Table of Contents

EXHIBIT 99.1

 

 

Contact:		Stacie Frank				FOR IMMEDIATE RELEASE
		Investor Relations
		312-394-3094
		Kathleen Cantillon
		Corporate Communications
		312-394-7417

Exelon Announces Second Quarter 2011 Results;

Raises Full Year Operating Earnings Guidance Range

CHICAGO (July 27, 2011) – Exelon Corporation (NYSE: EXC) announced second quarter 2011 consolidated earnings as follows:

 

		Second Quarter
		2011				2010
Adjusted (non-GAAP) Operating Results:
Net Income ($ millions)		$	697			$	656
Diluted Earnings per Share		$	1.05			$	0.99
GAAP Results:
Net Income ($ millions)		$	620			$	445
Diluted Earnings per Share		$	0.93			$	0.67

“We have again delivered a quarter of solid operational and financial performance,” said John W. Rowe, chairman and chief executive officer. “Exelon Generation’s nuclear fleet produced a capacity factor of 89.6 percent even with 103 planned refueling outage days, and our delivery companies ComEd and PECO performed well despite the challenges of severe weather conditions. Reflecting our first half results and confidence in our outlook for the remainder of the year, we are raising our operating earnings guidance range to $4.05 to $4.25 per share from $3.90 to $4.20 per share.”

Second Quarter Operating Results

As shown in the table above, Exelon’s adjusted (non-GAAP) operating earnings increased to $1.05 per share in the second quarter of 2011 from $0.99 per share in the second quarter of 2010, primarily due to:

 

•

The effect at Exelon Generation Company, LLC (Generation) of higher realized energy prices in the Mid-Atlantic region due to the expiration of the power purchase agreement (PPA) with PECO Energy Company (PECO) and favorable market and portfolio conditions including wind and hydro volume;

 

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Benefits from a special transfer tax deduction related to nuclear decommissioning trust (NDT) funds;

 

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•

One-time net benefits reflecting the 2011 electric distribution rate case order for Commonwealth Edison Company (ComEd); and

•

The effect of new electric and gas distribution rates at PECO effective January 1, 2011.

Higher second quarter 2011 earnings were partially offset by:

 

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Lower nuclear volume, primarily reflecting the effect of more plant outage days in 2011, and higher nuclear fuel costs;

•

The effect of competitive transition charge (CTC) recoveries in 2010, net of amortization expense, associated with PECO’s transition period, which ended on December 31, 2010;

•

Higher operating and maintenance expenses; and

•

Increased depreciation expense.

Adjusted (non-GAAP) operating earnings for the second quarter of 2011 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		$	(75	)		$	(0.12	)
One-time benefits for the recovery of previously incurred costs per ComEd’s 2011 distribution rate case order		$	17			$	0.03
Certain costs associated with Exelon’s proposed merger with Constellation Energy Group, Inc. (Constellation)		$	(15	)		$	(0.02	)
Financial impacts associated with the planned retirement of certain Generation fossil generating units		$	(10	)		$	(0.02	)
Unrealized gains related to NDT fund investments to the extent not offset by contractual accounting		$	6			$	0.01

Adjusted (non-GAAP) operating earnings for the second quarter of 2010 did 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		$	(75	)		$	(0.11	)
Non-cash remeasurement of income tax uncertainties related to ComEd’s 1999 sale of fossil generating assets and related to CTCs received by PECO		$	(65	)		$	(0.10	)
Unrealized losses related to NDT fund investments to the extent not offset by contractual accounting		$	(53	)		$	(0.08	)
Financial impacts associated with the planned retirement of certain Generation fossil generating units		$	(12	)		$	(0.02	)
Costs associated with the 2007 Illinois electric rate settlement agreement		$	(4	)		$	(0.01	)
Costs associated with ComEd’s 2007 settlement agreement with the City of Chicago		$	(2	)			—

 

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2011 Earnings Outlook

Exelon raised its guidance range for 2011 adjusted (non-GAAP) operating earnings to $4.05 to $4.25 per share from $3.90 to $4.20 per share. Operating earnings guidance is based on the assumption of normal weather for the balance of the year.

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

 

•

Non-cash charge to remeasure deferred taxes at higher Illinois corporate tax rates

 

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Financial impacts associated with the planned retirement of fossil generating units

 

•

One-time benefits reflecting ComEd’s 2011 distribution rate case order for the recovery of previously incurred costs related to the 2009 restructuring plan and for the passage of Federal health care legislation in 2010

 

•

Certain costs associated with the Exelon’s proposed merger with Constellation

 

•

Other unusual items

 

•

Significant changes to GAAP

Second Quarter and Recent Highlights

 

•

Proposed Merger with Constellation: On April 28, 2011, Exelon entered into a merger agreement with Constellation which contemplates a stock-for-stock transaction. Constellation is a leading competitive supplier of power, natural gas and energy products and services for homes and businesses across the continental United States. It owns a diversified fleet of generating units, totaling approximately 12,000 megawatts (MW) of generating capacity, and delivers electricity and natural gas through the Baltimore Gas and Electric Company (BGE), its regulated utility in central Maryland.

Constellation’s shareholders will receive 0.930 shares of Exelon common stock in exchange for each share of Constellation common stock. Following completion of the merger, Exelon shareholders will own approximately 78 percent of the combined company and Constellation shareholders approximately 22 percent on a fully diluted basis. The closing of the merger is dependent upon the receipt of all required approvals, including approval of the shareholders of both companies. Exelon and Constellation expect the closing of the merger to occur in early 2012.

 

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Nuclear Regulatory Commission (NRC) Task Force Report: On July 12, 2011, the NRC Near-Term Task Force issued its report, which reviewed nuclear processes and regulations in light of the accident at the Fukushima Daiichi plant in Japan. The Task Force concluded that U.S. nuclear plants are operating safely and did not identify changes to the existing nuclear licensing process nor recommend fundamental changes to spent nuclear fuel storage. The Task Force report made recommendations in three key areas: the NRC’s regulatory framework,

 

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specific plant design requirements, and emergency preparedness and actions. Exelon expects the report to be the first step in a longer-term review that the NRC will conduct, along with seeking broad stakeholder input. Exelon continues to apply lessons learned and work with regulators and industry organizations on appropriate assessments and actions.

 

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Nuclear Operations: Generation’s nuclear fleet, including its owned output from the Salem Generating Station, produced 33,167 gigawatt-hours (GWh) in the second quarter of 2011, compared with 35,035 GWh in the second quarter of 2010. The Exelon-operated nuclear plants achieved an 89.6 percent capacity factor for the second quarter of 2011 compared with 94.8 percent for the second quarter of 2010. The Exelon-operated nuclear plants completed four scheduled refueling outages in the second quarter of 2011, compared with completing three scheduled refueling outages in the second quarter of 2010. The number of refueling outage days totaled 103 in the second quarter of 2011 versus 44 days in the second quarter of 2010. The number of non-refueling outage days at the Exelon-operated plants totaled 24 days in the second quarter of 2011 compared with 15 days in the second quarter of 2010.

 

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Nuclear License Renewals: On June 30, 2011, the NRC approved extension of the operating licenses for the Salem Generating Units 1 and 2 by 20 years to 2036 and 2040, respectively. Exelon has a 42.59 percent ownership interest in these units, which are operated by PSEG Nuclear, LLC.

On June 22, 2011, Exelon submitted an application to the NRC to extend the operating licenses of Limerick Generating Units 1 and 2 by an additional 20 years. The current licenses of the units expire in 2024 and 2029, respectively. The NRC is expected to spend 22 to 30 months reviewing the application before making a decision.

 

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Fossil and Hydro Operations: The equivalent demand forced outage rate for Generation’s fossil fleet was 4.9 percent in the second quarter of 2011, compared with 3.8 percent in the second quarter of 2010. The increase was largely due to an outage in 2011 at a unit at the Handley Generating Station. The equivalent availability factor for the hydroelectric facilities was 93.4 percent in the second quarter of 2011, compared with 98.1 percent in the second quarter of 2010, largely due to planned outages in April at two units at the Muddy Run facility.

 

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Acquisition of Wolf Hollow: On May 12, 2011, Exelon announced an agreement to acquire Wolf Hollow, a combined-cycle natural gas-fired power plant in north Texas, from Sequent Wolf Hollow, LLC, for $305 million, as adjusted for working capital. The transaction adds 720 MW of clean energy to Exelon’s fleet in the competitive Electric Reliability Council of Texas (ERCOT) power market, where the company already owns and operates three other natural gas-fired power plants. Exelon currently has a PPA with Wolf Hollow, through 2023, to purchase 350 MW of its output at above current observable market power prices. In addition to eliminating the existing PPA, Exelon expects the proposed transaction to provide incremental cash flows beginning in 2012. The Wolf Hollow transaction is subject to antitrust clearance and approval by the Public Utility Commission of Texas. Exelon plans to finance the transaction with existing cash flow and liquidity resources and expects to close in the third quarter of 2011.

 

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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 June 30, 2011 is 95 to 98 percent for 2011, 82 to 85 percent for 2012 and 49 to 52 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.

 

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Reliability Interregional Transmission Extension (RITE) Line: On July 18, 2011, Exelon and Electric Transmission America (ETA), a joint venture of American Electric Power (AEP) and MidAmerican Energy Holdings, filed for a formula rate and incentives at FERC for a proposed 420-mile, 765-kilovolt (kV) transmission line called the RITE Line. The RITE Line will interconnect with the existing AEP 765-kV system at the Indiana/Ohio border and extend west through Indiana into Illinois, connecting with the ComEd system and extending to a new 765-kV substation near Byron, Illinois. The RITE Line will allow reliable interconnection to additional sources of energy, including renewables. The project will be built in stages over three to four years, likely between 2015 and 2018, and in addition to FERC is subject to PJM Interconnection, LLC and state approvals. The FERC filing is a significant step in the process of obtaining these approvals for the line.

 

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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 subsequent testimony, ComEd revised its requested revenue increase to $343 million, reflecting certain adjustments to its original request of $396 million. On May 24, 2011, the ICC issued its final order in the rate case. ComEd received a revenue increase of $143 million, which became effective on June 1, 2011. The approved rate of return on common equity is 10.50 percent.

 

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Illinois Proposed Energy Infrastructure and Modernization Act: On May 31, 2011, the Illinois General Assembly passed legislation (Senate Bill 1652) that will modernize Illinois’ electric grid if enacted into law. The legislation includes a policy-based approach that would provide a more predictable ratemaking system and would enable utilities to modernize the electric grid and set the stage for fostering economic development while creating and retaining jobs. The legislation also includes a process for determining formula rates that would provide for the recovery of actual costs of service that are prudent and reasonable. Once the legislation is presented to the Governor, he will have 60 days to act on it.

OPERATING COMPANY RESULTS

Generation consists of owned and contracted electric generating facilities, wholesale energy marketing operations and competitive retail sales operations.

Second quarter 2011 net income was $443 million compared with $382 million in the second quarter of 2010. Second quarter 2011 net income included (all after tax) mark-to-market losses of $75 million from economic hedging activities, net costs of $10 million associated with the planned retirement of

 

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certain fossil generating units, unrealized gains of $6 million related to NDT fund investments and certain costs of $1 million associated with the proposed merger with Constellation. Second quarter 2010 net income included (all after tax) mark-to-market losses of $75 million from economic hedging activities, a gain of $70 million related to the non-cash remeasurement of income tax uncertainties, unrealized losses of $53 million related to NDT fund investments, costs of $12 million associated with the retirement of certain fossil generating units and a charge of $4 million for costs associated with the 2007 Illinois electric rate settlement. Excluding the effects of these items, Generation’s net income in the second quarter of 2011 increased $67 million compared with the same quarter in 2010 primarily due to:

 

•

The impact on energy gross margin of higher realized energy prices in the Mid-Atlantic region due to the expiration of the PPA with PECO, coupled with favorable market and portfolio conditions including wind and hydro volume; and

 

•

Benefits from the special transfer tax deduction related to NDT funds.

The increase in net income was partially offset by:

 

•

The impact on energy gross margin of lower nuclear volume, primarily reflecting the effect of more plant outage days in 2011, and higher nuclear fuel costs;

 

•

Higher operating and maintenance expenses, primarily reflecting increased planned nuclear refueling outages; and

 

•

Increased depreciation and interest expenses.

Generation’s average realized margin on all electric sales, including sales to affiliates and excluding trading activity, was $41.59 per MWh in the second quarter of 2011 compared with $36.87 per MWh in the second quarter of 2010.

ComEd consists of the electricity transmission and distribution operations in northern Illinois.

ComEd recorded net income of $114 million in the second quarter of 2011, compared with net income of $9 million in the second quarter of 2010. Second quarter net income in 2011 included an after-tax non-cash credit of $17 million for the recovery of previously incurred costs pursuant to the 2011 distribution rate case order. Second quarter net income in 2010 included an after-tax charge of $106 million related to the non-cash remeasurement of income tax uncertainties and after-tax costs of $2 million for the City of Chicago settlement agreement. Excluding the effects of these items, ComEd’s net income in the second quarter of 2011 was down $20 million from the same quarter in 2010 primarily reflecting:

 

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The recording in 2010 of projected refunds related to Illinois electric distribution taxes;

 

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Higher operating and maintenance expenses; and

 

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Increased depreciation and interest expenses.

The decrease in net income was partially offset by:

 

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One-time net benefits pursuant to the 2011 electric distribution rate case order; and

 

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The impact of new electric distribution rates effective June 1, 2011.

In the second quarter of 2011, cooling degree-days in the ComEd service territory were down 24.0 percent relative to the same period in 2010 and were 5.8 percent above normal. Total retail electric deliveries decreased 2.3 percent quarter over quarter.

 

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Weather-normalized retail electric deliveries decreased 0.8 percent in the second quarter of 2011 relative to 2010, reflecting a decrease in deliveries to all major customer classes. For ComEd, weather had an unfavorable after-tax effect of $4 million on second quarter 2011 earnings relative to 2010 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 second quarter of 2011 was $83 million, up from $75 million in the second quarter of 2010. Second quarter 2010 net income included an after-tax interest expense charge of $22 million related to the non-cash remeasurement of income tax uncertainties. Excluding the effect of this item, PECO’s net income in the second quarter of 2011 was down $14 million from the same quarter in 2010, primarily reflecting:

 

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The effect of CTC recoveries in 2010, net of amortization expense, associated with PECO’s transition period, which ended on December 31, 2010.

The decrease in net income was partially offset by:

 

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The impact of new electric and gas distribution rates effective January 1, 2011;

 

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Decreased storm costs; and

 

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Lower interest expense.

In the second quarter of 2011, cooling degree-days in the PECO service territory were down 15.7 percent from 2010 and were 48.8 percent above normal. Total retail electric deliveries were down 2.5 percent from last year. On the retail gas side, deliveries in the second quarter of 2011 were up 9.8 percent from the second quarter of 2010.

Weather-normalized retail electric deliveries were about flat in the second quarter of 2011 relative to 2010, as a decline in large commercial and industrial deliveries was mostly offset by increases in deliveries to residential and small commercial and industrial customers. Weather-normalized retail gas deliveries were down 1.3 percent in the second quarter of 2011. For PECO, weather had an unfavorable after-tax effect of $4 million on second quarter 2011 earnings relative to 2010 and a favorable after-tax effect of $9 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 reconciliation 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 July 27, 2011.

 

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Conference call information: Exelon has scheduled a conference call for 11:00 AM ET (10:00 AM CT) on July 27, 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 80732345. 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 August 10. 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 80732345.

Cautionary Statements Regarding Forward-Looking Information

Except for the historical information contained herein, certain of the matters discussed in this communication constitute “forward-looking statements” within the meaning of the Securities Act of 1933 and the Securities Exchange Act of 1934, both as amended by the Private Securities Litigation Reform Act of 1995. Words such as “may,” “will,” “anticipate,” “estimate,” “expect,” “project,” “intend,” “plan,” “believe,” “target,” “forecast,” and words and terms of similar substance used in connection with any discussion of future plans, actions, or events identify forward-looking statements. These forward-looking statements include, but are not limited to, statements regarding benefits of the proposed merger of Exelon Corporation (Exelon) and Constellation Energy Group, Inc. (Constellation), integration plans and expected synergies, the expected timing of completion of the transaction, anticipated future financial and operating performance and results, including estimates for growth. These statements are based on the current expectations of management of Exelon and Constellation, as applicable. There are a number of risks and uncertainties that could cause actual results to differ materially from the forward-looking statements included in this communication regarding the proposed merger. For example, (1) the companies may be unable to obtain shareholder approvals required for the merger; (2) the companies may be unable to obtain regulatory approvals required for the merger, or required regulatory approvals may delay the merger or result in the imposition of conditions that could have a material adverse effect on the combined company or cause the companies to abandon the merger; (3) conditions to the closing of the merger may not be satisfied; (4) an unsolicited offer of another company to acquire assets or capital stock of Exelon or Constellation could interfere with the merger; (5) problems may arise in successfully integrating the businesses of the companies, which may result in the combined company not operating as effectively and efficiently as expected; (6) the combined company may be unable to achieve cost-cutting synergies or it may take longer than expected to achieve those synergies; (7) the merger may involve unexpected costs, unexpected liabilities or unexpected delays, or the effects of purchase accounting may be different from the companies’ expectations; (8) the credit ratings of the combined company or its subsidiaries may be different from what the companies expect; (9) the businesses of the companies may suffer as a result of uncertainty surrounding the merger; (10) the companies may not realize the values expected to be obtained for properties expected or required to be divested; (11) the industry may be subject to future regulatory or legislative actions that could adversely affect the companies; and (12) the companies may be adversely affected by other economic, business, and/or competitive factors. Other unknown or unpredictable factors could also have material adverse effects on future results, performance or achievements of Exelon or the combined company. Discussions of some of these other important factors and assumptions are contained in Exelon’s and Constellation’s respective filings with the Securities and Exchange Commission (SEC),

 

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and available at the SEC’s website at www.sec.gov, including: (1) Exelon’s 2010 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 Second Quarter 2011 Quarterly Report on Form 10-Q (to be filed on July 27, 2011) 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; (3) Constellation’s 2010 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 12; and (4) Constellation’s Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2011 in (a) Part II, Other Information, ITEM 5.Other Information, (b) Part I, 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: Notes to Consolidated Financial Statements, Commitments and Contingencies. These risks, as well as other risks associated with the proposed merger, are more fully discussed in the preliminary joint proxy statement/prospectus included in the Registration Statement on Form S-4 that Exelon filed with the SEC on June 27, 2011 in connection with the proposed merger. In light of these risks, uncertainties, assumptions and factors, the forward-looking events discussed in this communication may not occur. Readers are cautioned not to place undue reliance on these forward-looking statements, which speak only as of the date of this communication. Neither Exelon nor Constellation undertake any obligation to publicly release any revision to its forward-looking statements to reflect events or circumstances after the date of this communication.

Additional Information and Where to Find it

This communication does not constitute an offer to sell or the solicitation of an offer to buy any securities, or a solicitation of any vote or approval, nor shall there be any sale of securities in any jurisdiction in which such offer, solicitation or sale would be unlawful prior to registration or qualification under the securities laws of any such jurisdiction. On June 27, 2011, Exelon filed with the SEC a Registration Statement on Form S-4 that included a preliminary joint proxy statement/prospectus and other relevant documents to be mailed by Exelon and Constellation to their respective security holders in connection with the proposed merger of Exelon and Constellation. These materials are not yet final and may be amended. WE URGE INVESTORS AND SECURITY HOLDERS TO READ THE PRELIMINARY JOINT PROXY STATEMENT/PROSPECTUS AND THE DEFINITIVE JOINT PROXY STATEMENT/PROSPECTUS AND ANY OTHER RELEVANT DOCUMENTS WHEN THEY BECOME AVAILABLE, BECAUSE THEY CONTAIN OR WILL CONTAIN IMPORTANT INFORMATION about Exelon, Constellation and the proposed merger. Investors and security holders will be able to obtain these materials (when they are available) and other documents filed with the SEC free of charge at the SEC’s website, www.sec.gov. In addition, a copy of the preliminary joint proxy statement/prospectus and definitive joint proxy statement/prospectus (when it becomes available) may be obtained free of charge from Exelon Corporation, Investor Relations, 10 South Dearborn Street, P.O. Box 805398, Chicago, Illinois 60680-5398, or from Constellation Energy Group, Inc., Investor Relations, 100 Constellation Way, Suite 600C, Baltimore, MD 21202. Investors and security holders may also read and copy any reports, statements and other information filed by Exelon, or Constellation, with the SEC, at the SEC public reference room at 100 F Street, N.E., Washington, D.C. 20549. Please call the SEC at 1-800-SEC-0330 or visit the SEC’s website for further information on its public reference room.

 

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Participants in the Merger Solicitation

Exelon, Constellation, and their respective directors, executive officers and certain other members of management and employees may be deemed to be participants in the solicitation of proxies in respect of the proposed transaction. Information regarding Exelon’s directors and executive officers is available in its proxy statement filed with the SEC by Exelon on March 24, 2011 in connection with its 2011 annual meeting of shareholders, and information regarding Constellation’s directors and executive officers is available in its proxy statement filed with the SEC by Constellation on April 15, 2011 in connection with its 2011 annual meeting of shareholders. Other information regarding the participants in the proxy solicitation and a description of their direct and indirect interests, by security holdings or otherwise, is contained in the preliminary joint proxy statement/prospectus and will be contained in the definitive joint proxy statement/prospectus.

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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 490,000 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 June 30, 2011 and 2010			1
Consolidating Statements of Operations - Six Months Ended June 30, 2011 and 2010			2
Business Segment Comparative Statements of Operations - Generation and ComEd - Three and Six Months Ended June 30, 2011 and 2010			3
Business Segment Comparative Statements of Operations - PECO and Other - Three and Six Months Ended June 30, 2011 and 2010			4
Consolidated Balance Sheets - June 30, 2011 and December 31, 2010			5
Consolidated Statements of Cash Flows - Six Months Ended June 30, 2011 and 2010			6
Reconciliation of Adjusted (non-GAAP) Operating Earnings to GAAP Consolidated Statements of Operations - Exelon - Three Months Ended June 30, 2011 and 2010			7
Reconciliation of Adjusted (non-GAAP) Operating Earnings to GAAP Consolidated Statements of Operations - Exelon - Six Months Ended June 30, 2011 and 2010			8
Reconciliation of Adjusted (non-GAAP) Operating Earnings to GAAP Earnings By Business Segment - Three Months Ended June 30, 2011 and 2010			9
Reconciliation of Adjusted (non-GAAP) Operating Earnings to GAAP Earnings By Business Segment - Six Months Ended June 30, 2011 and 2010			10
Reconciliation of Adjusted (non-GAAP) Operating Earnings to GAAP Consolidated Statements of Operations - Generation - Three and Six Months Ended June 30, 2011 and 2010			11
Reconciliation of Adjusted (non-GAAP) Operating Earnings to GAAP Consolidated Statements of Operations - ComEd - Three and Six Months Ended June 30, 2011 and 2010			12
Reconciliation of Adjusted (non-GAAP) Operating Earnings to GAAP Consolidated Statements of Operations - PECO - Three and Six Months Ended June 30, 2011 and 2010			13
Reconciliation of Adjusted (non-GAAP) Operating Earnings to GAAP Consolidated Statements of Operations - Other - Three and Six Months Ended June 30, 2011 and 2010			14
Exelon Generation Statistics - Three Months Ended June 30, 2011, March 31, 2011,  December 31, 2010, September 30, 2010 and June 30, 2010			15
Exelon Generation Statistics - Six Months Ended June 30, 2011 and 2010			16
ComEd Statistics - Three and Six Months Ended June 30, 2011 and 2010			17
PECO Statistics - Three and Six Months Ended June 30, 2011 and 2010			18

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EXELON CORPORATION

Consolidating Statements of Operations

(unaudited)

(in millions)

 

		Three Months Ended June 30, 2011
		Generation				ComEd				PECO				Other (b)				Exelon Consolidated
Operating revenues		$	2,546			$	1,444			$	842			$	(245	)		$	4,587
Operating expenses
Purchased power			572				716				368				(249	)			1,407
Fuel			360				—				40				—				400
Operating and maintenance			763				245				154				23				1,185
Operating and maintenance for regulatory required programs (a)			—				23				18				—				41
Depreciation and amortization			138				136				50				5				329
Taxes other than income			66				70				51				4				191
Total operating expenses			1,899				1,190				681				(217	)			3,553
Operating income (loss)			647				254				161				(28	)			1,034
Other income and deductions
Interest expense			(45	)			(86	)			(34	)			(17	)			(182	)
Other, net			76				4				3				17				100
Total other income and deductions			31				(82	)			(31	)			—				(82	)
Income (loss) before income taxes			678				172				130				(28	)			952
Income taxes			235				58				47				(8	)			332
Net income (loss)		$	443			$	114			$	83			$	(20	)		$	620

 

		Three Months Ended June 30, 2010
		Generation				ComEd				PECO				Other (b)				Exelon Consolidated
Operating revenues		$	2,353			$	1,499			$	1,269			$	(723	)		$	4,398
Operating expenses
Purchased power			549				771				535				(721	)			1,134
Fuel			350				—				44				(1	)			393
Operating and maintenance			691				276				150				(3	)			1,114
Operating and maintenance for regulatory required programs (a)			—				21				13				—				34
Depreciation and amortization			115				131				268				5				519
Taxes other than income			61				44				77				4				186
Total operating expenses			1,766				1,243				1,087				(716	)			3,380
Operating income (loss)			587				256				182				(7	)			1,018
Other income and deductions
Interest expense			(37	)			(134	)			(77	)			(27	)			(275	)
Other, net			(133	)			8				(1	)			4				(122	)
Total other income and deductions			(170	)			(126	)			(78	)			(23	)			(397	)
Income (loss) before income taxes			417				130				104				(30	)			621
Income taxes			35				121				29				(9	)			176
Net income (loss)		$	382			$	9			$	75			$	(21	)		$	445

 

(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.

 

1

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Table of Contents

EXELON CORPORATION

Consolidating Statements of Operations

(unaudited)

(in millions)

 

		Six Months Ended June 30, 2011
		Generation				ComEd				PECO				Other (b)				Exelon Consolidated
Operating revenues		$	5,285			$	2,910			$	1,996			$	(553	)		$	9,638
Operating expenses
Purchased power			1,121				1,505				820				(555	)			2,891
Fuel			790				—				222				—				1,012
Operating and maintenance			1,517				493				340				20				2,370
Operating and maintenance for regulatory required programs (a)			—				41				38				—				79
Depreciation and amortization			277				270				98				11				656
Taxes other than income			132				147				106				9				394
Total operating expenses			3,837				2,456				1,624				(515	)			7,402
Operating income (loss)			1,448				454				372				(38	)			2,236
Other income and deductions
Interest expense			(91	)			(172	)			(68	)			(32	)			(363	)
Other, net			152				8				8				26				194
Total other income and deductions			61				(164	)			(60	)			(6	)			(169	)
Income (loss) before income taxes			1,509				290				312				(44	)			2,067
Income taxes			571				107				102				(1	)			779
Net income (loss)		$	938			$	183			$	210			$	(43	)		$	1,288
		Six Months Ended June 30, 2010
		Generation				ComEd				PECO				Other (b)				Exelon Consolidated
Operating revenues		$	4,773			$	2,914			$	2,724			$	(1,552	)		$	8,859
Operating expenses
Purchased power			757				1,524				1,059				(1,548	)			1,792
Fuel			740				—				255				(1	)			994
Operating and maintenance			1,432				435				331				(23	)			2,175
Operating and maintenance for regulatory required programs (a)			—				40				21				—				61
Depreciation and amortization			223				261				533				16				1,033
Taxes other than income			118				107				150				8				383
Total operating expenses			3,270				2,367				2,349				(1,548	)			6,438
Operating income (loss)			1,503				547				375				(4	)			2,421
Other income and deductions
Interest expense			(72	)			(218	)			(122	)			(47	)			(459	)
Other, net			(54	)			11				4				10				(29	)
Total other income and deductions			(126	)			(207	)			(118	)			(37	)			(488	)
Income (loss) before income taxes			1,377				340				257				(41	)			1,933
Income taxes			434				215				81				9				739
Net income (loss)		$	943			$	125			$	176			$	(50	)		$	1,194

 

(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.

 

2

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Table of Contents

EXELON CORPORATION

Business Segment Comparative Statements of Operations

(unaudited)

(in millions)

 

		Generation
		Three Months Ended June 30,												Six Months Ended June 30,
		2011				2010				Variance				2011				2010				Variance
Operating revenues		$	2,546			$	2,353			$	193			$	5,285			$	4,773			$	512
Operating expenses
Purchased power			572				549				23				1,121				757				364
Fuel			360				350				10				790				740				50
Operating and maintenance			763				691				72				1,517				1,432				85
Depreciation and amortization			138				115				23				277				223				54
Taxes other than income			66				61				5				132				118				14
Total operating expenses			1,899				1,766				133				3,837				3,270				567
Operating income			647				587				60				1,448				1,503				(55	)
Other income and deductions
Interest expense			(45	)			(37	)			(8	)			(91	)			(72	)			(19	)
Other, net			76				(133	)			209				152				(54	)			206
Total other income and deductions			31				(170	)			201				61				(126	)			187
Income before income taxes			678				417				261				1,509				1,377				132
Income taxes			235				35				200				571				434				137
Net income		$	443			$	382			$	61			$	938			$	943			$	(5	)
		ComEd
		Three Months Ended June 30,												Six Months Ended June 30,
		2011				2010				Variance				2011				2010				Variance
Operating revenues		$	1,444			$	1,499			$	(55	)		$	2,910			$	2,914			$	(4	)
Operating expenses
Purchased power			716				771				(55	)			1,505				1,524				(19	)
Operating and maintenance			245				276				(31	)			493				435				58
Operating and maintenance for regulatory required programs (a)			23				21				2				41				40				1
Depreciation and amortization			136				131				5				270				261				9
Taxes other than income			70				44				26				147				107				40
Total operating expenses			1,190				1,243				(53	)			2,456				2,367				89
Operating income			254				256				(2	)			454				547				(93	)
Other income and deductions
Interest expense			(86	)			(134	)			48				(172	)			(218	)			46
Other, net			4				8				(4	)			8				11				(3	)
Total other income and deductions			(82	)			(126	)			44				(164	)			(207	)			43
Income before income taxes			172				130				42				290				340				(50	)
Income taxes			58				121				(63	)			107				215				(108	)
Net income		$	114			$	9			$	105			$	183			$	125			$	58

 

(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.

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EXELON CORPORATION

Business Segment Comparative Statements of Operations

(unaudited)

(in millions)

 

		PECO
		Three Months Ended June 30,												Six Months Ended June 30,
		2011				2010				Variance				2011				2010				Variance
Operating revenues		$	842			$	1,269			$	(427	)		$	1,996			$	2,724			$	(728	)
Operating expenses
Purchased power			368				535				(167	)			820				1,059				(239	)
Fuel			40				44				(4	)			222				255				(33	)
Operating and maintenance			154				150				4				340				331				9
Operating and maintenance for regulatory required programs (a)			18				13				5				38				21				17
Depreciation and amortization			50				268				(218	)			98				533				(435	)
Taxes other than income			51				77				(26	)			106				150				(44	)
Total operating expenses			681				1,087				(406	)			1,624				2,349				(725	)
Operating income			161				182				(21	)			372				375				(3	)
Other income and deductions
Interest expense			(34	)			(77	)			43				(68	)			(122	)			54
Other, net			3				(1	)			4				8				4				4
Total other income and deductions			(31	)			(78	)			47				(60	)			(118	)			58
Income before income taxes			130				104				26				312				257				55
Income taxes			47				29				18				102				81				21
Net income		$	83			$	75			$	8			$	210			$	176			$	34
		Other (b)
		Three Months Ended June 30,												Six Months Ended June 30,
		2011				2010				Variance				2011				2010				Variance
Operating revenues		$	(245	)		$	(723	)		$	478			$	(553	)		$	(1,552	)		$	999
Operating expenses
Purchased power			(249	)			(721	)			472				(555	)			(1,548	)			993
Fuel			—				(1	)			1				—				(1	)			1
Operating and maintenance			23				(3	)			26				20				(23	)			43
Depreciation and amortization			5				5				—				11				16				(5	)
Taxes other than income			4				4				—				9				8				1
Total operating expenses			(217	)			(716	)			499				(515	)			(1,548	)			1,033
Operating loss			(28	)			(7	)			(21	)			(38	)			(4	)			(34	)
Other income and deductions
Interest expense			(17	)			(27	)			10				(32	)			(47	)			15
Other, net			17				4				13				26				10				16
Total other income and deductions			—				(23	)			23				(6	)			(37	)			31
Loss before income taxes			(28	)			(30	)			2				(44	)			(41	)			(3	)
Income taxes			(8	)			(9	)			1				(1	)			9				(10	)
Net loss		$	(20	)		$	(21	)		$	1			$	(43	)		$	(50	)		$	7

 

(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.

 

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Table of Contents

EXELON CORPORATION

Consolidated Balance Sheets

(unaudited)

(in millions)

 

		June 30, 2011				December 31, 2010
ASSETS
Current assets
Cash and cash equivalents		$	562			$	1,612
Restricted cash and investments			35				30
Accounts receivable, net
Customer			1,766				1,932
Other			697				1,196
Mark-to-market derivative assets			438				487
Inventories, net
Fossil fuel			161				216
Materials and supplies			625				590
Deferred income taxes			69				—
Regulatory assets			125				10
Other			509				325
Total current assets			4,987				6,398
Property, plant and equipment, net			30,856				29,941
Deferred debits and other assets
Regulatory assets			4,189				4,140
Nuclear decommissioning trust (NDT) funds			6,699				6,408
Investments			751				732
Goodwill			2,625				2,625
Mark-to-market derivative assets			324				409
Pledged assets for Zion Station decommissioning			804				824
Other			751				763
Total deferred debits and other assets			16,143				15,901
Total assets		$	51,986			$	52,240
Liabilities and shareholders’ equity
Current liabilities
Short-term borrowings		$	140			$	—
Short-term notes payable - accounts receivable agreement			225				225
Long-term debt due within one year			1,048				599
Accounts payable			1,297				1,373
Accrued expenses			878				1,040
Deferred income taxes			—				85
Regulatory liabilities			63				44
Mark-to-market derivative liabilities			50				38
Other			567				836
Total current liabilities			4,268				4,240
Long-term debt			11,764				11,614
Long-term debt to financing trusts			390				390
Deferred credits and other liabilities
Deferred income taxes and unamortized investment tax credits			7,391				6,621
Asset retirement obligations			3,597				3,494
Pension obligations			1,495				3,658
Non-pension postretirement benefit obligations			2,311				2,218
Spent nuclear fuel obligation			1,019				1,018
Regulatory liabilities			3,706				3,555
Mark-to-market derivative liabilities			66				21
Payable for Zion Station decommissioning			640				659
Other			1,137				1,102
Total deferred credits and other liabilities			21,362				22,346
Total liabilities			37,784				38,590
Preferred securities of subsidiary			87				87
Shareholders’ equity
Common stock			9,054				9,006
Treasury stock, at cost			(2,327	)			(2,327	)
Retained earnings			9,894				9,304
Accumulated other comprehensive loss, net			(2,509	)			(2,423	)
Total shareholders’ equity			14,112				13,560
Noncontrolling interest			3				3
Total equity			14,115				13,563
Total liabilities and shareholders’ equity		$	51,986			$	52,240

 

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EXELON CORPORATION

Consolidated Statements of Cash Flows

(unaudited)

(in millions)

 

		Six Months Ended June 30,
		2011				2010
Cash flows from operating activities
Net income		$	1,288			$	1,194
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation, amortization and accretion, including nuclear fuel amortization			1,114				1,455
Deferred income taxes and amortization of investment tax credits			590				(373	)
Net fair value changes related to derivatives			264				(123	)
Net realized and unrealized gains on NDT fund investments			(51	)			59
Other non-cash operating activities			378				278
Changes in assets and liabilities:
Accounts receivable			—				(229	)
Inventories			17				1
Accounts payable, accrued expenses and other current liabilities			(486	)			(239	)
Option premiums received (paid), net			38				(15	)
Counterparty collateral posted, net			(494	)			(172	)
Income taxes			691				661
Pension and non-pension postretirement benefit contributions			(2,089	)			(119	)
Other assets and liabilities			(247	)			(9	)
Net cash flows provided by operating activities			1,013				2,369
Cash flows from investing activities
Capital expenditures			(1,985	)			(1,584	)
Proceeds from nuclear decommissioning trust fund sales			1,657				1,799
Investment in nuclear decommissioning trust funds			(1,772	)			(1,897	)
Change in restricted cash			(2	)			(6	)
Other investing activities			28				30
Net cash flows used in investing activities			(2,074	)			(1,658	)
Cash flows from financing activities
Changes in short-term debt			140				134
Issuance of long-term debt			599				—
Retirement of long-term debt			(2	)			(615	)
Retirement of long-term debt of variable interest entity			—				(402	)
Dividends paid on common stock			(695	)			(694	)
Proceeds from employee stock plans			15				22
Other financing activities			(46	)			2
Net cash flows provided by (used in) financing activities			11				(1,553	)
Decrease in cash and cash equivalents			(1,050	)			(842	)
Cash and cash equivalents at beginning of period			1,612				2,010
Cash and cash equivalents at end of period		$	562			$	1,168

 

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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 June 30, 2011												Three Months Ended June 30, 2010
		GAAP (a)				Adjustments				Adjusted Non-GAAP				GAAP (a)				Adjustments				Adjusted Non-GAAP
Operating revenues		$	4,587			$	(8	) (c)		$	4,579			$	4,398			$	10	(h),(i)		$	4,408
Operating expenses
Purchased power			1,407				(94	) (d)			1,313				1,134				(150	) (d)			984
Fuel			400				(30	) (d)			370				393				26	(d)			419
Operating and maintenance			1,185				(15	) (c),(e),(f)			1,170				1,114				—				1,114
Operating and maintenance for regulatory required programs (b)			41				—				41				34				—				34
Depreciation and amortization			329				(22	) (c)			307				519				(19	) (c)			500
Taxes other than income			191				—				191				186				—				186
Total operating expenses			3,553				(161	)			3,392				3,380				(143	)			3,237
Operating income			1,034				153				1,187				1,018				153				1,171
Other income and deductions
Interest expense			(182	)			—				(182	)			(275	)			103	(j)			(172	)
Other, net			100				(25	) (g)			75				(122	)			159	(g),(j)			37
Total other income and deductions			(82	)			(25	)			(107	)			(397	)			262				(135	)
Income before income taxes			952				128				1,080				621				415				1,036
Income taxes			332				51	(c),(d),(e),  (f),(g)			383				176				204	(c),(d),(g),  (h),(i),(j)			380
Net income		$	620			$	77			$	697			$	445			$	211			$	656
Effective tax rate			34.9	%							35.5	%			28.3	%							36.7	%
Earnings per average common share
Basic		$	0.93			$	0.12			$	1.05			$	0.67			$	0.32			$	0.99
Diluted		$	0.93			$	0.12			$	1.05			$	0.67			$	0.32			$	0.99
Average common shares outstanding
Basic			663								663				661								661
Diluted			664								664				662								662
Effect of adjustments on earnings per average diluted common share recorded in accordance with GAAP:
Retirement of fossil generating units (c)						$	0.02											$	0.02
Mark-to-market impact of economic hedging activities (d)							0.12												0.11
Proposed acquisition costs (e)							0.02												—
Recovery of costs pursuant to distribution rate case order (f)							(0.03	)											—
Unrealized (gains) losses related to NDT fund investments (g)							(0.01	)											0.08
2007 Illinois electric rate settlement (h)							—												0.01
City of Chicago settlement (i)							—												—
Non-cash income tax matters (j)							—												0.10
Total adjustments						$	0.12											$	0.32

 

(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 costs associated with the planned retirement of fossil generating units and the impacts of the FERC approved reliability-must-run rate schedule.

(d)	Adjustment to exclude the mark-to-market impact of Exelon’s economic hedging activities.

(e)	Adjustment to exclude certain costs associated with Exelon’s proposed acquisitions of Constellation Energy Group, Inc. (Constellation).

(f)	Adjustment to exclude one-time benefits for the recovery of previously incurred costs related to the 2009 restructuring plan and for the passage of Federal health care legislation in 2010.

(g)	Adjustment to exclude the unrealized gains in 2011 and unrealized losses in 2010 associated with Generation’s NDT fund investments and the associated contractual accounting relating to income taxes.

(h)	Adjustment to exclude the impact of the 2007 Illinois electric rate settlement.

(i)	Adjustment to exclude the costs associated with ComEd’s 2007 settlement agreement with the City of Chicago.

(j)	Adjustment to exclude a 2010 remeasurement of income tax uncertainties.

 

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EXELON CORPORATION

Reconciliation of Adjusted (non-GAAP) Operating Earnings to GAAP Consolidated Statements of Operations

(unaudited)

(in millions, except per share data)

 

		Six Months Ended June 30, 2011												Six Months Ended June 30, 2010
		GAAP (a)				Adjustments				Adjusted Non-GAAP				GAAP (a)				Adjustments				Adjusted Non-GAAP
Operating revenues		$	9,638			$	(8	)(c)		$	9,630			$	8,859			$	13	(i),(j)		$	8,872
Operating expenses
Purchased power			2,891				(189	)(d)			2,702				1,792				35	(d)			1,827
Fuel			1,012				(83	)(d)			929				994				75	(d)			1,069
Operating and maintenance			2,370				(17	)(c),(e),(f)			2,353				2,175				2	(c)			2,177
Operating and maintenance for regulatory required programs (b)			79				—				79				61				—				61
Depreciation and amortization			656				(46	)(c)			610				1,033				(35	)(c)			998
Taxes other than income			394				—				394				383				—				383
Total operating expenses			7,402				(335	)			7,067				6,438				77				6,515
Operating income			2,236				327				2,563				2,421				(64	)			2,357
Other income and deductions
Interest expense			(363	)			—				(363	)			(459	)			103	(k)			(356	)
Other, net			194				(88	)(g)			106				(29	)			101	(g),(k)			72
Total other income and deductions			(169	)			(88	)			(257	)			(488	)			204				(284	)
Income before income taxes			2,067				239				2,306				1,933				140				2,073
Income taxes			779				51	(c),(d),(e),  (f),(g),(h)			830				739				15	(c),(d),(g),  (i),(j),(k),(l)			754
Net income		$	1,288			$	188			$	1,476			$	1,194			$	125			$	1,319
Effective tax rate			37.7%								36.0%				38.2%								36.4%
Earnings per average common share
Basic		$	1.94			$	0.28			$	2.22			$	1.81			$	0.19			$	2.00
Diluted		$	1.94			$	0.28			$	2.22			$	1.80			$	0.19			$	1.99
Average common shares outstanding
Basic			663								663				661								661
Diluted			664								664				662								662
Effect of adjustments on earnings per average diluted common share recorded in accordance with GAAP:
Retirement of fossil generating units (c)						$	0.04											$	0.03
Mark-to-market impact of economic hedging activities (d)							0.25												(0.10	)
Proposed acquisition costs (e)							0.02												—
Recovery of costs pursuant to distribution rate case order (f)							(0.03	)											—
Unrealized (gains) losses related to NDT fund investments (g)							(0.04	)											0.05
Charge resulting from Illinois tax rate change legislation (h)							0.04												—
2007 Illinois electric rate settlement (i)							—												0.01
City of Chicago settlement (j)							—												—
Non-cash income tax matters (k)							—												0.10
Charge resulting from health care legislation (l)							—												0.10
Total adjustments						$	0.28											$	0.19

 

(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 costs associated with the planned retirement of fossil generating units and the impacts of the FERC approved reliability-must-run rate schedule.

(d)	Adjustment to exclude the mark-to-market impact of Exelon’s economic hedging activities.

(e)	Adjustment to exclude certain costs associated with Exelon’s proposed acquisition of Constellation.

(f)	Adjustment to exclude one-time benefits for the recovery of previously incurred costs related to the 2009 restructuring plan and for the passage of Federal health care legislation in 2010.

(g)	Adjustment to exclude the unrealized gains in 2011 and unrealized losses in 2010 associated with Generation’s NDT fund investments and the associated contractual accounting relating to income taxes.

(h)	Adjustment to exclude a one-time, non-cash charge to remeasure deferred taxes at higher corporate tax rates pursuant to the Illinois tax rate change legislation.

(i)	Adjustment to exclude the impact of the 2007 Illinois electric rate settlement.

(j)	Adjustment to exclude the costs associated with ComEd’s 2007 settlement agreement with the City of Chicago.

(k)	Adjustment to exclude a 2010 remeasurement of income tax uncertainties.

(l)	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.

 

8

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EXELON CORPORATION

Reconciliation of Adjusted (non-GAAP) Operating

Earnings to GAAP Earnings (in millions)

Three Months Ended June 30, 2011 and 2010

 

		Exelon Earnings per Diluted  Share				Generation				ComEd				PECO				Other (a)				Exelon
2010 GAAP Earnings (Loss)		$	0.67			$	382			$	9			$	75			$	(21	)		$	445
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			0.11				75				—				—				—				75
Unrealized Losses Related to NDT Fund Investments (1)			0.08				53				—				—				—				53
City of Chicago Settlement with ComEd			—				—				2				—				—				2
Non-Cash Remeasurement of Income Tax Uncertainties (2)			0.10				(70	)			106				22				7				65
Retirement of Fossil Generating Units (3)			0.02				12				—				—				—				12
2010 Adjusted (non-GAAP) Operating Earnings (Loss)			0.99				456				117				97				(14	)			656
Year Over Year Effects on Earnings:
Generation Energy Margins, Excluding Mark-to-Market:
Nuclear Volume (4)			(0.05	)			(34	)			—				—				—				(34	)
Nuclear Fuel Costs (5)			(0.02	)			(15	)			—				—				—				(15	)
Capacity Pricing			(0.01	)			(6	)			—				—				—				(6	)
Market and Portfolio Conditions (6)			0.22				150				—				—				—				150
Transmission Upgrades (7)			—				(6	)			—				—				6				—
ComEd and PECO Margins:
Weather			(0.01	)			—				(4	)			(4	)			—				(8	)
Load			—				—				(2	)			—				—				(2	)
Other Energy Delivery (8)			0.04				—				7				21				—				28
2010 Competitive Transition Charge (CTC), Net (9)			(0.06	)			—				—				(41	)			—				(41	)
Discrete Impacts of Distribution Rate Case Order (10)			0.03				—				22				—				—				22
Operating and Maintenance Expense:
Bad Debt			(0.01	)			(1	)			(4	)			(3	)			—				(8	)
Labor, Contracting and Materials (11)			(0.05	)			(13	)			(10	)			(8	)			—				(31	)
Planned Nuclear Refueling Outages (12)			(0.04	)			(26	)			—				—				—				(26	)
Other Operating and Maintenance (13)			—				(4	)			(2	)			9				(2	)			1
Depreciation and Amortization Expense (14)			(0.03	)			(13	)			(4	)			(3	)			(1	)			(21	)
Nuclear Decommissioning Trust Fund Special Transfer Tax Deduction (15)			0.07				41				—				—				2				43
Income Taxes (16)			(0.01	)			2				—				(7	)			—				(5	)
Interest Expense, Net (17)			(0.01	)			(7	)			(7	)			4				6				(4	)
Other (18)			—				(1	)			(16	)			18				(3	)			(2	)
2011 Adjusted (non-GAAP) Operating Earnings (Loss)			1.05				523				97				83				(6	)			697
2011 Adjusted (non-GAAP) Operating Earnings (Loss) Adjustments:
Mark-to-Market Impact of Economic Hedging Activities			(0.12	)			(75	)			—				—				—				(75	)
Unrealized Gains Related to NDT Fund Investments (1)			0.01				6				—				—				—				6
Retirement of Fossil Generating Units (3)			(0.02	)			(10	)			—				—				—				(10	)
Recovery of Costs Pursuant to Distribution Rate Case Order (19)			0.03				—				17				—				—				17
Constellation Merger Costs (20)			(0.02	)			(1	)			—				—				(14	)			(15	)
2011 GAAP Earnings (Loss)		$	0.93			$	443			$	114			$	83			$	(20	)		$	620

 

(a)	Other primarily includes eliminating and consolidating adjustments, Exelon’s corporate operations, shared service entities and other financing and investment activities.

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(1)	Reflects the impact of unrealized losses in 2010 and unrealized gains in 2011 on NDT fund investments to the extent not offset by contractual accounting as described in the notes to the consolidated financial statements.

(2)	Reflects the impact of a remeasurement of income tax uncertainties related to ComEd’s 1999 sale of fossil generating assets and CTCs received by PECO.

(3)

Primarily reflects accelerated depreciation expense associated with the planned retirement of four generating units, two of which retired on May 31, 2011. Beginning June 1, 2011, reflects the net loss attributable to the remaining two units, which includes compensation for operating the units past their planned May 31, 2011 retirement date under a FERC-approved reliability-must-run rate schedule.

(4)	Primarily reflects the impact of increased planned and unplanned nuclear outage days in 2011.

(5)	Reflects the impact of higher nuclear fuel prices.

(6)	Primarily reflects the impact of increased realized market prices for the sale of energy in the Mid-Atlantic region due to the end of the PECO Power Purchase Agreement (PPA), energy margins at Exelon Wind, which was acquired in December 2010, and other favorable market and portfolio conditions.

(7)	Reflects intercompany expense at Generation for upgrades in transmission assets owned by ComEd, which are reflected as assets at Exelon Corporate.

(8)

For ComEd, includes increased distribution revenue pursuant to the 2011 electric distribution rate case order, effective June 1, 2011. For PECO, primarily reflects increased distribution revenue pursuant to the 2010 Pennsylvania electric and natural gas distribution rate cases effective January 1, 2011.

(9)	Reflects the impact of 2010 CTC recoveries, net of amortization expense, associated with PECO’s transition period, which ended on December 31, 2010.

(10)	Primarily reflects one-time net benefits pursuant to the 2011 ComEd electric distribution rate case order to reestablish previously expensed plant balances and to recognize the estimated recovery of funds for working capital related to the procurement of energy.

(11)	Primarily reflects the impacts of increased wages and other benefits and increased contracting expenses, including Exelon Wind (exclusive of planned nuclear refueling outages and incremental storm costs as disclosed in numbers 12 and 13 below).

(12)	Primarily reflects the impact of increased planned nuclear outage days in 2011, excluding Salem.

(13)	Primarily reflects decreased storm costs in the PECO service territories.

(14)	Primarily reflects increased depreciation expense across the operating companies due to ongoing capital expenditures and the impacts of Exelon Wind.

(15)

Reflects one-time interest and tax benefits associated with a change in the timing of the deduction for the transfer of cash or investments from nonqualified nuclear decommissioning trust funds to qualified decommissioning trust funds pursuant to the Energy Policy Act of 2005 and recently issued Treasury Regulations.

(16)

Primarily reflects a reduction in Generation’s manufacturing deduction benefits (given reduced taxable income as a result of bonus depreciation), higher corporate tax rates pursuant to the Illinois tax rate change legislation and increased Pennsylvania state tax expense resulting from the expiration of the CTCs and associated tax planning benefits, partially offset by benefits associated with Pennsylvania bonus depreciation and production tax credits at Exelon Wind.

(17)	Reflects higher interest expense at Generation and ComEd due to higher outstanding debt, partially offset by lower interest expense at PECO resulting from the retirement of the PECO Energy Transition Trust (PETT) transition bonds on September 1, 2010 and lower outstanding debt at Corporate.

(18)	For ComEd, primarily reflects Illinois electric distribution taxes recorded in 2010. For PECO, primarily reflects decreased gross receipts tax (completely offset by decreased PECO margins above).

(19)	Reflects one-time benefits pursuant to the ComEd 2011 electric distribution rate case order for the recovery of previously incurred costs related to the 2009 restructuring plan and for the passage of Federal health care legislation in 2010.

(20)	Reflects certain costs incurred associated with Exelon’s proposed merger with Constellation.

 

9

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EXELON CORPORATION

Reconciliation of Adjusted (non-GAAP) Operating

Earnings to GAAP Earnings (in millions)

Six Months Ended June 30, 2011 and 2010

 

		Exelon Earnings per Diluted  Share				Generation				ComEd				PECO				Other (a)				Exelon
2010 GAAP Earnings (Loss)		$	1.80			$	943			$	125			$	176			$	(50	)		$	1,194
2010 Adjusted (non-GAAP) Operating Earnings (Loss) Adjustments:
2007 Illinois Electric Rate Settlement			0.01				6				1				—				—				7
Mark-to-Market Impact of Economic Hedging Activities			(0.10	)			(67	)			—				—				—				(67	)
Unrealized Losses Related to NDT Fund Investments (1)			0.05				33				—				—				—				33
City of Chicago Settlement with ComEd			—				—				2				—				—				2
Non-Cash Charge Resulting From Health Care Legislation (2)			0.10				26				12				10				17				65
Non-Cash Remeasurement of Income Tax Uncertainties (3)			0.10				(70	)			106				22				7				65
Retirement of Fossil Generating Units (4)			0.03				20				—				—				—				20
2010 Adjusted (non-GAAP) Operating Earnings (Loss)			1.99				891				246				208				(26	)			1,319
Year Over Year Effects on Earnings:
Generation Energy Margins, Excluding Mark-to-Market:
Nuclear Volume (5)			(0.01	)			(4	)			—				—				—				(4	)
Nuclear Fuel Costs (6)			(0.03	)			(23	)			—				—				—				(23	)
Capacity Pricing			0.05				31				—				—				—				31
Market and Portfolio Conditions (7)			0.44				291				—				—				—				291
Transmission Upgrades (8)			—				(6	)			—				—				6				—
ComEd and PECO Margins:
Weather			—				—				(1	)			(1	)			—				(2	)
Load			(0.01	)			—				(3	)			(3	)			—				(6	)
Other Energy Delivery (9)			0.10				—				8				58				—				66
2010 CTC, Net (10)			(0.11	)			—				—				(72	)			—				(72	)
Discrete Impacts of Distribution Rate Case Order (11)			0.03				—				22				—				—				22
Operating and Maintenance Expense:
Bad Debt			(0.01	)			1				(1	)			(4	)			—				(4	)
Labor, Contracting and Materials (12)			(0.12	)			(40	)			(20	)			(17	)			—				(77	)
Planned Nuclear Refueling Outages			(0.01	)			(7	)			—				—				—				(7	)
Pension and Non-Pension Postretirement Benefits (13)			0.01				5				(2	)			3				2				8
2010 Recovery of Bad Debt Expense at ComEd (14)			(0.06	)			—				(36	)			—				—				(36	)
Other Operating and Maintenance			(0.01	)			(4	)			(2	)			10				(12	)			(8	)
Depreciation and Amortization Expense (15)			(0.06	)			(27	)			(7	)			(6	)			4				(36	)
Nuclear Decommissioning Trust Fund Special Transfer Tax Deduction (16)			0.07				41				—				—				2				43
Income Taxes (17)			(0.01	)			6				3				(8	)			(10	)			(9	)
Interest Expense, Net (18)			—				(14	)			(9	)			11				11				(1	)
Other (19)			(0.03	)			(20	)			(28	)			31				(2	)			(19	)
2011 Adjusted (non-GAAP) Operating Earnings (Loss)			2.22				1,121				170				210				(25	)			1,476
2011 Adjusted (non-GAAP) Operating Earnings (Loss) Adjustments:
Mark-to-Market Impact of Economic Hedging Activities			(0.25	)			(164	)			—				—				—				(164	)
Unrealized Gains Related to NDT Fund Investments (1)			0.04				30				—				—				—				30
Retirement of Fossil Generating Units (4)			(0.04	)			(27	)			—				—				—				(27	)
Non-Cash Charge Resulting From Illinois Tax Rate Change Legislation (20)			(0.04	)			(21	)			(4	)			—				(4	)			(29	)
Recovery of Costs Pursuant to Distribution Rate Case Order (21)			0.03				—				17				—				—				17
Constellation Merger Costs (22)			(0.02	)			(1	)			—				—				(14	)			(15	)
2011 GAAP Earnings (Loss)		$	1.94			$	938			$	183			$	210			$	(43	)		$	1,288

 

(a)	Other primarily includes eliminating and consolidating adjustments, Exelon’s corporate operations, shared service entities and other financing and investment activities.

(1)	Reflects the impact of unrealized losses in 2010 and unrealized gains in 2011 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 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.

(3)	Reflects the impact of a remeasurement of income tax uncertainties related to ComEd’s 1999 sale of fossil generating assets and CTCs received by PECO.

(4)

Primarily reflects accelerated depreciation expense associated with the planned retirement of four generating units, two of which retired on May 31, 2011. Beginning June 1, 2011, reflects the net loss attributable to the remaining two units, which includes compensation for operating the units past their planned May 31, 2011 retirement date under a FERC-approved reliability-must-run rate schedule.

(5)	Primarily reflects the impact of increased planned and unplanned nuclear outage days in 2011.

(6)	Reflects the impact of higher nuclear fuel prices.

(7)	Primarily reflects the impact of increased realized market prices for the sale of energy in the Mid-Atlantic region due to the end of the PECO PPA, energy margins at Exelon Wind, which was acquired in December 2010, and other favorable market and portfolio conditions.

(8)	Reflects intercompany expense at Generation for upgrades in transmission assets owned by ComEd, which are reflected as assets at Exelon Corporate.

(9)

For ComEd, includes increased distribution revenue pursuant to the 2011 electric distribution rate case order, effective June 1, 2011. For PECO, primarily reflects increased distribution revenue pursuant to the 2010 Pennsylvania electric and natural gas distribution rate cases effective January 1, 2011.

(10)	Reflects the impact of 2010 CTC recoveries, net of amortization expense, associated with PECO’s transition period, which ended on December 31, 2010.

(11)	Primarily reflects one-time net benefits pursuant to the 2011 ComEd electric distribution rate case order to reestablish previously expensed plant balances and to recognize the estimated recovery of funds for working capital related to the procurement of energy.

(12)	Primarily reflects the impacts of increased wages and other benefits and increased contracting expenses, including Exelon Wind (exclusive of planned nuclear refueling outages and incremental storm costs).

(13)	Primarily reflects the impact of the $2.1 billion pension contribution made in January 2011, partially offset by the lower assumed discount rate and expected return on plan assets used in 2011 as compared to 2010 to calculate the pension and other postretirement benefit obligations and costs.

(14)	Reflects a 2010 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.

(15)	Primarily reflects increased depreciation expense across the operating companies due to ongoing capital expenditures and the impacts of Exelon Wind.

(16)

Reflects one-time interest and tax benefits associated with a change in the timing of the deduction for the transfer of cash or investments from nonqualified nuclear decommissioning trust funds to qualified decommissioning trust funds pursuant to the Energy Policy Act of 2005 and recently issued Treasury Regulations.

(17)

Primarily reflects a reduction in Generation’s manufacturing deduction benefits (given reduced taxable income as a result of bonus depreciation), higher corporate tax rates pursuant to the Illinois tax rate change legislation and increased Pennsylvania state tax expense resulting from the expiration of the CTCs and associated tax planning benefits, partially offset by benefits associated with Pennsylvania bonus depreciation and production tax credits at Exelon Wind.

(18)	Primarily reflects higher interest expense at Generation and ComEd due to higher outstanding debt, partially offset by lower interest expense at PECO resulting from the retirement of the PECO PETT transition bonds on September 1, 2010 and lower outstanding debt at Corporate.

(19)

Primarily reflects increased gross receipts tax at Generation (completely offset by increased Generation margins above) and Illinois electric distribution tax refunds recorded in 2010 at ComEd, partially offset by decreased gross receipts tax at PECO (completely offset by decreased PECO margins above).

(20)	Reflects the impact of a one-time, non-cash charge to remeasure deferred taxes at higher corporate tax rates pursuant to the Illinois tax rate change legislation.

(21)	Reflects one-time benefits pursuant to the ComEd 2011 electric distribution rate case order for the recovery of previously incurred costs related to the 2009 restructuring plan and for the passage of Federal health care legislation in 2010.

(22)	Reflects certain costs incurred associated with Exelon’s proposed merger with Constellation.

 

10

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EXELON CORPORATION

Reconciliation of Adjusted (non-GAAP) Operating Earnings to

GAAP Consolidated Statements of Operations

(unaudited)

(in millions)

 

		Generation
		Three Months Ended June 30, 2011												Three Months Ended June 30, 2010
		GAAP (a)				Adjustments				Adjusted Non- GAAP				GAAP (a)				Adjustments				Adjusted Non- GAAP
Operating revenues		$	2,546			$	(8	)(b)		$	2,538			$	2,353			$	7	(f)		$	2,360
Operating expenses
Purchased power			572				(94	)(c)			478				549				(150	)(c)			399
Fuel			360				(30	)(c)			330				350				26	(c)			376
Operating and maintenance			763				(4	)(b),(d)			759				691				—				691
Depreciation and amortization			138				(22	)(b)			116				115				(19	)(b)			96
Taxes other than income			66				—				66				61				—				61
Total operating expenses			1,899				(150	)			1,749				1,766				(143	)			1,623
Operating income			647				142				789				587				150				737
Other income and deductions
Interest expense			(45	)			—				(45	)			(37	)			—				(37	)
Other, net			76				(25	)(e)			51				(133	)			157	(e)			24
Total other income and deductions			31				(25	)			6				(170	)			157				(13	)
Income before income taxes			678				117				795				417				307				724
Income taxes			235				37	(b),(c),(d),  (e)			272				35				233	(b),(c),(e),  (f),(g)			268
Net income		$	443			$	80			$	523			$	382			$	74			$	456
		Six Months Ended June 30, 2011												Six Months Ended June 30, 2010
		GAAP (a)				Adjustments				Adjusted Non- GAAP				GAAP (a)				Adjustments				Adjusted Non- GAAP
Operating revenues		$	5,285			$	(8	)(b)		$	5,277			$	4,773			$	9	(f)		$	4,782
Operating expenses
Purchased power			1,121				(189	)(c)			932				757				35	(c)			792
Fuel			790				(83	)(c)			707				740				74	(c)			814
Operating and maintenance			1,517				(6	)(b),(d)			1,511				1,432				(2	)(b),(i)			1,430
Depreciation and amortization			277				(46	)(b)			231				223				(35	)(b)			188
Taxes other than income			132				—				132				118				—				118
Total operating expenses			3,837				(324	)			3,513				3,270				72				3,342
Operating income			1,448				316				1,764				1,503				(63	)			1,440
Other income and deductions
Interest expense			(91	)			—				(91	)			(72	)			—				(72	)
Other, net			152				(88	)(e)			64				(54	)			99	(e)			45
Total other income and deductions			61				(88	)			(27	)			(126	)			99				(27	)
Income before income taxes			1,509				228				1,737				1,377				36				1,413
Income taxes			571				45	(b),(c),(d),  (e),(h)			616				434				88	(b),(c),(e),  (f),(g),(i)			522
Net income		$	938			$	183			$	1,121			$	943			$	(52	)		$	891

 

(a)	Results reported in accordance with GAAP.

(b)	Adjustment to exclude costs associated with the planned retirement of fossil generating units and the impacts of the FERC approved reliability-must-run rate schedule.

(c)	Adjustment to exclude the mark-to-market impact of Generation’s economic hedging activities.

(d)	Adjustment to exclude certain costs associated with Exelon’s proposed acquisition of Constellation.

(e)	Adjustment to exclude the unrealized gains in 2011 and unrealized losses in 2010 associated with Generation’s NDT fund investments and the associated contractual accounting relating to income taxes.

(f)	Adjustment to exclude the impact of the 2007 Illinois electric rate settlement.

(g)	Adjustment to exclude a 2010 remeasurement of income tax uncertainties.

(h)	Adjustment to exclude a one-time, non-cash charge to remeasure deferred taxes at higher corporate tax rates pursuant to the Illinois tax rate change legislation.

(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.

 

11

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EXELON CORPORATION

Reconciliation of Adjusted (non-GAAP) Operating Earnings to

GAAP Consolidated Statements of Operations

(unaudited)

(in millions)

 

		ComEd
		Three Months Ended June 30, 2011												Three Months Ended June 30, 2010
		GAAP (a)				Adjustments				Adjusted Non- GAAP				GAAP (a)				Adjustments				Adjusted Non- GAAP
Operating revenues		$	1,444			$	—			$	1,444			$	1,499			$	3	(d)		$	1,502
Operating expenses
Purchased power			716				—				716				771				—				771
Operating and maintenance			245				13	(c)			258				276				—				276
Operating and maintenance for regulatory required programs (b)			23				—				23				21				—				21
Depreciation and amortization			136				—				136				131				—				131
Taxes other than income			70				—				70				44				—				44
Total operating expenses			1,190				13				1,203				1,243				—				1,243
Operating income			254				(13	)			241				256				3				259
Other income and deductions
Interest expense			(86	)			—				(86	)			(134	)			59	(e)			(75	)
Other, net			4				—				4				8				—				8
Total other income and deductions			(82	)			—				(82	)			(126	)			59				(67	)
Income before income taxes			172				(13	)			159				130				62				192
Income taxes			58				4	(c)			62				121				(46	)(d),(e)			75
Net income		$	114			$	(17	)		$	97			$	9			$	108			$	117
		Six Months Ended June 30, 2011												Six Months Ended June 30, 2010
		GAAP (a)				Adjustments				Adjusted Non- GAAP				GAAP (a)				Adjustments				Adjusted Non- GAAP
Operating revenues		$	2,910			$	—			$	2,910			$	2,914			$	4	(d),(g)		$	2,918
Operating expenses
Purchased power			1,505				—				1,505				1,524				—				1,524
Operating and maintenance			493				13	(c)			506				435				(3	)(h)			432
Operating and maintenance for regulatory required programs (b)			41				—				41				40				—				40
Depreciation and amortization			270				—				270				261				—				261
Taxes other than income			147				—				147				107				—				107
Total operating expenses			2,456				13				2,469				2,367				(3	)			2,364
Operating income			454				(13	)			441				547				7				554
Other income and deductions
Interest expense			(172	)			—				(172	)			(218	)			59	(e)			(159	)
Other, net			8				—				8				11				—				11
Total other income and deductions			(164	)			—				(164	)			(207	)			59				(148	)
Income before income taxes			290				(13	)			277				340				66				406
Income taxes			107				—	(c),(f)			107				215				(55	)(d),(e),(g),(h)			160
Net income		$	183			$	(13	)		$	170			$	125			$	121			$	246

 

(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 one-time benefits for the recovery of previously incurred costs related to the 2009 restructuring plan and for the passage of Federal health care legislation in 2010.

(d)	Adjustment to exclude the costs associated with ComEd’s 2007 settlement agreement with the City of Chicago.

(e)	Adjustment to exclude a 2010 remeasurement of income tax uncertainties.

(f)	Adjustment to exclude a one-time, non-cash charge to remeasure deferred taxes at higher corporate tax rates pursuant to the Illinois tax rate change legislation.

(g)	Adjustment to exclude the impact of the 2007 Illinois electric rate settlement.

(h)	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.

 

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EXELON CORPORATION

Reconciliation of Adjusted (non-GAAP) Operating Earnings to

GAAP Consolidated Statements of Operations

(unaudited)

(in millions)

 

		PECO
		Three Months Ended June 30, 2011												Three Months Ended June 30, 2010
		GAAP (a)				Adjustments				Adjusted Non- GAAP				GAAP (a)				Adjustments				Adjusted Non- GAAP
Operating revenues		$	842			$	—			$	842			$	1,269			$	—			$	1,269
Operating expenses
Purchased power			368				—				368				535				—				535
Fuel			40				—				40				44				—				44
Operating and maintenance			154				—				154				150				—				150
Operating and maintenance for regulatory required programs (b)			18				—				18				13				—				13
Depreciation and amortization			50				—				50				268				—				268
Taxes other than income			51				—				51				77				—				77
Total operating expenses			681				—				681				1,087				—				1,087
Operating income			161				—				161				182				—				182
Other income and deductions
Interest expense			(34	)			—				(34	)			(77	)			36	(c)			(41	)
Other, net			3				—				3				(1	)			2	(c)			1
Total other income and deductions			(31	)			—				(31	)			(78	)			38				(40	)
Income before income taxes			130				—				130				104				38				142
Income taxes			47				—				47				29				16	(c)			45
Net income		$	83			$	—			$	83			$	75			$	22			$	97
		Six Months Ended June 30, 2011												Six Months Ended June 30, 2010
		GAAP (a)				Adjustments				Adjusted Non- GAAP				GAAP (a)				Adjustments				Adjusted Non- GAAP
Operating revenues		$	1,996			$	—			$	1,996			$	2,724			$	—			$	2,724
Operating expenses
Purchased power			820				—				820				1,059				—				1,059
Fuel			222				—				222				255				—				255
Operating and maintenance			340				—				340				331				(2	)(d)			329
Operating and maintenance for regulatory required programs (b)			38				—				38				21				—				21
Depreciation and amortization			98				—				98				533				—				533
Taxes other than income			106				—				106				150				—				150
Total operating expenses			1,624				—				1,624				2,349				(2	)			2,347
Operating income			372				—				372				375				2				377
Other income and deductions
Interest expense			(68	)			—				(68	)			(122	)			36	(c)			(86	)
Other, net			8				—				8				4				2	(c)			6
Total other income and deductions			(60	)			—				(60	)			(118	)			38				(80	)
Income before income taxes			312				—				312				257				40				297
Income taxes			102				—				102				81				8	(c),(d)			89
Net income		$	210			$	—			$	210			$	176			$	32			$	208

 

(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 2010 remeasurement of income tax uncertainties.

(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.

 

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EXELON CORPORATION

Reconciliation of Adjusted (non-GAAP) Operating Earnings to

GAAP Consolidated Statements of Operations

(unaudited)

(in millions)

 

		Other (a)
		Three Months Ended June 30, 2011												Three Months Ended June 30, 2010
		GAAP (b)				Adjustments				Adjusted Non- GAAP				GAAP (b)				Adjustments				Adjusted Non- GAAP
Operating revenues		$	(245	)		$	—			$	(245	)		$	(723	)		$	—			$	(723	)
Operating expenses
Purchased power			(249	)			—				(249	)			(721	)			—				(721	)
Fuel			—				—				—				(1	)			—				(1	)
Operating and maintenance			23				(24	)(c)			(1	)			(3	)			—				(3	)
Depreciation and amortization			5				—				5				5				—				5
Taxes other than income			4				—				4				4				—				4
Total operating expenses			(217	)			(24	)			(241	)			(716	)			—				(716	)
Operating loss			(28	)			24				(4	)			(7	)			—				(7	)
Other income and deductions
Interest expense			(17	)			—				(17	)			(27	)			8	(d)			(19	)
Other, net			17				—				17				4				—				4
Total other income and deductions			—				—				—				(23	)			8				(15	)
Loss before income taxes			(28	)			24				(4	)			(30	)			8				(22	)
Income taxes			(8	)			10	(c)			2				(9	)			1	(d)			(8	)
Net loss		$	(20	)		$	14			$	(6	)		$	(21	)		$	7			$	(14	)
		Six Months Ended June 30, 2011												Six Months Ended June 30, 2010
		GAAP (b)				Adjustments				Adjusted Non- GAAP				GAAP (b)				Adjustments				Adjusted Non- GAAP
Operating revenues		$	(553	)		$	—			$	(553	)		$	(1,552	)		$	—			$	(1,552	)
Operating expenses
Purchased power			(555	)			—				(555	)			(1,548	)			—				(1,548	)
Fuel			—				—				—				(1	)			—				(1	)
Operating and maintenance			20				(24	)(c)			(4	)			(23	)			8	(f)			(15	)
Depreciation and amortization			11				—				11				16				—				16
Taxes other than income			9				—				9				8				—				8
Total operating expenses			(515	)			(24	)			(539	)			(1,548	)			8				(1,540	)
Operating loss			(38	)			24				(14	)			(4	)			(8	)			(12	)
Other income and deductions
Interest expense			(32	)			—				(32	)			(47	)			8	(d)			(39	)
Other, net			26				—				26				10				—				10
Total other income and deductions			(6	)			—				(6	)			(37	)			8				(29	)
Loss before income taxes			(44	)			24				(20	)			(41	)			—				(41	)
Income taxes			(1	)			6	(c),(e)			5				9				(24	)(d),(f)			(15	)
Net loss		$	(43	)		$	18			$	(25	)		$	(50	)		$	24			$	(26	)

 

(a)	Other primarily includes eliminating and consolidating adjustments, Exelon’s corporate operations, shared service entities and other financing and investment activities.

(b)	Results reported in accordance with GAAP.

(c)	Adjustment to exclude certain costs associated with Exelon’s proposed acquisition of Constellation.

(d)	Adjustment to exclude a 2010 remeasurement of income tax uncertainties.

(e)	Adjustment to exclude a one-time, non-cash charge to remeasure deferred taxes at higher corporate tax rates pursuant to the Illinois tax rate change legislation.

(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.

 

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EXELON CORPORATION

Exelon Generation Statistics

 

		Three Months Ended
		Jun. 30, 2011				Mar. 31, 2011				Dec. 31, 2010				Sept. 30, 2010				Jun. 30, 2010
Supply (in GWhs)
Nuclear Generation (a)
Mid-Atlantic			11,172				12,370				11,974				12,076				11,691
Midwest			21,995				22,822				23,141				23,675				23,344
Total Nuclear Generation			33,167				35,192				35,115				35,751				35,035
Fossil and Renewables
Mid-Atlantic (a) (b)			2,054				2,166				2,115				2,582				2,175
Midwest (c)			163				157				45				16				7
South and West (c)			638				509				93				691				310
Total Fossil and Renewables			2,855				2,832				2,253				3,289				2,492
Purchased Power
Mid-Atlantic			707				750				442				599				414
Midwest			1,659				1,412				1,776				1,774				1,568
South and West			2,411				2,181				2,632				4,084				2,695
Total Purchased Power			4,777				4,343				4,850				6,457				4,677
Total Supply by Region
Mid-Atlantic			13,933				15,286				14,531				15,257				14,280
Midwest			23,817				24,391				24,962				25,465				24,919
South and West			3,049				2,690				2,725				4,775				3,005
			40,799				42,367				42,218				45,497				42,204
		Three Months Ended
		Jun. 30, 2011				Mar. 31, 2011				Dec. 31, 2010				Sept. 30, 2010				Jun. 30, 2010
Electric Sales (in GWhs)
ComEd (d)			—				—				—				—				1,895
PECO (d)			—				—				9,756				11,976				10,044
Market and Retail (d)			40,799				42,367				32,462				33,521				30,265
Total Electric Sales (d) (e)			40,799				42,367				42,218				45,497				42,204
Average Margin ($/MWh) (f)(g)(h)
Mid-Atlantic		$	58.92			$	59.92			$	51.75			$	36.97			$	40.83
Midwest			37.28				39.60				41.14				41.00				40.78
South and West			(3.61	)			(1.49	)			(10.64	)			(2.30	)			(14.31	)
Average Margin - Overall Portfolio		$	41.59			$	44.30			$	41.45			$	35.11			$	36.87
Around-the-clock Market Prices ($/MWh) (i)
PJM West Hub		$	47.27			$	45.82			$	43.65			$	52.25			$	43.21
NiHub			34.94				34.10				27.26				38.32				32.35
ERCOT North Spark Spread			6.73				8.00				(0.69	)			8.25				1.52

 

(a)	Includes Generation’s proportionate share of the output of its jointly owned generating plants.

(b)	Includes New England generation.

(c)	Includes generation from Exelon Wind, acquired in December, 2010, of 154 GWh, 155 GWh and 41GWh in the Midwest and 431 GWh, 358 GWh and 84 GWh in the South and West for the three months ended June 30, 2011, March 31, 2011 and December 31, 2010, respectively.

(d)	ComEd and PECO line items represent sales under the 2006 ComEd Auction and the PECO PPA, respectively. Settlements of the ComEd swap, sales under the Request for Proposal (RFP) and sales to PECO through the competitive procurement process are included within Market and Retail sales.

(e)	Total sales do not include physical trading volume of 1,496 GWhs, 1,333 GWhs, 740 GWhs, 1,077 GWhs and 889 GWhs for the three months ended June 30, 2011, March 31, 2011, December 31, 2010, September 30, 2010 and June 30, 2010, respectively.

(f)

Excludes retail gas activity, trading portfolio activity, the $57 million lower of cost or market impairment of certain SO2 allowances recorded in the three months ended September 30, 2010, amounts paid related to the Illinois Settlement Legislation and compensation under the reliability-must-run rate schedule.

(g)	Excludes the mark-to-market impact of Generation’s economic hedging activities.

(h)	Results of transactions with PECO and ComEd are included in the Mid-Atlantic and Midwest regions, respectively.

(i)	Represents the average for the quarter.

 

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EXELON CORPORATION

Exelon Generation Statistics

Six Months Ended June 30, 2011 and 2010

 

		June 30, 2011				June 30, 2010
Supply (in GWhs)
Nuclear Generation (a)
Mid-Atlantic			23,543				23,467
Midwest			44,816				45,677
Total Nuclear Generation			68,359				69,144
Fossil and Renewables
Mid-Atlantic (a) (b)			4,220				4,739
Midwest (c)			320				7
South and West (c)			1,147				429
Total Fossil and Renewables			5,687				5,175
Purchased Power
Mid-Atlantic			1,457				877
Midwest			3,071				3,482
South and West			4,593				5,396
Total Purchased Power			9,121				9,755
Total Supply by Region
Mid-Atlantic			29,220				29,083
Midwest			48,207				49,166
South and West			5,740				5,825
			83,167				84,074
		June 30, 2011				June 30, 2010
Electric Sales (in GWhs)
ComEd (d)			—				5,323
PECO (d)			—				20,272
Market and Retail (d)			83,167				58,479
Total Electric Sales (e)			83,167				84,074
Average Margin ($/MWh) (f)(g)(h)
Mid-Atlantic		$	59.45			$	41.14
Midwest			38.40				40.88
South and West			(2.44	)			(15.62	)
Average Margin - Overall Portfolio		$	42.97			$	37.06
Around-the-clock Market Prices ($/MWh) (i)
PJM West Hub		$	46.55			$	43.87
NiHub			34.52				33.40
ERCOT North Spark Spread			3.34				0.75

 

(a)	Includes Generation’s proportionate share of the output of its jointly owned generating plants.

(b)	Includes New England generation.

(c)	Includes generation from Exelon Wind, acquired in December, 2010, of 309 GWh and 789 GWh in the Midwest and South, respectively.

(d)	ComEd and PECO line items represent sales under the 2006 ComEd Auction and PECO PPA. Settlements of the ComEd swap, sales under the RFP and sales to PECO through the competitive procurement process are included within Market and Retail sales.

(e)	Total sales do not include physical trading volume of 2,829 GWhs and 1,808 GWhs for the six months ended June 30, 2011 and 2010, respectively.

(f)	Excludes retail gas activity, trading portfolio activity, amounts paid related to the Illinois Settlement Legislation and compensation under the reliability-must-run rate schedule.

(g)	Excludes the mark-to-market impact of Generation’s economic hedging activities.

(h)	Results of transactions with PECO and ComEd are included in the Mid-Atlantic and Midwest regions, respectively.

(i)	Represents the average for the six months ended June 30, 2011 and 2010, respectively.

 

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EXELON CORPORATION

ComEd Statistics

Three Months Ended June 30, 2011 and 2010

 

		Electric Deliveries (in GWhs)																Revenue (in millions)
		2011				2010				% Change				Weather- Normal % Change				2011				2010				% Change
Retail Deliveries and Sales (a)
Residential			6,277				6,474				(3.0	)%			(1.6	)%		$	800			$	829				(3.5	)%
Small Commercial & Industrial			7,763				7,935				(2.2	)%			(0.2	)%			386				415				(7.0	)%
Large Commercial & Industrial			6,698				6,825				(1.9	)%			(0.9	)%			95				100				(5.0	)%
Public Authorities & Electric Railroads			286				277				3.2	%			3.2	%			12				16				(25.0	)%
Total Retail			21,024				21,511				(2.3	)%			(0.8	)%			1,293				1,360				(4.9	)%
Other Revenue (b)																			151				139				8.6	%
Total Electric Revenue																		$	1,444			$	1,499				(3.7	)%
Purchased Power																		$	716			$	771				(7.1	)%
														% Change
Heating and Cooling Degree-Days		2011				2010				Normal				From 2010				From Normal
Heating Degree-Days			823				519				766				58.6	%			7.4	%
Cooling Degree-Days			237				312				224				(24.0	)%			5.8	%
		Six Months Ended June 30, 2011 and 2010
		Electric Deliveries (in GWhs)																Revenue (in millions)
		2011				2010				% Change				Weather- Normal % Change				2011				2010				% Change
Retail Deliveries and Sales (a)
Residential			13,231				13,417				(1.4	)%			(1.7	)%		$	1,634			$	1,606				1.7	%
Small Commercial & Industrial			15,837				15,864				(0.2	)%			0.2	%			767				804				(4.6	)%
Large Commercial & Industrial			13,517				13,488				0.2	%			0.3	%			186				197				(5.6	)%
Public Authorities & Electric Railroads			616				645				(4.5	)%			(5.2	)%			26				33				(21.2	)%
Total Retail			43,201				43,414				(0.5	)%			(0.5	)%			2,613				2,640				(1.0	)%
Other Revenue (b)																			297				274				8.4	%
Total Electric Revenue																		$	2,910			$	2,914				(0.1	)%
Purchased Power																		$	1,505			$	1,524				(1.2	)%
														% Change
Heating and Cooling Degree-Days		2011				2010				Normal				From 2010				From Normal
Heating Degree-Days			4,155				3,629				3,974				14.5	%			4.6	%
Cooling Degree-Days			237				312				224				(24.0	)%			5.8	%
Number of Electric Customers		2011				2010
Residential			3,447,194				3,432,466
Small Commercial & Industrial			364,902				361,326
Large Commercial & Industrial			2,007				1,982
Public Authorities & Electric Railroads			4,914				5,072
Total			3,819,017				3,800,846

 

(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). Other items include late payment charges and mutual assistance program revenues.

 

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EXELON CORPORATION

PECO Statistics

Three Months Ended June 30, 2011 and 2010

 

		Electric and Gas Deliveries																Revenue (in millions)
		2011				2010				% Change				Weather- Normal % Change				2011				2010				% Change
Electric (in GWhs)
Retail Deliveries and Sales (a)
Residential			3,075				3,118				(1.4	)%			3.2	%		$	451			$	489				(7.8	)%
Small Commercial & Industrial			2,026				2,027				(0.0	)%			1.7	%			165				271				(39.1	)%
Large Commercial & Industrial			3,954				4,156				(4.9	)%			(3.3	)%			67				337				(80.1	)%
Public Authorities & Electric Railroads			229				225				1.8	%			1.8	%			9				24				(62.5	)%
Total Retail			9,284				9,526				(2.5	)%			(0.1	)%			692				1,121				(38.3	)%
Other Revenue (b)																			61				59				3.4	%
Total Electric Revenue																			753				1,180				(36.2	)%
Gas (in mmcfs)
Retail Deliveries and Sales (c)
Retail Sales			6,561				5,973				9.8	%			(1.3	)%			82				81				1.2	%
Transportation and Other			6,278				6,540				(4.0	)%			2.1	%			7				8				(12.5	)%
Total Gas			12,839				12,513				2.6	%			0.2	%			89				89				0.0	%
Total Electric and Gas Revenues																		$	842			$	1,269				(33.6	)%
Purchased Power																		$	368			$	535				(31.2	)%
Fuel																			40				44				(9.1	)%
Total Purchased Power and Fuel																		$	408			$	579				(29.5	)%
														% Change
Heating and Cooling Degree-Days		2011				2010				Normal				From 2010				From Normal
Heating Degree-Days			331				299				458				10.7	%			(27.7	)%
Cooling Degree-Days			494				586				332				(15.7	)%			48.8	%
		Six Months Ended June 30, 2011 and 2010
		Electric and Gas Deliveries																Revenue (in millions)
		2011				2010				% Change				Weather- Normal % Change				2011				2010				% Change
Electric (in GWhs)
Retail Deliveries and Sales (a)
Residential			6,665				6,645				0.3	%			1.7	%		$	944			$	962				(1.9	)%
Small Commercial & Industrial			4,165				4,177				(0.3	)%			0.2	%			334				519				(35.6	)%
Large Commercial & Industrial			7,642				7,950				(3.9	)%			(3.1	)%			175				661				(73.5	)%
Public Authorities & Electric Railroads			471				471				0.0	%			0.0	%			20				47				(57.4	)%
Total Retail			18,943				19,243				(1.6	)%			(0.6	)%			1,473				2,189				(32.7	)%
Other Revenue (b)																			126				120				5.0	%
Total Electric Revenue																			1,599				2,309				(30.7	)%
Gas (in mmcfs)
Retail Deliveries and Sales (c)
Retail Sales			35,295				33,557				5.2	%			0.3	%			378				399				(5.3	)%
Transportation and Other			15,238				15,157				0.5	%			3.3	%			19				16				18.8	%
Total Gas			50,533				48,714				3.7	%			1.1	%			397				415				(4.3	)%
Total Electric and Gas Revenues																		$	1,996			$	2,724				(26.7	)%
Purchased Power																		$	820			$	1,059				(22.6	)%
Fuel																			222				255				(12.9	)%
Total Purchased Power and Fuel																		$	1,042			$	1,314				(20.7	)%
														% Change
Heating and Cooling Degree-Days		2011				2010				Normal				From 2010				From Normal
Heating Degree-Days			2,837				2,710				2,968				4.7	%			(4.4	)%
Cooling Degree-Days			494				586				332				(15.7	%)			48.8	%
Number of Electric Customers		2011				2010				Number of Gas Customers												2011				2010
Residential			1,412,692				1,406,014				Residential												449,066				446,236
Small Commercial & Industrial			156,686				156,423				Commercial &     Industrial												40,956				40,944
Large Commercial & Industrial			3,127				3,093				Total Retail												490,022				487,180
Public Authorities & Electric Railroads			1,091				1,081				Transportation												864				805
Total			1,573,596				1,566,611				Total												490,886				487,985

 

(a)

Reflects delivery volumes and revenues from customers purchasing electricity directly from PECO and customers electing to receive electric generation service from a competitive electric generation supplier as all customers are assessed delivery charges. For customers purchasing electricity from PECO, revenue also reflects the cost of energy and transmission.

(b)	Other revenue includes transmission revenue from PJM, wholesale revenue and other wholesale energy sales.

(c)

Reflects delivery volumes and revenues from customers purchasing natural gas directly from PECO and customers purchasing natural gas directly from a competitive natural gas supplier as all customers are assessed delivery charges. The cost of natural gas is charged to customers purchasing natural gas from PECO.

 

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