |
(10) |
(b),(c),(e),(f), (g) |
290 | ||||||||||||||
| Net income |
$ | 424 | $ | 114 | $ | 538 | $ | 425 | $ | 16 | $ | 441 | ||||||||||||
| Twelve Months Ended December 31, 2010 | Twelve Months Ended December 31, 2009 | |||||||||||||||||||||||
| GAAP (a) | Adjustments | Adjusted Non- GAAP |
GAAP (a) | Adjustments | Adjusted Non- GAAP |
|||||||||||||||||||
| Operating revenues |
$ | 10,025 | $ | 21 | (b) | $ | 10,046 | $ | 9,703 | $ | 98 | (b) | $ | 9,801 | ||||||||||
| Operating expenses |
||||||||||||||||||||||||
| Purchased power |
1,853 | (3 | )(c) | 1,850 | 1,338 | 94 | (c) | 1,432 | ||||||||||||||||
| Fuel |
1,610 | 32 | (c),(h) | 1,642 | 1,594 | 87 | (c) | 1,681 | ||||||||||||||||
| Operating and maintenance |
2,812 | (18 | )(d),(e),(i) | 2,794 | 2,938 | (207 | )(e),(k),(l),(m) | 2,731 | ||||||||||||||||
| Depreciation and amortization |
474 | (80 | )(e) | 394 | 333 | (32 | )(e) | 301 | ||||||||||||||||
| Taxes other than income |
230 | — | 230 | 205 | — | 205 | ||||||||||||||||||
| Total operating expenses |
6,979 | (69 | ) | 6,910 | 6,408 | (58 | ) | 6,350 | ||||||||||||||||
| Operating income |
3,046 | 90 | 3,136 | 3,295 | 156 | 3,451 | ||||||||||||||||||
| Other income and deductions |
||||||||||||||||||||||||
| Interest expense |
(153 | ) | — | (153 | ) | (113 | ) | 2 | (g) | (111 | ) | |||||||||||||
| Loss in equity method investments |
— | — | — | (3 | ) | — | (3 | ) | ||||||||||||||||
| Other, net |
257 | (155 | )(f) | 102 | 376 | (320 | )(f),(g),(n) | 56 | ||||||||||||||||
| Total other income and deductions |
104 | (155 | ) | (51 | ) | 260 | (318 | ) | (58 | ) | ||||||||||||||
| Income before income taxes |
3,150 | (65 | ) | 3,085 | 3,555 | (162 | ) | 3,393 | ||||||||||||||||
| Income taxes |
1,178 | |
(21) |
(b),(c),(d),(e), (f),(h),(i),(j) |
1,157 | 1,433 | |
(132) |
(b),(c),(e), (f),(g),(k),(l), (m),(n) |
1,301 | ||||||||||||||
| Net income |
$ | 1,972 | $ | (44 | ) | $ | 1,928 | $ | 2,122 | $ | (30 | ) | $ | 2,092 | ||||||||||
| (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 costs associated with Exelon’s acquisition of JDR (now known as Exelon Wind). |
| (e) | Adjustment to exclude costs associated with the planned retirement of fossil generating units. |
| (f) | Adjustment to exclude unrealized gains in 2010 and 2009 associated with Generation’s NDT fund investments to the extent not offset by contractual accounting as described in the notes to the consolidated financial statements. |
| (g) | Adjustment to exclude costs associated with early debt retirements. |
| (h) | Adjustment to exclude a non-cash charge for the impairment of certain SO2 emission allowances as a result of declining market prices since the release of the EPA’s proposed Transport Rule in the third quarter of 2010. |
| (i) | Adjustment to exclude a non-cash charge related to the passage of Federal health care legislation that reduces the deductibility of retiree prescription drug benefits for Federal income tax purposes to the extent they are reimbursed under Medicare Part D. |
| (j) | Adjustment to exclude a 2010 remeasurement of income tax uncertainties. |
| (k) | Adjustment to exclude a decrease in 2009 in Generation’s decommissioning obligation. |
| (l) | Adjustment to exclude 2009 charges associated with the elimination of management and staff positions. |
| (m) | Adjustment to exclude a non-cash charge for the impairment of certain of Generation’s Texas plants. |
| (n) | 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 December 31, 2010 | Three Months Ended December 31, 2009 | |||||||||||||||||||||||
| GAAP (a) | Adjustments | Adjusted
Non- GAAP |
GAAP (a) | Adjustments | Adjusted
Non- GAAP |
|||||||||||||||||||
| Operating revenues |
$ | 1,372 | $ | — | $ | 1,372 | $ | 1,357 | $ | 12 | (d),(e) | $ | 1,369 | |||||||||||
| Operating expenses |
||||||||||||||||||||||||
| Purchased power |
671 | — | 671 | 692 | — | 692 | ||||||||||||||||||
| Operating and maintenance |
247 | 10 | (c) | 257 | 232 | — | 232 | |||||||||||||||||
| Operating and maintenance |
27 | — | 27 | 19 | — | 19 | ||||||||||||||||||
| Depreciation and amortization |
130 | — | 130 | 123 | — | 123 | ||||||||||||||||||
| Taxes other than income |
68 | — | 68 | 67 | — | 67 | ||||||||||||||||||
| Total operating expenses |
1,143 | 10 | 1,153 | 1,133 | — | 1,133 | ||||||||||||||||||
| Operating income |
229 | (10 | ) | 219 | 224 | 12 | 236 | |||||||||||||||||
| Other income and deductions |
||||||||||||||||||||||||
| Interest expense |
(86 | ) | — | (86 | ) | (78 | ) | — | (78 | ) | ||||||||||||||
| Other, net |
10 | — | 10 | 11 | — | 11 | ||||||||||||||||||
| Total other income and |
(76 | ) | — | (76 | ) | (67 | ) | — | (67 | ) | ||||||||||||||
| Income before income taxes |
153 | (10 | ) | 143 | 157 | 12 | 169 | |||||||||||||||||
| Income taxes |
62 | (4 | )(c) | 58 | 59 | 5 | (d),(e) | 64 | ||||||||||||||||
| Net income |
$ | 91 | $ | (6 | ) | $ | 85 | $ | 98 | $ | 7 | $ | 105 | |||||||||||
| Twelve Months Ended December 31, 2010 | Twelve Months Ended December 31, 2009 | |||||||||||||||||||||||
| GAAP (a) | Adjustments | Adjusted
Non- GAAP |
GAAP (a) | Adjustments | Adjusted
Non- GAAP |
|||||||||||||||||||
| Operating revenues |
$ | 6,204 | $ | 4 | (d),(e) | $ | 6,208 | $ | 5,774 | $ | 16 | (d),(e) | $ | 5,790 | ||||||||||
| Operating expenses |
||||||||||||||||||||||||
| Purchased power |
3,307 | — | 3,307 | 3,065 | — | 3,065 | ||||||||||||||||||
| Operating and maintenance |
975 | 7 | (c),(f) | 982 | 1,028 | (20 | )(d),(h) | 1,008 | ||||||||||||||||
| Operating and maintenance |
94 | 94 | 63 | — | 63 | |||||||||||||||||||
| Depreciation and amortization |
516 | — | 516 | 494 | — | 494 | ||||||||||||||||||
| Taxes other than income |
256 | — | 256 | 281 | — | 281 | ||||||||||||||||||
| Total operating expenses |
5,148 | 7 | 5,155 | 4,931 | (20 | ) | 4,911 | |||||||||||||||||
| Operating income |
1,056 | (3 | ) | 1,053 | 843 | 36 | 879 | |||||||||||||||||
| Other income and deductions |
||||||||||||||||||||||||
| Interest expense |
(386 | ) | 59 | (g) | (327 | ) | (319 | ) | (6 | )(g) | (325 | ) | ||||||||||||
| Other, net |
24 | — | 24 | 79 | (60 | )(g) | 19 | |||||||||||||||||
| Total other income and |
(362 | ) | 59 | (303 | ) | (240 | ) | (66 | ) | (306 | ) | |||||||||||||
| Income before income taxes |
694 | 56 | 750 | 603 | (30 | ) | 573 | |||||||||||||||||
| Income taxes |
357 |
|
(59 |
(c),(d), )(e),(f),(g) |
298 | 229 |
|
(12 |
(d),(e), )(g),(h) |
217 | ||||||||||||||
| Net income |
$ | 337 | $ | 115 | $ | 452 | $ | 374 | $ | (18 | ) | $ | 356 | |||||||||||
| (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. |
| (c) | Adjustment to exclude a decrease in 2010 in ComEd’s asset retirement obligation. |
| (d) | Adjustment to exclude the impact of the 2007 Illinois electric rate settlement. |
| (e) | Adjustment to exclude costs associated with ComEd’s 2007 settlement agreement with the City of Chicago. |
| (f) | Adjustment to exclude a non-cash charge related to the passage of Federal health care legislation that reduces the deductibility of retiree prescription drug benefits for Federal income tax purposes to the extent they are reimbursed under Medicare Part D. |
| (g) | Adjustment to exclude 2010 and 2009 remeasurements of income tax uncertainties. |
| (h) | Adjustment to exclude 2009 charges associated with the elimination of management and staff positions. |
12
EXELON CORPORATION
Reconciliation of Adjusted (non-GAAP) Operating Earnings to
GAAP Consolidated Statements of Operations
(unaudited)
(in millions)
| PECO | ||||||||||||||||||||||||
| Three Months Ended December 31, 2010 | Three Months Ended December 31, 2009 | |||||||||||||||||||||||
| GAAP (a) | Adjustments | Adjusted Non- GAAP |
GAAP (a) | Adjustments | Adjusted Non- GAAP |
|||||||||||||||||||
| Operating revenues |
$ | 1,299 | $ | — | $ | 1,299 | $ | 1,266 | $ | — | $ | 1,266 | ||||||||||||
| Operating expenses |
||||||||||||||||||||||||
| Purchased power |
652 | — | 652 | 532 | — | 532 | ||||||||||||||||||
| Fuel |
123 | — | 123 | 126 | — | 126 | ||||||||||||||||||
| Operating and maintenance |
172 | 1 | (c) | 173 | 159 | — | 159 | |||||||||||||||||
| Operating and maintenance for regulatory required programs (b) |
17 | — | 17 | — | — | — | ||||||||||||||||||
| Depreciation and amortization |
201 | — | 201 | 225 | — | 225 | ||||||||||||||||||
| Taxes other than income |
64 | — | 64 | 64 | — | 64 | ||||||||||||||||||
| Total operating expenses |
1,229 | 1 | 1,230 | 1,106 | — | 1,106 | ||||||||||||||||||
| Operating income |
70 | (1 | ) | 69 | 160 | — | 160 | |||||||||||||||||
| Other income and deductions |
||||||||||||||||||||||||
| Interest expense |
(34 | ) | — | (34 | ) | (42 | ) | — | (42 | ) | ||||||||||||||
| Loss in equity method investments |
— | — | — | (5 | ) | — | (5 | ) | ||||||||||||||||
| Other, net |
2 | — | 2 | 5 | — | 5 | ||||||||||||||||||
| Total other income and deductions |
(32 | ) | — | (32 | ) | (42 | ) | — | (42 | ) | ||||||||||||||
| Income before income taxes |
38 | (1 | ) | 37 | 118 | — | 118 | |||||||||||||||||
| Income taxes |
17 | — | (c) | 17 | 40 | — | 40 | |||||||||||||||||
| Net income |
$ | 21 | $ | (1 | ) | $ | 20 | $ | 78 | $ | — | $ | 78 | |||||||||||
| Twelve Months Ended December 31, 2010 | Twelve Months Ended December 31, 2009 | |||||||||||||||||||||||
| GAAP (a) | Adjustments | Adjusted Non- GAAP |
GAAP (a) | Adjustments | Adjusted Non- GAAP |
|||||||||||||||||||
| Operating revenues |
$ | 5,519 | $ | — | $ | 5,519 | $ | 5,311 | $ | — | $ | 5,311 | ||||||||||||
| Operating expenses |
||||||||||||||||||||||||
| Purchased power |
2,361 | — | 2,361 | 2,274 | — | 2,274 | ||||||||||||||||||
| Fuel |
401 | — | 401 | 472 | — | 472 | ||||||||||||||||||
| Operating and maintenance |
680 | (1 | )(c),(d) | 679 | 640 | (3 | )(f) | 637 | ||||||||||||||||
| Operating and maintenance for regulatory required programs (b) |
53 | — | 53 | — | — | — | ||||||||||||||||||
| Depreciation and amortization |
1,060 | — | 1,060 | 952 | — | 952 | ||||||||||||||||||
| Taxes other than income |
303 | — | 303 | 276 | — | 276 | ||||||||||||||||||
| Total operating expenses |
4,858 | (1 | ) | 4,857 | 4,614 | (3 | ) | 4,611 | ||||||||||||||||
| Operating income |
661 | 1 | 662 | 697 | 3 | 700 | ||||||||||||||||||
| Other income and deductions |
||||||||||||||||||||||||
| Interest expense |
(193 | ) | 36 | (e) | (157 | ) | (187 | ) | — | (187 | ) | |||||||||||||
| Loss in equity method investments |
— | — | — | (24 | ) | — | (24 | ) | ||||||||||||||||
| Other, net |
8 | 2 | (e) | 10 | 13 | — | 13 | |||||||||||||||||
| Total other income and deductions |
(185 | ) | 38 | (147 | ) | (198 | ) | — | (198 | ) | ||||||||||||||
| Income before income taxes |
476 | 39 | 515 | 499 | 3 | 502 | ||||||||||||||||||
| Income taxes |
152 | 8 | (c),(d),(e) | 160 | 146 | 2 | (f) | 148 | ||||||||||||||||
| Net income |
$ | 324 | $ | 31 | $ | 355 | $ | 353 | $ | 1 | $ | 354 | ||||||||||||
| (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. |
| (c) | Adjustment to exclude a decrease in 2010 PECO’s asset retirement obligation. |
| (d) | Adjustment to exclude a non-cash charge related to the passage of Federal health care legislation that reduces the deductibility of retiree prescription drug benefits for Federal income tax purposes to the extent they are reimbursed under Medicare Part D. |
| (e) | Adjustment to exclude a 2010 remeasurement of income tax uncertainties. |
| (f) | Adjustment to exclude 2009 charges associated with the elimination of management and staff positions. |
13
EXELON CORPORATION
Reconciliation of Adjusted (non-GAAP) Operating Earnings to
GAAP Consolidated Statements of Operations
(unaudited)
(in millions)
| Other | ||||||||||||||||||||||||
| Three Months Ended December 31, 2010 | Three Months Ended December 31, 2009 | |||||||||||||||||||||||
| GAAP (a) | Adjustments | Adjusted Non- GAAP |
GAAP (a) | Adjustments | Adjusted
Non- GAAP |
|||||||||||||||||||
| Operating revenues |
$ | (773 | ) | $ | — | $ | (773 | ) | $ | (785 | ) | $ | — | $ | (785 | ) | ||||||||
| Operating expenses |
||||||||||||||||||||||||
| Purchased power |
(773 | ) | — | (773 | ) | (784 | ) | — | (784 | ) | ||||||||||||||
| Fuel |
— | — | — | (1 | ) | — | (1 | ) | ||||||||||||||||
| Operating and maintenance |
10 | — | 10 | 2 | — | 2 | ||||||||||||||||||
| Depreciation and amortization |
5 | — | 5 | 16 | — | 16 | ||||||||||||||||||
| Taxes other than income |
5 | — | 5 | 1 | — | 1 | ||||||||||||||||||
| Total operating expenses |
(753 | ) | — | (753 | ) | (766 | ) | — | (766 | ) | ||||||||||||||
| Operating loss |
(20 | ) | — | (20 | ) | (19 | ) | — | (19 | ) | ||||||||||||||
| Other income and deductions |
||||||||||||||||||||||||
| Interest expense |
(19 | ) | — | (19 | ) | (20 | ) | — | (20 | ) | ||||||||||||||
| Loss in equity method investments |
— | — | — | (1 | ) | — | (1 | ) | ||||||||||||||||
| Other, net |
5 | — | 5 | (6 | ) | 10 | (b) | 4 | ||||||||||||||||
| Total other income and deductions |
(14 | ) | — | (14 | ) | (27 | ) | 10 | (17 | ) | ||||||||||||||
| Loss before income taxes |
(34 | ) | — | (34 | ) | (46 | ) | 10 | (36 | ) | ||||||||||||||
| Income taxes |
(22 | ) | — | (22 | ) | (26 | ) | 4 | (b) | (22 | ) | |||||||||||||
| Net loss |
$ | (12 | ) | $ | — | $ | (12 | ) | $ | (20 | ) | $ | 6 | $ | (14 | ) | ||||||||
| Twelve Months Ended December 31, 2010 | Twelve Months Ended December 31, 2009 | |||||||||||||||||||||||
| GAAP (a) | Adjustments | Adjusted Non- GAAP |
GAAP (a) | Adjustments | Adjusted Non- GAAP |
|||||||||||||||||||
| Operating revenues |
$ | (3,104 | ) | $ | — | $ | (3,104 | ) | $ | (3,469 | ) | $ | — | $ | (3,469 | ) | ||||||||
| Operating expenses |
||||||||||||||||||||||||
| Purchased power |
(3,096 | ) | — | (3,096 | ) | (3,462 | ) | — | (3,462 | ) | ||||||||||||||
| Fuel |
(1 | ) | — | (1 | ) | — | — | — | ||||||||||||||||
| Operating and maintenance |
(14 | ) | 8 | (c) | (6 | ) | 6 | (35 | )(e),(f) | (29 | ) | |||||||||||||
| Depreciation and amortization |
25 | — | 25 | 55 | — | 55 | ||||||||||||||||||
| Taxes other than income |
19 | — | 19 | 16 | — | 16 | ||||||||||||||||||
| Total operating expenses |
(3,067 | ) | 8 | (3,059 | ) | (3,385 | ) | (35 | ) | (3,420 | ) | |||||||||||||
| Operating loss |
(37 | ) | (8 | ) | (45 | ) | (84 | ) | 35 | (49 | ) | |||||||||||||
| Other income and deductions |
||||||||||||||||||||||||
| Interest expense |
(85 | ) | 8 | (d) | (77 | ) | (112 | ) | 16 | (b),(d) | (96 | ) | ||||||||||||
| Other, net |
23 | — | 23 | (42 | ) | 56 | (b),(d) | 14 | ||||||||||||||||
| Total other income and deductions |
(62 | ) | 8 | (54 | ) | (154 | ) | 72 | (82 | ) | ||||||||||||||
| Loss before income taxes |
(99 | ) | — | (99 | ) | (238 | ) | 107 | (131 | ) | ||||||||||||||
| Income taxes |
(29 | ) | (24 | )(c),(d) | (53 | ) | (96 | ) | 44 | (b),(d),(e),(f) | (52 | ) | ||||||||||||
| Net loss |
$ | (70 | ) | $ | 24 | $ | (46 | ) | $ | (142 | ) | $ | 63 | $ | (79 | ) | ||||||||
| (a) | Results reported in accordance with GAAP. |
| (b) | Adjustment to exclude costs associated with early debt retirements. |
| (c) | Adjustment to exclude a non-cash charge related to the passage of Federal health care legislation that reduces the deductibility of retiree prescription drug benefits for Federal income tax purposes to the extent they are reimbursed under Medicare Part D. |
| (d) | Adjustment to exclude 2010 and 2009 remeasurements of income tax uncertainties. |
| (e) | Adjustment to exclude external costs associated with Exelon’s proposed acquisition of NRG, which was terminated in July 2009. |
| (f) | Adjustment to exclude 2009 charges associated with the elimination of management and staff positions. |
14
EXELON CORPORATION
Exelon Generation Statistics
| Three Months Ended | ||||||||||||||||||||
| Dec. 31, 2010 | Sept. 30, 2010 | Jun. 30, 2010 | Mar. 31, 2010 | Dec. 31, 2009 | ||||||||||||||||
| Supply (in GWhs) |
||||||||||||||||||||
| Nuclear Generation |
||||||||||||||||||||
| Mid-Atlantic (a) |
11,974 | 12,076 | 11,691 | 11,776 | 11,137 | |||||||||||||||
| Midwest |
23,141 | 23,675 | 23,344 | 22,333 | 22,472 | |||||||||||||||
| Total Nuclear Generation |
35,115 | 35,751 | 35,035 | 34,109 | 33,609 | |||||||||||||||
| Fossil and Renewables |
||||||||||||||||||||
| Mid-Atlantic (b) |
2,115 | 2,582 | 2,175 | 2,564 | 1,986 | |||||||||||||||
| Midwest |
45 | 16 | 7 | — | — | |||||||||||||||
| South and West |
93 | 691 | 310 | 119 | 48 | |||||||||||||||
| Total Fossil and Renewables |
2,253 | 3,289 | 2,492 | 2,683 | 2,034 | |||||||||||||||
| Purchased Power |
||||||||||||||||||||
| Mid-Atlantic |
442 | 599 | 414 | 463 | 342 | |||||||||||||||
| Midwest |
1,776 | 1,774 | 1,568 | 1,914 | 1,991 | |||||||||||||||
| South and West |
2,632 | 4,084 | 2,695 | 2,701 | 2,851 | |||||||||||||||
| Total Purchased Power |
4,850 | 6,457 | 4,677 | 5,078 | 5,184 | |||||||||||||||
| Total Supply by Region |
||||||||||||||||||||
| Mid-Atlantic |
14,531 | 15,257 | 14,280 | 14,803 | 13,465 | |||||||||||||||
| Midwest |
24,962 | 25,465 | 24,919 | 24,247 | 24,463 | |||||||||||||||
| South and West |
2,725 | 4,775 | 3,005 | 2,820 | 2,899 | |||||||||||||||
| 42,218 | 45,497 | 42,204 | 41,870 | 40,827 | ||||||||||||||||
| Three Months Ended | ||||||||||||||||||||
| Dec. 31, 2010 | Sept. 30, 2010 | Jun. 30, 2010 | Mar. 31, 2010 | Dec. 31, 2009 | ||||||||||||||||
| Electric Sales (in GWhs) |
||||||||||||||||||||
| ComEd (c) |
— | — | 1,895 | 3,428 | 3,439 | |||||||||||||||
| PECO |
9,756 | 11,976 | 10,044 | 10,228 | 9,588 | |||||||||||||||
| Market and Retail (c) |
32,462 | 33,521 | 30,265 | 28,214 | 27,800 | |||||||||||||||
| Total Electric Sales (d)(e) |
42,218 | 45,497 | 42,204 | 41,870 | 40,827 | |||||||||||||||
| Average Margin ($/MWh) (f)(g) |
||||||||||||||||||||
| Mid-Atlantic |
$ | 51.75 | $ | 36.97 | $ | 40.83 | $ | 41.41 | $ | 43.15 | ||||||||||
| Midwest |
41.14 | 41.00 | 40.78 | 41.00 | 41.98 | |||||||||||||||
| South and West |
(10.64 | ) | (2.30 | ) | (14.31 | ) | (16.67 | ) | (14.49 | ) | ||||||||||
| Average Margin - Overall Portfolio |
$ | 41.45 | $ | 35.11 | $ | 36.87 | $ | 37.26 | $ | 38.36 | ||||||||||
| Around-the-clock Market Prices ($/MWh) (h) |
||||||||||||||||||||
| PJM West Hub |
$ | 43.65 | $ | 52.25 | $ | 43.21 | $ | 44.54 | $ | 37.31 | ||||||||||
| NiHub |
27.26 | 38.32 | 32.35 | 34.47 | 29.61 | |||||||||||||||
| ERCOT North Spark Spread |
(0.69 | ) | 8.25 | 1.52 | (0.02 | ) | (1.34 | ) | ||||||||||||
| (a) | Includes Generation’s proportionate share of the output of its nuclear generating plants, including Salem. |
| (b) | Includes New England generation. |
| (c) | ComEd line item represents sales under the 2006 ComEd Auction. Settlements of the ComEd swap and sales under the Request for Proposal (RFP) are included within Market and Retail sales. In addition, renewable energy credit sales to affiliates have been included within Market and Retail sales. |
| (d) | Excludes retail gas activity, trading portfolio and other operating revenue. |
| (e) | Total sales do not include trading volume of 740 GWhs, 1,077 GWhs, 889 GWhs, 920 GWhs and 1,599 GWhs for the three months ended December 31, 2010, September 30, 2010, June 30, 2010, March 31, 2010 and December 31, 2009, respectively. |
| (f) | Excludes the mark-to-market impact of Generation’s economic hedging activities. |
| (g) | Results of transactions with PECO and ComEd are included in the Mid-Atlantic and Midwest regions, respectively. |
| (h) | Represents the average for the quarter. |
15
EXELON CORPORATION
Exelon Generation Statistics
Twelve Months Ended December 31, 2010 and 2009
| December 31, 2010 |
December 31, 2009 |
|||||||
| Supply (in GWhs) |
||||||||
| Nuclear Generation |
||||||||
| Mid-Atlantic (a) |
47,517 | 47,866 | ||||||
| Midwest |
92,493 | 91,804 | ||||||
| Total Nuclear Generation |
140,010 | 139,670 | ||||||
| Fossil and Renewables |
||||||||
| Mid-Atlantic (b) |
9,436 | 8,938 | ||||||
| Midwest |
68 | 4 | ||||||
| South and West |
1,213 | 1,247 | ||||||
| Total Fossil and Renewables |
10,717 | 10,189 | ||||||
| Purchased Power |
||||||||
| Mid-Atlantic |
1,918 | 1,747 | ||||||
| Midwest |
7,032 | 7,738 | ||||||
| South and West |
12,112 | 13,721 | ||||||
| Total Purchased Power |
21,062 | 23,206 | ||||||
| Total Supply by Region |
||||||||
| Mid-Atlantic |
58,871 | 58,551 | ||||||
| Midwest |
99,593 | 99,546 | ||||||
| South and West |
13,325 | 14,968 | ||||||
| 171,789 | 173,065 | |||||||
| December 31, 2010 |
December 31, 2009 |
|||||||
| Electric Sales (in GWhs) |
||||||||
| ComEd (c) |
5,323 | 16,830 | ||||||
| PECO |
42,003 | 39,897 | ||||||
| Market and Retail (c) |
124,463 | 116,338 | ||||||
| Total Electric Sales (d)(e) |
171,789 | 173,065 | ||||||
| Average Margin ($/MWh) (f)(g) |
||||||||
| Mid-Atlantic |
$ | 42.67 | $ | 44.03 | ||||
| Midwest |
40.98 | 41.67 | ||||||
| South and West |
(9.83 | ) | (7.82 | ) | ||||
| Average Margin - Overall Portfolio |
$ | 37.62 | $ | 38.20 | ||||
| Around-the-clock Market Prices ($/MWh) (h) |
||||||||
| PJM West Hub |
$ | 45.93 | $ | 38.30 | ||||
| NiHub |
33.09 | 28.85 | ||||||
| ERCOT North Spark Spread |
2.31 | 0.35 | ||||||
| (a) | Includes Generation’s proportionate share of the output of its nuclear generating plants, including Salem. |
| (b) | Includes New England generation. |
| (c) | ComEd line item represents sales under the 2006 ComEd Auction. Settlements of the ComEd swap and sales under the RFP are included within Market and Retail sales. In addition, renewable energy credit sales to affiliates have been included within Market and Retail sales. |
| (d) | Excludes retail gas activity, trading portfolio and other operating revenue. |
| (e) | Total sales do not include trading volume of 3,625 GWhs and 7,578 GWhs for the years ended December 31, 2010 and 2009, respectively. |
| (f) | Excludes the mark-to-market impact of Generation’s economic hedging activities. |
| (g) | Results of transactions with PECO and ComEd are included in the Mid-Atlantic and Midwest regions, respectively. |
| (h) | Represents the average for the years ended December 31, 2010 and 2009, respectively. |
16
EXELON CORPORATION
ComEd Statistics
Three Months Ended December 31, 2010 and 2009
| Electric Deliveries (in GWhs) | Revenue (in millions) | |||||||||||||||||||||||||||
| 2010 | 2009 | % Change | Weather- Normal % Change |
2010 | 2009 | % Change | ||||||||||||||||||||||
| Retail Deliveries and Sales (a) |
||||||||||||||||||||||||||||
| Residential |
6,393 | 6,541 | (2.3 | )% | (4.1 | )% | $ | 761 | $ | 741 | 2.7 | % | ||||||||||||||||
| Small Commercial & Industrial |
7,929 | 7,897 | 0.4 | % | (1.5 | )% | 366 | 378 | (3.2 | )% | ||||||||||||||||||
| Large Commercial & Industrial |
6,725 | 6,505 | 3.4 | % | 1.9 | % | 91 | 93 | (2.2 | )% | ||||||||||||||||||
| Public Authorities & Electric Railroads |
346 | 329 | 5.2 | % | 2.9 | % | 14 | 15 | (6.7 | )% | ||||||||||||||||||
| Total Retail |
21,393 | 21,272 | 0.6 | % | (1.2 | )% | 1,232 | 1,227 | 0.4 | % | ||||||||||||||||||
| Other Revenue (b) |
140 | 130 | 7.7 | % | ||||||||||||||||||||||||
| Total Electric Revenue |
$ | 1,372 | $ | 1,357 | 1.1 | % | ||||||||||||||||||||||
| Purchased Power |
$ | 671 | $ | 692 | (3.0 | )% | ||||||||||||||||||||||
| % Change | ||||||||||||||||||||
| Heating and Cooling Degree-Days |
2010 | 2009 | Normal | From 2009 | From Normal | |||||||||||||||
| Heating Degree-Days |
2,292 | 2,264 | 2,278 | 1.2 | % | 0.6 | % | |||||||||||||
| Cooling Degree-Days |
15 | — | 7 | n/a | 114.3 | % | ||||||||||||||
Twelve Months Ended December 31, 2010 and 2009
| Electric Deliveries (in GWhs) | Revenue (in millions) | |||||||||||||||||||||||||||
| 2010 | 2009 | % Change | Weather- Normal % Change |
2010 | 2009 | % Change | ||||||||||||||||||||||
| Retail Deliveries and Sales (a) |
||||||||||||||||||||||||||||
| Residential |
29,171 | 26,621 | 9.6 | % | (1.2 | )% | $ | 3,549 | $ | 3,115 | 13.9 | % | ||||||||||||||||
| Small Commercial & Industrial |
32,904 | 32,234 | 2.1 | % | (0.6 | )% | 1,639 | 1,660 | (1.3 | )% | ||||||||||||||||||
| Large Commercial & Industrial |
27,717 | 26,668 | 3.9 | % | 2.6 | % | 397 | 387 | 2.6 | % | ||||||||||||||||||
| Public Authorities & Electric Railroads |
1,273 | 1,237 | 2.9 | % | 2.4 | % | 62 | 57 | 8.8 | % | ||||||||||||||||||
| Total Retail |
91,065 | 86,760 | 5.0 | % | 0.2 | % | 5,647 | 5,219 | 8.2 | % | ||||||||||||||||||
| Other Revenue (b) |
557 | 555 | 0.4 | % | ||||||||||||||||||||||||
| Total Electric Revenue |
$ | 6,204 | $ | 5,774 | 7.4 | % | ||||||||||||||||||||||
| Purchased Power |
$ | 3,307 | $ | 3,065 | 7.9 | % | ||||||||||||||||||||||
| % Change | ||||||||||||||||||||
| Heating and Cooling Degree-Days |
2010 | 2009 | Normal | From 2009 | From Normal | |||||||||||||||
| Heating Degree-Days |
5,991 | 6,429 | 6,362 | (6.8 | )% | (5.8 | )% | |||||||||||||
| Cooling Degree-Days |
1,181 | 589 | 855 | 100.5 | % | 38.1 | % | |||||||||||||
| Number of Electric Customers |
2010 | 2009 | ||||||||||||||||||
| Residential |
3,438,677 | 3,425,570 | ||||||||||||||||||
| Small Commercial & Industrial |
363,393 | 360,779 | ||||||||||||||||||
| Large Commercial & Industrial |
2,005 | 1,985 | ||||||||||||||||||
| Public Authorities & Electric Railroads |
5,078 | 5,008 | ||||||||||||||||||
| Total |
3,809,153 | 3,793,342 | ||||||||||||||||||
| (a) | Reflects delivery revenues and volumes from customers purchasing electricity directly from ComEd and customers purchasing electricity from a competitive electric generation supplier as all customers are assessed delivery charges. For customers purchasing electricity from ComEd, revenue also reflects the cost of energy. |
| (b) | Other revenue primarily includes transmission revenue from PJM Interconnection, LLC (PJM). |
17
EXELON CORPORATION
PECO Statistics
Three Months Ended December 31, 2010 and 2009
| Electric and Gas Deliveries | Revenue (in millions) | |||||||||||||||||||||||||||
| 2010 | 2009 | % Change | Weather- Normal % Change |
2010 | 2009 | % Change | ||||||||||||||||||||||
| Electric (in GWhs) |
||||||||||||||||||||||||||||
| Retail Deliveries and Sales (a) |
||||||||||||||||||||||||||||
| Residential |
3,124 | 3,088 | 1.2 | % | (0.7 | )% | $ | 444 | $ | 429 | 3.5 | % | ||||||||||||||||
| Small Commercial & Industrial |
1,958 | 1,965 | (0.4 | )% | (2.0 | )% | 233 | 232 | 0.4 | % | ||||||||||||||||||
| Large Commercial & Industrial |
3,975 | 3,878 | 2.5 | % | 1.5 | % | 327 | 312 | 4.8 | % | ||||||||||||||||||
| Public Authorities & Electric Railroads |
226 | 228 | (0.9 | )% | (0.3 | )% | 22 | 22 | 0.0 | % | ||||||||||||||||||
| Total Retail |
9,283 | 9,159 | 1.4 | % | (0.0 | )% | 1,026 | 995 | 3.1 | % | ||||||||||||||||||
| Other Revenue (b) |
61 | 59 | 3.4 | % | ||||||||||||||||||||||||
| Total Electric Revenue |
1,087 | 1,054 | 3.1 | % | ||||||||||||||||||||||||
| Gas (in mmcfs) |
||||||||||||||||||||||||||||
| Retail Sales |
19,730 | 17,659 | 11.7 | % | 0.7 | % | 205 | 202 | 1.5 | % | ||||||||||||||||||
| Transportation and Other |
7,253 | 7,078 | 2.5 | % | 2.2 | % | 7 | 10 | (30.0 | )% | ||||||||||||||||||
| Total Gas |
26,983 | 24,737 | 9.1 | % | 1.1 | % | 212 | 212 | 0.0 | % | ||||||||||||||||||
| Total Electric and Gas Revenues |
$ | 1,299 | $ | 1,266 | 2.6 | % | ||||||||||||||||||||||
| Purchased Power |
$ | 652 | $ | 532 | 22.6 | % | ||||||||||||||||||||||
| Fuel |
123 | 126 | (2.4 | )% | ||||||||||||||||||||||||
| Total Purchased Power and Fuel |
$ | 775 | $ | 658 | 17.8 | % | ||||||||||||||||||||||
| % Change | ||||||||||||||||||||
| Heating and Cooling Degree-Days |
2010 | 2009 | Normal | From 2009 | From Normal | |||||||||||||||
| Heating Degree-Days |
1,686 | 1,567 | 1,634 | 7.6 | % | 3.2 | % | |||||||||||||
| Cooling Degree-Days |
19 | 10 | 21 | 90.0 | % | (9.5 | %) | |||||||||||||
Twelve Months Ended December 31, 2010 and 2009
| Electric and Gas Deliveries | Revenue (in millions) | |||||||||||||||||||||||||||
| 2010 | 2009 | % Change | Weather- Normal % Change |
2010 | 2009 | % Change | ||||||||||||||||||||||
| Electric (in GWhs) |
||||||||||||||||||||||||||||
| Retail Deliveries and Sales (a) |
||||||||||||||||||||||||||||
| Residential |
13,913 | 12,893 | 7.9 | % | 0.5 | % | $ | 2,069 | $ | 1,859 | 11.3 | % | ||||||||||||||||
| Small Commercial & Industrial |
8,503 | 8,397 | 1.3 | % | (1.9 | )% | 1,060 | 1,034 | 2.5 | % | ||||||||||||||||||
| Large Commercial & Industrial |
16,372 | 15,848 | 3.3 | % | 0.8 | % | 1,362 | 1,307 | 4.2 | % | ||||||||||||||||||
| Public Authorities & Electric Railroads |
925 | 930 | (0.5 | )% | (0.3 | )% | 89 | 90 | (1.1 | )% | ||||||||||||||||||
| Total Retail |
39,713 | 38,068 | 4.3 | % | 0.1 | % | 4,580 | 4,290 | 6.8 | % | ||||||||||||||||||
| Other Revenue (b) |
255 | 259 | (1.5 | )% | ||||||||||||||||||||||||
| Total Electric Revenue |
4,835 | 4,549 | 6.3 | % | ||||||||||||||||||||||||
| Gas (in mmcfs) |
||||||||||||||||||||||||||||
| Retail Sales |
56,833 | 57,103 | (0.5 | )% | 0.9 | % | 656 | 732 | (10.4 | )% | ||||||||||||||||||
| Transportation and Other |
30,911 | 27,206 | 13.6 | % | 10.8 | % | 28 | 30 | (6.7 | )% | ||||||||||||||||||
| Total Gas |
87,744 | 84,309 | 4.1 | % | 4.1 | % | 684 | 762 | (10.2 | )% | ||||||||||||||||||
| Total Electric and Gas Revenues |
$ | 5,519 | $ | 5,311 | 3.9 | % | ||||||||||||||||||||||
| Purchased Power |
$ | 2,361 | $ | 2,274 | 3.8 | % | ||||||||||||||||||||||
| Fuel |
401 | 472 | (15.0 | )% | ||||||||||||||||||||||||
| Total Purchased Power and Fuel |
$ | 2,762 | $ | 2,746 | 0.6 | % | ||||||||||||||||||||||
| % Change | ||||||||||||||||||||
| Heating and Cooling Degree-Days |
2010 | 2009 | Normal | From 2009 | From Normal | |||||||||||||||
| Heating Degree-Days |
4,396 | 4,534 | 4,638 | (3.0 | )% | (5.2 | )% | |||||||||||||
| Cooling Degree-Days |
1,817 | 1,246 | 1,292 | 45.8 | % | 40.6 | % | |||||||||||||
| Number of Electric Customers |
2010 | 2009 | Number of Gas Customers |
2010 | 2009 | |||||||||||||
| Residential |
1,411,643 | 1,404,416 | Residential |
448,391 | 444,923 | |||||||||||||
| Small Commercial & Industrial |
156,865 | 156,305 | Commercial & Industrial |
41,303 | 40,991 | |||||||||||||
| Large Commercial & Industrial |
3,071 | 3,094 | Total Retail |
489,694 | 485,914 | |||||||||||||
| Public Authorities & Electric Railroads |
1,102 | 1,085 | Transportation |
838 | 778 | |||||||||||||
| Total |
1,572,681 | 1,564,900 | Total |
490,532 | 486,692 | |||||||||||||
| (a) | Reflects delivery revenues and volumes from customers purchasing electricity directly from PECO and customers purchasing electricity from a competitive electric generation supplier as all customers are assessed delivery charges and a CTC. For customers purchasing electricity from PECO, revenue should also reflects the cost of energy. |
| (b) | Other revenue includes transmission revenue from PJM and wholesale revenues. |
18
 Earnings Conference Call
4
th
Quarter 2010
January 26, 2011
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 2009 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 2010 Quarterly Report on Form 10-Q in (a) Part II, Other
Information, ITEM 1A. Risk Factors, (b) Part 1, Financial Information,
ITEM 2. Management’s Discussion and Analysis of Financial Condition and
Results of Operations and (c) Part I , Financial Information, ITEM 1. Financial
Statements: Note 13 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 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
of
non-GAAP cash flows to GAAP cash flows. |
 3
2010: Another Strong Year for Exelon
Exemplary year of financial
and operational performance
•
Operating earnings of
$4.06/share
(1)
•
2010 Cash from operations
of $5.3 billion
(2)
•
Returned $1.4 billion in cash
to shareholders through
dividends
Continuing to position Exelon
for cleaner energy future
Strong reliability scores despite significant storm
activity
Highest customer satisfaction scores in > 5 yrs
Completed electric and gas distribution rate cases
Best
customer
satisfaction
scores
in
PECO
history
Eighth consecutive year with nuclear capacity
factor above 93%
59 MW added through nuclear uprate program
Acquired John Deere Renewables
Announced early retirement of Oyster Creek
RITE line project announced
(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. (2)
2010 Cash from operations excludes counterparty collateral and includes net cash from investing
activities other than capital expenditures, acquisition of Exelon Wind and change in restricted
cash. |
 4
2011 Operating Earnings Guidance
2011E
(2)
2010A
$0.54
$2.91
$4.06
(1)
ComEd
PECO
Exelon
Generation
ComEd
PECO
Exelon
Generation
Holdco
Holdco
Exelon
$0.68
Exelon
$3.90 -
$4.20
(1)
$0.55 -
$0.65
$0.50 -
$0.55
$2.85 -
$3.05
Key Drivers of FY Guidance
+
Generation margins driven by PECO
PPA roll-off, partially offset by lower
capacity revenues
+
Higher PECO gross margin driven by
new distribution rates effective 1/1/11
-
Higher O&M expense
-
Higher depreciation & amortization
expense
Introducing
2011
operating
earnings
guidance
of
$3.90
–
$4.20/share
and
1Q
2011
guidance
of
$1.00
–
$1.10/share
(1)
(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. (2)
Earnings guidance for OpCos may not add up to consolidated EPS guidance.
|
 5
2017/
2018
2016/
2017
2015/
2016
2014/
2015
PJM RPM Auctions
Delivery Year
2010
2011
2012
2013
2014
2015
2016
2017
2018
EPA Regulations Will Move Forward in 2011
Notes: RPM auctions take place annually in May.
For definition of the EPA regulations referred to on this slide, please see the EPA’s Terms of
Environment (http://www.epa.gov/OCEPAterms/). |
 6
Key Financial Messages
2010
operating
earnings
of
$4.06/share
(1)
in
line
with
expectations
•
Higher capacity and energy (PECO PPA) revenues at ExGen
•
Higher earnings (vs. 2009) at ComEd
2011
earnings
guidance
of
$3.90
-
$4.20/share
(1)
•
Expiration
of
PECO
PPA
allows
ExGen
to
sell
additional
energy
at
market
prices,
offset by lower RPM capacity prices and higher costs
•
New distribution rates effective 1/1/11 at PECO
Strong cash flows in 2011
•
Expect to generate $4.3 billion cash from operations in 2011
•
Increasing investment in growth projects at ExGen and Utilities
Efficient use of cash benefits from bonus depreciation
•
$2.1 billion pension contribution proactively reduces pension costs and future
contributions while improving pension funding status
(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. |
 7
Exelon Generation
Operating EPS Contribution
2010
2009
(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.
97
136
Refueling
18
23
Non-refueling
4Q10
4Q09
Outage Days
(2)
4Q
YTD
$0.66
$3.16
$0.81
$2.91
Note: PPA = Power Purchase Agreement
Key Drivers –
4Q10 vs. 4Q09
(1)
Higher energy prices under the PECO
PPA, offset at PECO: $0.10
Favorable RPM capacity pricing: $0.07
Higher nuclear volume: $0.04
Higher nuclear fuel costs: $(0.02)
Higher depreciation expense: $(0.03) |
 8
0%
10%
20%
30%
40%
50%
60%
70%
80%
Q1 2010
Q2 2010
Q3 2010
Q4 2010
Underlying
Options
Ratable
Power Fundamentals & Hedging Update
Using our perspective on the markets to time
sales, thereby adding value
•
PJMW energy prices increased in 4Q 2010, driven by
higher eastern coal prices
•
NiHub energy prices and Henry Hub natural gas prices
remained relatively stable in 4Q 2010
•
Slowed down pace of hedging in Q3 & Q4 to recognize
future upside from environmental regulations and
economic recovery
Normal practice is to hedge commodity risk
on a ratable basis over three years
•
Maintain flexibility from quarter to quarter
•
Use gas and power put options to capture potential
upside while providing downside price protection
Exelon’s ratable hedging program provides flexibility to time sales based
on fundamental view of the market
2012 Historical Energy & Gas Prices
31.00
33.00
35.00
37.00
39.00
41.00
43.00
45.00
47.00
49.00
51.00
1/4/10
2/3/10
3/5/10
4/4/10
5/4/10
6/3/10
7/3/10
8/2/10
9/1/10
10/1/10
10/31/10
11/30/10
12/30/10
4.80
5.00
5.20
5.40
5.60
5.80
6.00
6.20
6.40
6.60
6.80
PJMWHub
NiHub
Henry Hub Nat Gas
2012 Quarterly Hedge Level vs. Ratable Plan
Note: % values represent amount
above ratable plan
10%
8%
11%
5% |
 9
Key Drivers –
4Q10 vs. 4Q09
(1)
Appellate Court ruling: $(0.02)
Higher O&M expense: $(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.
2010
2009
4Q
YTD
$0.16
$0.54
4Q10
Actual
Normal
% Change
Heating Degree-Days
2,292 2,278 0.6%
Cooling Degree-Days 15
7 114%
$0.13
$0.68 |
 10
10
ComEd Load Trends
Chicago
U.S.
Unemployment rate
(1)
9.3%
9.4%
2010 annualized growth in
gross
domestic/metro
product
(2)
1.6%
2.8% Note: C&I = Commercial &
Industrial Weather-Normalized Load Year-over-Year
Key Economic Indicators
Weather-Normalized Load
4Q10
2010 2011E
Average Customer Growth
0.4%
0.2%
0.5%
Average Use-Per-Customer
(4.5)%
(1.4)%
0.0%
Total Residential
(4.1)%
(1.2)% 0.5%
Small C&I
(1.5)%
(0.6)% (0.3)%
Large C&I
1.9%
2.6% (0.2)%
All Customer Classes
(1.2)%
0.2% 0.0%
(1)
Source: U.S. Dept. of Labor (December 2010) and Illinois
Department of Security (December 2010)
(2) Source: Global Insight December 2010
-6.0%
-3.0%
0.0%
3.0%
6.0%
1Q10
2Q10
3Q10
4Q10
1Q11
2Q11
3Q11
4Q11
-6.0%
-3.0%
0.0%
3.0%
6.0%
All Customer Classes
Large C&I
Residential
Gross Metro Product |
 11
PECO Operating EPS Contribution
Key Drivers –
4Q10 vs. 4Q09
(1)
Decreased CTC revenue resulting
in higher energy prices paid to
Generation under the PPA, offset
at Generation: $(0.10)
Weather: $0.01
CTC amortization $0.02
2010
2009
(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. 4Q
YTD
$0.12
$0.54
4Q10
$0.03
$0.54
Actual
Normal
% Change
Heating Degree-Days
1,686 1,634 3.2%
Cooling Degree-Days
19 21 (9.5)%
Note: CTC = Competitive Transition Charge |
 12
(1)
Source: U.S Dept. of Labor (PHL – November 2010 preliminary data,
US – December 2010)
(2)
Source: Global Insight December 2010
PECO Load Trends
Philadelphia
U.S.
Unemployment rate
(1)
8.4%
9.4% 2010 annualized growth in
gross
domestic/metro
product
(2)
2.8%
2.8% Note: C&I = Commercial & Industrial
Weather-Normalized Load Year-over-Year
Key Economic Indicators
Weather-Normalized Load
4Q10
2010 2011E
Average Customer Growth
0.5%
0.3%
0.4%
Average Use-Per-Customer
(1.2)%
0.3%
(0.3)%
Total Residential
(0.7)%
0.5% 0.1%
Small C&I
(2.0)%
(1.9)% (0.5)%
Large C&I
1.5%
0.8% 0.1%
All Customer Classes
0.0%
0.1% 0.0%
-5.0%
-2.5%
0.0%
2.5%
5.0%
1Q10
2Q10
3Q10
4Q10
1Q11E
2Q11E
3Q11E
4Q11E
-5.0%
-2.5%
0.0%
2.5%
5.0%
All Customer Classes
Large C&I
Residential
Gross Metro Product |
 $0.98
$0.68
$2.74
$2.91
$1.07
$0.71
2010A
2011E
PECO
ComEd
ExGen
Operating O&M Outlook
2010 to 2011 Drivers (per share)
Inflation $(0.08)
Full year of Exelon Wind $(0.05)
Two additional nuclear refueling
outages $(0.05)
ComEd uncollectibles
$(0.04)
Estimated
2011
O&M
represents
a
new
“base”
level
for
operating
O&M
$4.39B
$4.68B
2010 Operating O&M below 2008 levels for second consecutive year
One-time savings in 2010 included executive salary freezes and reduced
compensation benefits
Anticipate annual O&M growth rate of ~2% for 2011-2013
(1)
(1)
13
(1) Amounts may not add due to rounding. Refer to slide 44 for a reconciliation of GAAP O&M to
Operating O&M. |
 14
Pension and OPEB Expense and
Contributions –
As of 12/31/10
(1)
Pension expense amounts exclude settlement charges.
(2)
Note: Slide provided for illustrative purposes and not intended to represent a
forecast of future outcomes. Assumes an ~25% capitalization of pension and OPEB costs.
$190
$240
Pre-tax
expense
$205
$1,655
$3,875
$2,220
$765
$8,860
$12,525
$3,665
Actual
contribution
$210
$2,140
$225
$185
$2,180
$210
5.83% in 2010
5.30% in 2011
5.52% in 2012
11.6% in 2010
7.08% in 2011
7.08% in 2012
OPEB
Assets
Obligations
Unfunded balance –
end of year
$110
$1,015
$240
$2,100
$1,305
$200
5.83% in 2010
5.26% in 2011
5.48% in 2012
11.9% in 2010
8.0% in 2011
7.5% in 2012
Pension
Assets
Obligations
Unfunded balance –
end of year
Expected
contribution
Pre-tax
expense
Expected
contribution
Pre-tax
expense
Discount Rate
(used for
expense)
Asset Returns
(actual for 2010 and
expected for
2011 and 2012)
($ in millions)
Assumptions
2011
2012
2010
The decrease in pension expense in 2011 is primarily due to the $2.1 billion pension
contribution, partially offset by the impacts of lower discount rates and a
decrease in EROA Management considers various factors when making pension funding decisions,
including actuarially determined minimum contribution requirements under ERISA, contributions
required to avoid benefit restrictions and at-risk status as defined by the Pension Protection Act
of 2006 (the Act), management of the pension obligation and regulatory implications. The Act
requires the attainment of certain funding levels to avoid benefit restrictions (such as an inability to pay lump sums or to accrue benefits prospectively), and at-risk status
(which triggers higher minimum contribution requirements and participant notification). |
 15
2011 Pension Contribution
$2.1 billion contribution to pension in 2011
•
Timing:
~$850
million
funded
by
the
accelerated cash benefits generated as a
result of bonus depreciation
•
Tax
efficient:
Income
tax
deduction
of
pension contribution creates $750 million
of cash benefit
•
Economic:
Reduces
estimated
future
pension expense, lowers future minimum
funding requirements and reduces volatility
Improves financial flexibility
•
Creates debt capacity for future growth
•
Improves ability to weather commodity
cycle in 2012 and 2013 and maintain the
dividend
Contributes to improved pension funded
status of 71% at 12/31/10, projected to be
89% at 12/31/11
Pension Contributions
615
2,100
765
110
175
160
195
780
790
170
485
2010
2011
2012
2013
2014
2015
With $2.1B
Original Plan*
Pre-Tax Pension Expense
(1)
240
300
265
200
240
2010
2011
2012
(1) Assumes an ~25% capitalization rate.
$ millions
$ millions
*
Original Plan reflects preliminary 2010 underlying assumptions (including
discount rate and asset returns) |
 16
2011 Projected Sources and Uses of Cash
(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.
(3)
Assumes 2011 dividend of $2.10/share. Dividends are subject to declaration by
the Board of Directors. (4)
Includes $475 million in Nuclear Uprates and $225 million for Exelon Wind spend.
(5)
Represents new business, smart grid/smart meter investment and transmission growth
projects. (6)
Excludes ComEd’s $191 million of tax-exempt bonds that are backed by
letters of credit (LOCs). Excludes PECO’s $225 million Accounts Receivable (A/R) Agreement with Bank of Tokyo.
PECO’s A/R Agreement was extended in accordance with its terms through
September 6, 2011. (7)
“Other”
includes proceeds from options and expected changes in short-term debt.
(8) Includes cash flow activity from Holding Company, eliminations, and
other corporate entities. ($ millions)
Exelon
(8)
Beginning Cash Balance
(1)
$800
Cash Flow from Operations
(2)
425
775
3,150
4,325
CapEx (excluding Nuclear Fuel, Nuclear
Uprates, Exelon Wind, Utility Growth CapEx)
(700)
(325)
(850)
(1,875)
Nuclear Fuel
n/a
n/a
(1,025)
(1,025)
Dividend
(3)
(1,400)
Nuclear Uprates and Exelon Wind
(4)
n/a
n/a
(700)
(700)
Utility Growth CapEx
(5)
(325)
(125)
n/a
(450)
Net Financing (excluding Dividend):
Planned Debt Issuances
(6)
1,000
--
--
1,000
Planned Debt Retirements
(350)
(250)
--
(600)
Other
(7)
250
--
--
300
Ending Cash Balance
(1)
$375 |
 17
2011 Events of Interest
Q1
Q2
Q3
Q4
RPM Auction results
(5/13)
Illinois Power Agency
RFP (April)
ALJ Proposed Order
–
DST Rate Case
(3/31)
Procurement RFP
(bids due 5/23;
results by 6/23)
DST Rate Case Final
Order (by 5/31)
EPA Final HAP
Rule (November)
Retirement of Cromby
1 & Eddystone 1 units
(5/31)
Proposed HAP EPA
Regulation (by 3/16)
Procurement RFP
(bids due 9/19;
results by 10/19)
Retirement of
Cromby 2 unit
(12/31)
Proposed 316(b) EPA
Regulation (by 3/14)
EPA Final Transport
Rule (June)
For definition of the EPA regulations referred to on this slide, please see the EPA’s Terms of
Environment (http://www.epa.gov/OCEPAterms/). |
 18
Exelon Generation Hedging Disclosures
(as of December 31, 2010)
*********** |
 19
19
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
December
31,
2010.
We
update
this
information
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. |
      20
20
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
% Hedged
High End of Profit
Low End of Profit
Open Generation
with LT Contracts
Portfolio
Optimization
Portfolio
Management
Portfolio Management Over Time |
 21
21
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 |
 22
22
2011
2012
2013
Estimated Open Gross Margin ($ millions)
(1)(2)(3)
$5,200
$5,050
$5,700
Open gross margin assumes all expected generation is sold
at the Reference Prices listed below
Reference Prices
(1)
Henry Hub Natural Gas ($/MMBtu)
NI-Hub ATC Energy Price ($/MWh)
PJM-W ATC Energy Price ($/MWh)
ERCOT North ATC Spark Spread ($/MWh)
(4)
$4.56
$30.69
$45.45
$1.12
$5.08
$32.38
$46.41
$0.82
$5.33
$35.09
$48.25
$1.84
Exelon Generation Open Gross Margin and
Reference Prices
(1)
Based on December 31, 2010 market conditions.
(2)
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 revenues and payments. The estimation of open
gross margin incorporates management discretion and modeling assumptions that are
subject to change. (3)
As of December 31, 2010 disclosure, Exelon Wind included. Assets in IL,
MI and MN are in Midwest region and assets in ID, KS, MO, OR and TX are in South and West region.
(4)
ERCOT North ATC spark spread using Houston Ship Channel Gas, 7,200 heat rate, $2.50
variable O&M. |
 23
23
2011
2012
2013
Expected Generation
(GWh)
(1)
165,900
165,800
163,300
Midwest
99,600
98,500
96,200
Mid-Atlantic
56,800
57,200
56,500
South & West
9,500
10,100
10,600
Percentage
of
Expected
Generation
Hedged
(2)
90-93%
67-70%
32-35%
Midwest
91-94
69-72
31-34
Mid-Atlantic
93-96
67-70
36-39
South & West
70-73
51-54
39-42
Effective Realized Energy Price
($/MWh)
(3)
Midwest
$43.00
$41.50
$43.50
Mid-Atlantic
$57.00
$50.50
$51.50
South & West
$2.50
$(1.00)
$(3.50)
Generation Profile
(1)
Expected
generation
represents
the
amount
of
energy
estimated
to
be
generated
or
purchased
through
owned
or
contracted
for
capacity.
Expected
generation
is
based
upon
a
simulated
dispatch
model
that
makes
assumptions
regarding
future
market
conditions,which
are
calibrated
to
market
quotes
for
power,
fuel,
load
following
products,
and
options.
Expected
generation
assumes
12
refueling
outages
in
2011
and
10
refueling
outages
in
2012
and
2013
at
Exelon-operated
nuclear
plants
and
Salem.
Expected
generation
assumes
capacity
factors
of
93.0%,
93.6%
and
93.1%
in
2011,
2012
and
2013
at
Exelon-operated
nuclear
plants.
These
estimates
of
expected
generation
in
2012
and
2013
do
not
represent guidance or a
forecast of future results as Exelon has not completed its planning or optimization
processes for those years. (2)
Percent of expected generation hedged is the amount of equivalent sales divided by
the expected generation. Includes all hedging products, such as wholesale and retail sales of power,
options, and swaps. Uses expected value on options. Reflects decision to
permanently retire Cromby Station and Eddystone Units 1&2 as of May 31, 2011.
(3)
Effective realized energy price is representative of an all-in hedged price, on
a per MWh basis, at which expected generation has been hedged. It is developed by considering the energy
revenues
and
costs
associated
with
our
hedges
and
by
considering
the
fossil
fuel
that
has
been
purchased
to
lock
in
margin.
It
excludes
uranium
costs
and
RPM
capacity
revenue,
but
includes
the
mark-to-market
value
of
capacity
contracted
at
prices
other
than
RPM
clearing
prices
including
our
load
obligations.
It
can
be
compared
with
the
reference
prices
used
to
calculate open gross margin in order to determine the mark-to-market value
of Exelon Generation's energy hedges. |
 24
24
Gross Margin Sensitivities with Existing Hedges ($ 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%
2011
$5
$(5)
$30
$(20)
$15
$(10)
+/-
$40
2012
$175
$(95)
$185
$(165)
$115
$(110)
+/-
$45
2013
$495
$(445)
$340
$(335)
$200
$(195)
+/-
$50
Exelon Generation Gross Margin Sensitivities
(with Existing Hedges)
(1)
Based on December 31, 2010 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. |
 25
25
95% case
5% case
$5,400
$7,100
$6,800
$6,300
Exelon Generation Gross Margin Upside / Risk
(with Existing Hedges)
$3,000
$4,000
$5,000
$6,000
$7,000
$8,000
$9,000
2011
2012
(1)
Represents
an
approximate
range
of
expected
gross
margin,
taking
into
account
hedges
in
place,
between
the
5th
and
95th
percent
confidence
levels
assuming
all
unhedged
supply
is
sold
into
the
spot
market.
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
2012
and
2013
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
December
31,
2010.
$7,200
$5,000
2013 |
 26
26
Midwest
Mid-Atlantic
South & West
Step 1
Start
with
fleetwide
open
gross
margin
$5.20 billion
Step 2
Determine the mark-to-market value
of
energy hedges
99,600GWh * 92% *
($43.00/MWh-$30.69MWh)
= $1.13 billion
56,800GWh * 94% *
($57.00/MWh-$45.45MWh)
= $0.62 billion
9,500GWh * 71% *
($2.50/MWh-$1.12/MWh)
= $0.01 billion
Step 3
Estimate
hedged
gross
margin
by
adding open gross margin to mark-to-
market value of energy hedges
Open gross
margin: $5.20 billion
MTM value of energy
hedges: $1.13billion + $0.62billion + $0.01 billion
Estimated hedged gross margin:
$6.96 billion
Illustrative Example
of Modeling Exelon Generation 2011 Gross Margin
(with Existing Hedges) |
 27
35
40
45
50
55
60
65
70
75
1/10
2/10
3/10
4/10
5/10
6/10
7/10
8/10
9/10
10/10
11/10
12/10
1/11
4.0
4.5
5.0
5.5
6.0
6.5
7.0
7.5
8.0
1/10
2/10
3/10
4/10
5/10
6/10
7/10
8/10
9/10
10/10
11/10
12/10
1/11
27
27
20
25
30
35
40
45
1/10
2/10
3/10
4/10
5/10
6/10
7/10
8/10
9/10
10/10
11/10
12/10
1/11
50
55
60
65
70
75
80
85
90
1/10
2/10
3/10
4/10
5/10
6/10
7/10
8/10
9/10
10/10
11/10
12/10
1/11
Market Price Snapshot
Forward NYMEX Natural Gas
PJM-West and Ni-Hub On-Peak Forward Prices
PJM-West and Ni-Hub Wrap Forward Prices
2012
$5.54
2013 $5.79
Rolling
12
months,
as
of
January
20
,
2011.
Source:
OTC
quotes
and
electronic
trading
system.
Quotes
are
daily.
Forward NYMEX Coal
2012
$75.61
2013
$79.57
2012 Ni-Hub $41.35
2013 Ni-Hub
$43.48
2013 PJM-West $55.12
2012 PJM-West
$53.08
2012 Ni-Hub
$25.78
2013 Ni-Hub
$28.06
2013 PJM-West
$40.79
2012 PJM-West
$38.84
th |
 28
28
28
4.5
5.5
6.5
7.5
8.5
9.5
10.5
11.5
12.5
13.5
1/10
2/10
3/10
4/10
5/10
6/10
7/10
8/10
9/10
10/10
11/10
12/10
1/11
8.0
8.2
8.4
8.6
8.8
9.0
9.2
9.4
9.6
9.8
10.0
1/10
2/10
3/10
4/10
5/10
6/10
7/10
8/10
9/10
10/10
11/10
12/10
1/11
35
40
45
50
55
60
65
70
1/10
2/10
3/10
4/10
5/10
6/10
7/10
8/10
9/10
10/10
11/10
12/10
1/11
3.5
4.0
4.5
5.0
5.5
6.0
6.5
7.0
7.5
8.0
1/10
2/10
3/10
4/10
5/10
6/10
7/10
8/10
9/10
10/10
11/10
12/10
1/11
Market Price Snapshot
2013
9.29
2012
9.10
2012
$49.40
2013
$52.75
2012
$5.43
2013
$5.67
Houston Ship Channel Natural Gas
Forward Prices
ERCOT North On-Peak Forward Prices
ERCOT North On-Peak v. Houston Ship Channel
Implied Heat Rate
2012
$7.72
2013
$9.30
ERCOT North On Peak Spark Spread
Assumes a 7.2 Heat Rate, $1.50 O&M, and $.15 adder
Rolling
12
months,
as
of
January
20
,
2011.
Source:
OTC
quotes
and
electronic
trading
system.
Quotes
are
daily.
th |
 29
Appendix
************************* |
 30
Exelon Generation 2011 EPS Contribution
(1)
Estimated contribution to Exelon’s operating earnings guidance.
$ / Share
$0.35
$(0.03)
RNF
O&M
Other
Depreciation &
Amortization
$(0.08)
Key Items:
Inflation
Exelon
Wind
Nuclear
Outages
2010A
2011E
(1)
$2.85 -
$3.05
$2.91
Key Items:
PECO
CTC $0.62
Exelon Wind
$0.08
Capacity Market Prices
$(0.29) Nuclear Fuel
$(0.09)
Market/portfolio conditions
and Exelon
Energy $0.07
$(0.17)
$(0.03)
Interest
Expense
Note: Drivers add up to mid-point of 2011 EPS range.
$(0.05)
$(0.05)
$(0.05) |
 31
ComEd 2011 EPS Contribution
2010A
Depreciation &
Amortization
Interest
Expense
$0.55 -
$0.65
$0.03
$(0.08)
$(0.03)
2011E
(3)
$ / Share
$(0.02)
$0.02
Other
RNF
(1)
O&M
(1)
Key Items:
Weather
Uncollectibles
Appellate Court ruling
Distribution revenue
(2)
Key Items:
Uncollectibles
$(0.04)
Inflation
$(0.02) Note: Drivers add up to mid-point of 2011 EPS range.
$0.68
1
$(0.04)
$(0.02)
$(0.01)
$0.08
(1)
Excludes estimated impact of Rider EDA (Energy Efficiency and Demand Response Adjustment) of
+/-$0.05/share. 2010 net income includes a one-time benefit for collections of
under-recovered 2008 and 2009 bad debt costs, as provided by the uncollectible expense rider approved by the ICC in February 2010. Going forward, the
rider provides for full recovery of all bad debt costs.
(2)
Distribution rate case currently pending, new rates will be effective in June 2011. Earnings
guidance assumes mid-point of ComEd’s requested revenue increase. (3)
Estimated contribution to Exelon’s operating earnings guidance. |
 32
PECO 2011 EPS Contribution
$ / Share
RNF
(2)
$(0.03)
$0.54
(1)
CTC,net
2011E
(3)
Key Items:
Electric & Gas
Distribution Rate
$0.19
Weather
$(0.05) Key Items:
Inflation
$(0.01) Bad
Debt $(0.01)
$0.14
O&M
(2)
$0.50 -
$0.55
(1)
$(0.04)
2010A
(1)
Excludes preferred dividends.
(2)
Excludes items that are income statement neutral and estimated impact of energy
efficiency and smart meter costs recoverable under a rider of $0.10/share.
(3)
Estimated contribution to Exelon’s operating earnings guidance.
Note: Drivers add up to mid-point of 2011 EPS range.
$(0.03)
Depreciation
$(0.05)
Income Taxes
Key Items:
Revenue net $(0.06)
of amortization
Interest on PECO
transition bonds $0.02 |
 33
Key Assumptions
38.0
31.1
29.5
PECO
40.8
39.7
37.9
ComEd
37.1
37.5
38.3
Exelon Generation
38.1
36.7
37.2
Effective Tax Rate -
Operating (%)
136.59
144.40
106.13
RTO Capacity Price ($/MW-day)
2009 Actual
2010 Actual
2011 Est.
(3)
Nuclear Capacity Factor (%)
(1)
93.6
93.9
93.0
Total Generation Sales Excluding Trading (GWh)
173,065
171,789
168,700
Henry Hub Gas Price ($/mmBtu)
3.92
4.37
4.56
PJM West Hub ATC Price ($/MWh)
38.30
45.93
45.45
Tetco M3 Gas Price ($/mmBtu)
4.64
5.10
5.32
PJM West Hub Implied ATC Heat Rate (mmbtu/MWh)
8.25
9.01
8.54
NI Hub ATC Price ($/MWh)
28.85
33.09
30.69
Chicago City Gate Gas Price ($/mmBtu)
3.92
4.46
4.61
NI Hub Implied ATC Heat Rate (mmbtu/MWh)
7.36
7.42
6.66
MAAC Capacity Price ($/MW-day)
158.48
181.34
136.59
EMAAC Capacity Price ($/MW-day)
173.73
181.34
136.59
Electric Delivery Growth (%)
(2)
PECO
0.6
0.1
0.0
ComEd
(0.1)
0.2
0.0
(1)
Excludes Salem.
.
(2)
Weather-normalized retail load growth.
(3)
Reflects forward market prices as of December 31, 2010.
Note:
The
estimates
of
planned
generation
do
not
represent
guidance
or
a
forecast
of
future
results
as
Exelon
has
not
completed
its
planning
or
optimization
processes. |
 34
34
Total Portfolio Characteristics
110,594
142,400
42,003
5,295
13,897
26,300
0
50,000
100,000
150,000
200,000
2010
2011E
ComEd Swap
IL Auction
PECO Load
Actual Forward Hedges & Open Position
Expected Total Supply (GWh)
Expected Total Sales
(GWh)
92,493
91,300
47,517
48,100
27,090
26,500
4,689
2,800
0
50,000
100,000
150,000
200,000
2010
2011E
Forward / Spot Purchases
Fossil and Renewables
Mid-Atlantic Nuclear
Midwest Nuclear
171,789
171,789
168,700
168,700
Note:
The
estimates
of
planned
generation
do
not
represent
guidance
or
a
forecast
of
future
results
as
Exelon
has
not
completed
its
planning
or
optimization
processes. |
 35
Refueling Outage Schedule
Note:
Data
includes
Salem.
Net
nuclear
generation
data
based
on
ownership
interest.
The
estimates
of
planned
generation
do
not
represent
guidance
or
a forecast of future results as Exelon has not completed its planning or
optimization processes. All Exelon owned units on a 24 month
cycle except for Braidwood U1/U2,
Byron U1/U2 and Salem U1/U2,
which are on 18 month cycles
Average Outage Duration (2009-10):
~29 days
(1)
Nuclear Refueling Cycle
12 planned refueling outages,
including 2 at Salem; Clinton outage
was moved from spring 2012 to fall
2011
6 refueling outages planned for the
Spring and 6 refueling outages
planned for the Fall
2011 Refueling Outage Impact
(1)
Excludes Salem.
125
127
129
131
133
135
137
139
141
143
145
2004
2005
2006
2007
2008
2009
2010
2011
2012
2013
2014
2015
7
8
9
10
11
12
13
Nuclear Output
Actual
Plan
# of Outages |
 36
ComEd 2010 Rate Case Update
ComEd Surrebuttal (1/3/11)
$326M increase requested
11.50% ROE / 47.28% equity ratio
Rate base $7,349M
2009 test year with pro forma plant
additions through 6/30/11
ICC Staff Position
$116M increase proposed in Dec 2010
rebuttal testimony
10.00% ROE / 47.11% equity ratio
Rate base $6,602M
Pro forma plant additions and
depreciation reserve through 12/31/10
(ICC Docket No. 10-0467)
$ millions
ComEd Original Request (6/30/10)
396
$
Adjustments:
Bonus Depreciation
(14)
Pro forma plant adds/O&M update
(4)
Errata in Initial Filing
(12)
Reduction to Reg Asset Amortization
(8)
Other Items
(4)
ComEd Rebuttal (11/22/10)
354
$
Adjustments:
New Bonus Depreciation
(22)
Pro forma plant adds/O&M update
(4)
Reduction to AMI/Other
(2)
ComEd Surrebuttal (1/3/2011)
326
$
Reconciliation of ComEd Request to ComEd Surrebuttal
Note: See slide 17 for ComEd rate case key dates
* ComEd request does not reflect Appellate Court decision relating to
depreciation reserve, which we estimate would have a $85M reduction
to revenue requirement
* |
 37
ComEd Customer Usage Breakdown
Other
2%
Residential
31%
Small C&I
36%
380 Large
C&I
18%
Other Large
C&I
13%
3%
Leisure & Hospitality
9%
Trade, Transportation & Utilities
11%
Finance, Professional &
Business Services
12%
Health & Educational Services
13%
Government
52%
Manufacturing
Customer Usage by Revenue Class
Top 380 Customer Usage by Segment
Limited survey of select Large C&I customers has indicated an increase in
production via longer production runs and additional shifts due to improved
economic conditions for manufacturing-based customers, especially in the
steel and transportation sectors, along with data center expansions.
|
 38
PECO Customer Usage Breakdown
Other
3%
Other Large
C&I
24%
150 Large
C&I
17%
Small C&I
22%
Residential
34%
7%
Other
13%
Transportation, Communication &
Utilities
18%
Health & Educational Services
18%
Manufacturing
22%
Petroleum
2%
Retail Trade
9%
Finance, Insurance & Real Estate
12%
Pharmaceuticals
Customer Usage by Revenue Class
Top 150 Customer Usage by Segment
PECO’s load is relatively diversified by customer class and industry
|
 39
Sufficient Liquidity
--
--
--
--
Outstanding Facility Draws
(338)
(134)
(1)
(196)
Outstanding Letters of Credit
$7,365
$4,834
$574
$1,000
Aggregate Bank Commitments
(1)
7,027
4,700
573
804
Available Capacity Under Facilities
(2)
--
--
--
--
Outstanding Commercial Paper
$7,027
$4,700
$573
$804
Available Capacity Less Outstanding
Commercial Paper
Exelon
(3)
($ millions)
Available Capacity Under Bank Facilities as of January 14, 2011
(1) Excludes previous commitment from Lehman Brothers Bank and 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.
Plan
to
extend/refinance
Exelon
Generation,
PECO
and
Exelon
Corp
credit
facilities in first half of 2011 |
 40
Key Credit Metrics
0.0x
2.0x
4.0x
6.0x
8.0x
10.0x
12.0x
2009A
2010A
2011E
ExGen/Corp
ComEd
PECO
0%
5%
10%
15%
20%
25%
30%
35%
40%
45%
50%
2009A
2010A
2011E
ExGen/Corp
ComEd
PECO
FFO / Debt
(1)
(1)
Reflects FFO / Debt, Interest Coverage and Debt / Cap ratios as calculated by
S&P. (2)
Reflects S&P Target Range. See slide 41 for reconciliations to
GAAP. (3)
FFO/Debt Target Range reflects Generation FFO/Debt in addition to the debt
obligations of Exelon Corp. (4)
Current senior unsecured ratings for Exelon and Exelon Generation and senior
secured ratings for ComEd and PECO as of January 21, 2011. 30-35%
(3)
15-18%
15-18%
FFO / Debt
Target
Range
(2)
BBB+
A
BBB+
BBB+
Fitch
Credit
Ratings
(4)
BBB
A-
A-
BBB-
S&P
Credit
Ratings
(4)
A3
A1
Baa1
Baa1
Moody’s
Credit
Ratings
(4)
ComEd:
PECO:
Generation:
Exelon:
Interest Coverage
(1)
0%
10%
20%
30%
40%
50%
60%
70%
80%
90%
100%
2009A
2010A
2011E
ExGen/Corp
ComEd
PECO
Debt / Cap
(1) |
 41
Metric Calculations and Ratios
+
Other
Non-Cash
items
(1)
-
AFUDC/Cap. Interest
-
Decommissioning activity
+/-
Change in Working Capital
FFO Calculation:
= FFO
-
PECO Transition Bond Principal Paydown
Net Cash Flows provided by Operating Activities
Adjusted Interest:
Net Interest Expense
Adjusted Interest
FFO + Adjusted Interest
= Adjusted Interest
+ AFUDC & Capitalized interest
+ Interest on Present Value (PV) of Operating Leases
+ Interest on Imputed Debt Related to PV of Power Purchase Agreements (PPA)
-
PECO Transition Bond Interest Expense
Interest Coverage:
FFO
= Adjusted Debt
+ Off-balance sheet debt equivalents
(3)
-
PECO Transition Bond Principal Balance
+ STD
LTD
Adjusted Debt:
Adjusted Debt
(2)
FFO / Debt:
(1)
Reflects depreciation adjustment for PPAs and operating leases and pension/OPEB
contribution normalization. (2)
Uses current year-end adjusted debt balance.
(3)
Metrics
are
calculated
in
presentation
adjusted
for
debt
equivalents
for
PV
of
Operating
Leases,
PPAs,
unfunded
Pension
and
OPEB
obligations
(after-tax)
and
other
minor
debt equivalents.
+ Adjusted Debt
(3)
Debt / Cap:
= Adjusted Capitalization
Adjusted Debt
(2)
Adjusted Capitalization
Adjusted Capitalization:
Total shareholder’s equity
+ Preferred Securities of Subsidiaries |
 42
4Q GAAP EPS Reconciliation
(0.01)
-
-
-
(0.01)
2007 Illinois electric rate settlement
(0.01)
-
-
-
(0.01)
John Deere Renewables acquisition costs
0.01
-
-
0.01
-
Asset Retirement Obligation reduction
(0.03)
-
-
-
(0.03)
Retirements of fossil generation units / plant retirements
(0.17)
-
-
-
(0.17)
Mark-to-market adjustments from economic hedging activities
$0.79
$(0.01)
$0.03
$0.14
$0.63
4Q 2010 GAAP Earnings (Loss) Per Share
$0.96
$(0.01)
$0.03
$0.13
$0.81
2010 Adjusted (non-GAAP) Operating Earnings (Loss) Per Share
0.04
-
-
-
0.04
Unrealized gains related to nuclear decommissioning trust funds
Exelon
Other
PECO
ComEd
ExGen
Three Months Ended December 31, 2010
NOTE: All amounts shown are per Exelon share and represent contributions to
Exelon's EPS. Amounts may not add due to rounding. 0.04
-
-
-
0.04
Mark-to-market adjustments from economic hedging activities
(0.01)
-
-
(0.01)
-
City of Chicago settlement with ComEd
(0.02)
(0.01)
-
-
(0.01)
Costs associated with early debt retirements
(0.02)
-
-
-
(0.02)
2007 Illinois electric rate settlement
(0.05)
-
-
-
(0.05)
Retirement of fossil generating units
0.02
-
-
-
0.02
Unrealized gains related to nuclear decommissioning trust funds
$0.88
$(0.03)
$0.12
$0.15
$0.64
4Q 2009 GAAP Earnings (Loss) Per Share
$0.92
$(0.02)
$0.12
$0.16
$0.66
2009 Adjusted (non-GAAP) Operating Earnings (Loss) Per Share
Exelon
Other
PECO
ComEd
ExGen
Three Months Ended December 31, 2009 |
 43
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. (0.01)
-
-
-
(0.01)
John Deere Renewables acquisition costs
0.01
-
-
0.01
-
Asset Retirement Obligation reduction
(0.10)
(0.01)
(0.03)
(0.16)
0.10
Non-cash remeasurement of income tax uncertainties
(0.10)
(0.02)
(0.02)
(0.02)
(0.04)
Non-cash charge resulting from health care legislation
(0.05)
-
-
-
(0.05)
Impact of certain emission allowances
0.08
-
-
-
0.08
Mark-to-market adjustments from economic hedging activities
(0.08)
-
-
-
(0.08)
Retirement of fossil generating units
$3.87
$(0.10)
$0.49
$0.51
$2.97
FY 2010 GAAP Earnings (Loss) Per Share
$4.06
$(0.07)
$0.54
$0.68
$2.91
2010 Adjusted (non-GAAP) Operating Earnings (Loss) Per Share
(0.02)
-
-
-
(0.02)
2007 Illinois electric rate settlement
0.08
-
-
-
0.08
Unrealized gains related to nuclear decommissioning trust funds
Exelon
Other
PECO
ComEd
ExGen
Twelve Months Ended December 31, 2010
0.16
-
-
-
0.16
Mark-to-market adjustments from economic hedging activities
(0.05)
-
-
-
(0.05)
Retirement of fossil generating units
(0.01)
-
-
(0.01)
-
City of Chicago settlement with ComEd
(0.10)
-
-
(0.01)
(0.09)
2007 Illinois electric rate settlement
(0.11)
(0.04)
-
-
(0.07)
Costs associated with early debt retirements
(0.20)
-
-
-
(0.20)
Impairment of certain generating assets
(0.03)
-
(0.00)
(0.02)
(0.01)
2009 severance charges
0.05
-
-
-
0.05
Nuclear decommissioning obligation reduction
(0.03)
(0.03)
-
-
-
NRG acquisition costs
0.19
-
-
-
0.19
Unrealized gains related to nuclear decommissioning trust funds
0.10
(0.02)
-
0.06
0.06
Non-cash remeasurement of income tax uncertainties and reassessment of state
deferred income taxes
$4.09
$(0.21)
$0.53
$0.56
$3.21
FY 2009 GAAP Earnings (Loss) Per Share
$4.12
$(0.12)
$0.54
$0.54
$3.16
2009 Adjusted (non-GAAP) Operating Earnings (Loss) Per Share
Exelon
Other
PECO
ComEd
ExGen
Twelve Months Ended December 31, 2009 |
 GAAP
to Operating Adjustments Exelon’s 2011 adjusted (non-GAAP) operating
earnings outlook excludes the earnings effects of the following:
•
Mark-to-market adjustments from economic hedging activities
•
Unrealized gains and losses from nuclear decommissioning trust fund investments to
the extent not offset by contractual accounting as described in the notes
to the consolidated financial statements •
Significant impairments of assets, including goodwill
•
Any changes in decommissioning obligation estimates
•
Costs associated with ComEd’s 2007 settlement with the City of Chicago
•
Financial impacts associated with the planned retirement of fossil generating
units •
Other unusual items
•
Significant changes to GAAP
Operating earnings guidance assumes normal weather for full year
O&M reconciliation:
2010
2011
ExGen
ComEd
PECO
Other
Exelon
ExGen
ComEd
PECO
Other
Exelon
Operating and maintenance (GAAP)
2,812
1,069
733
(14)
4,600
3,010
1,220
820
(10)
5,040
JDR acquisition costs
(11)
-
-
-
(11)
-
-
-
-
-
Retirement of Fossil Generating Units
(3)
-
-
-
(3)
(30)
-
-
-
(30)
Non-cash charge resulting from health care legislation
(4)
(3)
(2)
8
(1)
-
-
-
-
-
Asset Retirement Obligation reduction
-
10
1
-
11
-
-
-
-
-
Adjusted Non-GAAP O&M
2,794
1,076
732
(6)
4,596
2,980
1,220
820
(10)
5,010
Decommissioning accretion
(57)
-
-
-
(57)
(70)
-
-
-
(70)
Regulatory required programs
-
(94)
(53)
-
(147)
-
(150)
(110)
-
(260)
Operating O&M (as shown on slide 13)
2,737
982
679
(6)
4,392
2,910
1,070
710
(10)
4,680
($ millions)
44 |