8-K

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, DC 20549

FORM 8-K

CURRENT REPORT

Pursuant to Section 13 or 15(d) of the

Securities Exchange Act of 1934

July 27, 2011

Date of Report (Date of earliest event reported)

Commission File Number	Exact Name of Registrant as Specified in Its Charter; State of Incorporation; Address of Principal Executive Offices; and Telephone Number	IRS Employer Identification Number
1-16169	EXELON CORPORATION (a Pennsylvania corporation) 10 South Dearborn Street P.O. Box 805379 Chicago, Illinois 60680-5379 (312) 394-7398	23-2990190
333-85496	EXELON GENERATION COMPANY, LLC (a Pennsylvania limited liability company) 300 Exelon Way Kennett Square, Pennsylvania 19348-2473 (610) 765-5959	23-3064219
1-1839	COMMONWEALTH EDISON COMPANY (an Illinois corporation) 440 South LaSalle Street Chicago, Illinois 60605-1028 (312) 394-4321	36-0938600
000-16844	PECO ENERGY COMPANY (a Pennsylvania corporation) P.O. Box 8699 2301 Market Street Philadelphia, Pennsylvania 19101-8699 (215) 841-4000	23-0970240

Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligation of the registrant under any of the following provisions:

¨ Written communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425)

¨ Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12)

¨ Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b))

¨ Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c))

Section 2 – Financial Information

Item 2.02. Results of Operations and Financial Condition.

Section 7 – Regulation FD

Item 7.01. Regulation FD Disclosure.

On July 27, 2011, Exelon Corporation (Exelon) announced via press release its results for the second quarter ended June 30, 2011. A copy of the press release and related attachments is attached hereto as Exhibit 99.1. Also attached as Exhibit 99.2 to this Current Report on Form 8-K are the presentation slides to be used at the second quarter 2011 earnings conference call. This Form 8-K and the attached exhibits are provided under Items 2.02, 7.01 and 9.01 of Form 8-K and are furnished to, but not filed with, the Securities and Exchange Commission.

Exelon has scheduled the conference call for 11:00 AM ET (10:00 AM CT) on 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.

Section 9 – Financial Statements and Exhibits

Item 9.01. Financial Statements and Exhibits.

(d) Exhibits.

Exhibit No.	Description
99.1	Press release and earnings release attachments
99.2	Earnings conference call presentation slides

* * * * *

This combined Form 8-K is being furnished separately by Exelon, Exelon Generation Company, LLC, Commonwealth Edison Company and PECO Energy Company (Registrants). Information contained herein relating to any individual Registrant has been furnished by such Registrant on its own behalf. No Registrant makes any representation as to information relating to any other Registrant.

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), 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.

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.

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, each Registrant has duly caused this report to be signed on its behalf by the undersigned hereunto duly authorized.

EXELON CORPORATION

EXELON GENERATION COMPANY, LLC

/s/ Matthew F. Hilzinger

Matthew F. Hilzinger

Senior Vice President, Chief Financial Officer and Treasurer

Exelon Corporation

COMMONWEALTH EDISON COMPANY

/s/ Joseph R. Trpik, Jr.

Joseph R. Trpik, Jr.

Senior Vice President, Chief Financial Officer and Treasurer

Commonwealth Edison Company

PECO ENERGY COMPANY

/s/ Phillip S. Barnett

Phillip S. Barnett

Senior Vice President and Chief Financial Officer

PECO Energy Company

July 27, 2011

EXHIBIT INDEX

Exhibit No.	Description
99.1	Press release and earnings release attachments
99.2	Earnings conference call presentation slides

EX-99.1

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;

• 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:

• 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

• 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.

• 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.

• 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.

• 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.

• 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.

• 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.

• 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.

• 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.

• 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:

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

• Higher operating and maintenance expenses; and

• Increased depreciation and interest expenses.

The decrease in net income was partially offset by:

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

• 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:

• 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:

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

• Decreased storm costs; and

• 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),

8

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.

9

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.

###

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.

10

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

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

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

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.

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.

4

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

5

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

6

EXELON CORPORATION

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

(unaudited)

(in millions, except per share data)

	Three Months Ended 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.

7

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

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.

(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

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

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

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.

12

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.

13

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.

14

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.

15

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.

16

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.

17

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.

18

EX-99.2

Earnings Conference Call

2

nd

Quarter 2011

July 27, 2011

EXHIBIT 99.2

Cautionary Statements Regarding

Forward-Looking Information

2

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), 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

Quarterly

Report

on

Form

10-Q

for

the

quarterly

period

ended

June

30,

2011

(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.

Cautionary Statements Regarding

Forward-Looking Information (Continued)

3

Additional Information and Where to Find It

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.

Participants in the Merger Solicitation

Use of Non-GAAP Financial Measures

This presentation includes references to adjusted (non-GAAP) operating earnings and non-GAAP cash flows that exclude

the impact of certain factors. We believe that these adjusted operating earnings and cash flows are representative of the

underlying

operational

results

of

the

Companies.

Please

refer

to

the

appendix

to

this

presentation

for

a

reconciliation of

adjusted (non-GAAP) operating earnings to GAAP earnings.  Please refer to the footnotes of the following slides for a

reconciliation of non-GAAP cash flows to GAAP cash flows.

4

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.

5

2011 Operating Earnings Guidance

2011 Prior

Guidance

(2)

ComEd

PECO

Exelon

Generation

Holdco

Exelon

$3.90 -

$4.20

(1)

$0.55 -

$0.65

$0.50 -

$0.60

$2.85 -

$3.05

2Q 2011 operating earnings of

$1.05/share

Strong operating results in second

quarter

•

Nuclear capacity factor of 89.6% largely

due to a higher number of nuclear

refueling outages

•

Strong operating results at utilities

despite severe storms in ComEd

service territory

2011 Revised

Guidance

(2)

$4.05 -

$4.25

(1)

$0.55 -

$0.65

$0.50 -

$0.60

$2.95 -

$3.10

Updating

2011

operating

earnings

guidance

to

$4.05

-

$4.25/share

from

$3.90 -

$4.20/share

(1)

(1)

Refer to Earnings Release Attachments for additional details and to the Appendix for a reconciliation of adjusted (non-GAAP) operating EPS to GAAP EPS.

(2)

Earnings guidance for OpCos may not add up to consolidated EPS guidance.

Status of Merger Approvals (as of 7/26/11)

Stakeholder

Status of Key Milestones

Filed

Approved

Securities

and

Exchange 

Commission

(SEC)

(File

No.

333-175162) 

•

Filed S-4 Registration Statement June 27, 2011

•

Shareholder approval anticipated in Q3 2011

Department

of

Justice

(DOJ)

•

Submitted Hart-Scott-Rodino filing on May 31, 2011

for review under U.S. antitrust laws

•

Approval expected by January 2012

Federal

Energy

Regulatory

Commission

(FERC) 

(Docket

No.

EC

11-83)

•

Filed merger approval application and related filings

on May 20, 2011, which assesses market power-

related issues

•

Approval expected in Q4 2011

Nuclear

Regulatory

Commission

(Docket

Nos.

50-317,

50-318,

50-

220,

50-410,

50-244,

72-8,

72-67)

•

Filed for indirect transfer of Constellation Energy

licenses on May 12, 2011

•

Approval expected by January 2012

Maryland

PSC

(Case

No.

9271)

•

Commission on May 25, 2011

•

Approval expected by January 2012

New

York

PSC

(Case

No.

11-E-0245)

•

Filed for approval with the New York State Public

Service Commission on May 17, 2011

•

Approval expected in Q4 2011

Texas

PUC

(Case

No.

39413)

•

Filed for approval with the Public Utility Commission

of Texas on May 17, 2011

•

Approval expected in Q3 2011

6

Filed for approval with the Maryland Public Service

Significant Events

Date of Event

Filing of Application

May 25, 2011

Intervention Deadline

June 24, 2011

Prehearing Conference

June 28, 2011

Filing of Staff, Office of People Counsel and Intervenor Testimony

September 16, 2011

Filing of Rebuttal Testimony

October 12, 2011

Filing of Surrebuttal Testimony

October 26, 2011

Status Conference

October 28, 2011

Evidentiary Hearings

October 31, 2011 -

November 10, 2011

Public Comment Hearings

November 29, December 1 &

December 5, 2011

Filing of Initial Briefs

December 1, 2011

Filing of Reply Briefs

December 15, 2011

Decision Deadline

January 5, 2012

7

Maryland PSC Review Schedule

8

Factors Influencing RPM

Auction (PY 14/15 vs. PY

13/14)

Expected

Exelon

Price

Impact

Actual

Price

Impact

Actual Auction Results and Supplier

Bidding Behavior

Cost of Environmental

Upgrades and Higher Net

ACRs for Coal Units

3,237 MW reduction in offered capacity

(coal/oil/gas)

7,746 MW reduction in cleared capacity

(coal/oil/gas)

Import Transmission Limits

and Objectives 

(muted impact on portfolio

revenues due to regional

diversification)

Total revenue from PY 14/15 capacity

auction close to PY 13/14 revenues for

Exelon fleet

Balanced portfolio, split evenly between east

and west, reduces volatility in revenues due  

to transmission or demand changes.

Demand Response Growth

Increase in cleared DR (~4,836 MW) was

close to internal estimates. 

Limited DR was capped, causing price

separation for premium products

RPM Results: Favorable and As Expected

Auction results were in line with Exelon’s expectations with EPA

regulations being one of the primary drivers of bidding behavior

9

NRC Near-Term Task Force Recommendations

Key Findings :

U.S nuclear plants are safe

No major changes to spent nuclear fuel

storage and licensing

Key Recommendations:

Clarifying regulatory framework

Ensuring protection and enhancing mitigation

Strengthening emergency preparedness

Improving efficiency of NRC programs

Report

is

first

step

in

systematic

review

that

NRC

will

conduct;

stakeholder

input

will

be

sought

10

Key Financial Messages

Higher than expected 2Q 2011 operating earnings of

$1.05/share

(1)

•

NDT funds special transfer tax deduction benefit of $0.07 per share in 2Q;

additional benefit of $0.01 per share expected in second half of

2011

ICC approved revenue increase of $143 million in ComEd’s

2010 distribution rate case

Expect to generate $4.3 billion cash from operations in 2011

Expect

3Q

2011

operating

earnings

of

$1.00

-

$1.10/share

(1)

(1)    Refer to Earnings Release Attachments for additional details and to the Appendix for a reconciliation of adjusted (non-GAAP) operating EPS to GAAP EPS.

Note: NDT = Nuclear Decommissioning Trust

11

Exelon Generation

Operating EPS Contribution

2010

2011

Outage Days

(3)

2Q10

2Q11

Refueling

44

103

Non-refueling

15

24

2Q

YTD

$0.69

$1.35

Note: PPA = Power Purchase Agreement

Key Drivers –

2Q11 vs. 2Q10

(1)

Higher margins due to expiration of the

PECO PPA: $0.15

Favorable market/portfolio conditions: 

$0.07

(2)

NDT funds special transfer tax deduction:

$0.07

Higher O&M costs, including planned

nuclear refueling outages: $(0.07)

Nuclear volume: $(0.05)

Higher nuclear fuel costs: $(0.02)

Higher depreciation and interest expense:

$(0.03)

$0.79

$1.69

(1)

Refer to the Earnings Release Attachments for additional details and to the Appendix for a reconciliation of adjusted (non-GAAP) operating EPS to GAAP EPS.

(2)

Favorable market/portfolio conditions include: $0.02 Wind, $0.02 Hydro volume and $0.03 higher realized prices in Mid-Atlantic

(3)    Outage days exclude Salem.  

12

Key Drivers –

2Q11 vs. 2Q10

(1)

IL distribution tax refund recorded in

2010: $(0.02)

Higher O&M costs: $(0.02)

Higher depreciation and interest

expense: $(0.02)

One-time impacts of distribution rate

case order:  $0.03

Electric distribution rates: $0.01

ComEd Operating EPS Contribution

(1) Refer to the Earnings Release Attachments for additional details and to the Appendix for a reconciliation of adjusted (non-GAAP) operating EPS to GAAP EPS.

2010

2011

2Q

YTD

$0.18

2Q11

Actual

Actual

Normal

Heating Degree-Days        519           823           766

Cooling Degree-Days        312 

237          224         

$0.37

$0.15

$0.26

2Q10

13

PECO Operating EPS Contribution

Key Drivers –

2Q11 vs. 2Q10

(1)

2010 CTC collections, net of

amortization expense: $(0.06)

Electric and gas distribution rates: $0.02

Decreased storm costs: $0.01

Lower interest expense: $0.01

2010

2011

(1) Refer to the Earnings Release Attachments for additional details and to the Appendix for a reconciliation of adjusted (non-GAAP) operating EPS to GAAP EPS.

2Q

YTD

$0.15

2Q11

$0.31

Note: CTC = Competitive Transition Charge

$0.32

$0.13

Actual

Actual

Normal

Heating Degree-Days        299         331          458

Cooling Degree-Days        586

494          332       

2Q10

14

Exelon Generation Hedging Program

Q2 provided favorable 2013 sales

opportunities

•

Reflects successful participation in Illinois IPA

procurements in the first half of May

Price movements

•

Recovery in heat rates, especially at NI Hub

•

Upward move in NI Hub wrap

2013 Hedge % and Value Above Ratable

2013 PJM West Hub & NI Hub ATC Prices

PJM NI Hub ATC Heat Rates

15

Diverse Generation and Sales Mix

Exelon’s diverse portfolio is well positioned to serve a variety of products

2011-2013 Sales as a Percentage

of Expected Generation

Current Owned & Contracted

Generation

Capacity

by

Fuel

Type

(1)

Matching Exelon’s favorable asset position with a diverse set of products is an important aspect of the

hedging program

•

Reduces and diversifies our collateral exposure 

•

Enables sales to be made closer to assets

•

Increases opportunities for margin via retail, utility solicitations and mid-marketing channels

•

Use of alternate channels and locations help minimize liquidity and congestion risks

Data as of 6/30/2011

(1) Reflects owned and contracted generation as of 6/30/2011. Excludes Cromby Station 1 & 2, Eddystone 1&2 and PPA with Tenaska Georgia Partners.  Includes Wolf Hollow PPA 

volume only (350 MW).

RITE Line Project Update

Project Background

420 miles of 765kV transmission

stretches from Northern Illinois to

Ohio.  The RITE Line will be built

from the existing 765kV system in

Ohio in the East to the West

Estimated construction to begin

2015 pending regulatory approvals

and siting

Strategic and Financial Objectives

Ensures reliability, enables states to

meet RPS standards, and supports

the integration of more renewables

ComEd/Exelon investment ~ $1.1

billion

Requested ROE 12.70%

Latest Developments

Signed partnership agreement with

ETA on July 13

Completed FERC incentive rate

filing on July 18. Expect FERC ruling

by October 2011.

16

Note: ETA = Electric Transmission America

RPS = Renewable Portfolio Standards

RTEP = Regional Transmission Expansion Planning

17

($ millions)

Exelon

(8)

Beginning Cash Balance

(1)

$800

Cash Flow from Operations

(2)

375

875

3,175

4,350

CapEx (excluding Nuclear Fuel, Nuclear

Uprates, Exelon Wind, Utility Growth CapEx

and Wolf Hollow)

(725)

(325)

(850)

(1,950)

Nuclear Fuel

n/a

n/a

(1,050)

(1,050)

Dividend

(3)

(1,400)

Nuclear Uprates

and Exelon Wind

(4)

n/a

n/a

(625)

(625)

Wolf Hollow Acquisition

n/a

n/a

(300)

(300)

Utility Growth CapEx

(5)

(300)

(125)

n/a

(425)

Net Financing (excluding Dividend):

Planned Debt Issuances

(6)

1,000

--

--

1,000

Planned Debt Retirements

(350)

(250)

--

(600)

Other

(7)

300

(125)

200

550

Ending Cash Balance

(1)

$350

2011 Projected Sources and Uses of Cash

(1)

Excludes counterparty collateral activity. 

(2)

Cash Flow from Operations primarily includes net cash flows provided by operating activities and net cash flows used in investing activities other than capital expenditures.  

(3)

Assumes 2011 dividend of $2.10/share.  Dividends are subject to declaration by the Board of Directors.

(4)

Includes $400 million in Nuclear Uprates and $225 million for Exelon Wind spend. 

(5)

Represents new business, smart grid/smart meter investment and transmission growth projects.

(6)

Excludes ComEd’s $191 million of tax-exempt bonds that are backed by letters of credit (LOCs).  Excludes PECO’s $225 million Accounts Receivable (A/R) Agreement with

Bank of Tokyo. PECO’s A/R Agreement was extended in accordance with its terms through September 6, 2011. 

(7)

“Other” includes proceeds from options and expected changes in short-term debt.

(8)

Includes cash flow activity from Holding Company, eliminations, and other corporate entities. 

18

Exelon Generation Hedging Disclosures

(as of June 30, 2011)

19

Important Information

The following slides are intended to provide additional information regarding the hedging

program at Exelon Generation and to serve as an aid for the purposes of modeling Exelon

Generation’s gross margin (operating revenues less purchased power and fuel expense). The

information on the following slides is not intended to represent earnings guidance or a

forecast of future events.  In fact, many of the factors that ultimately will determine Exelon

Generation’s actual gross margin are based upon highly variable market factors outside of

our control.  The information on the following slides is as of June 30, 2011.  We update this

information on a quarterly basis.

Certain information on the following slides is based upon an internal simulation model that

incorporates assumptions regarding future market conditions, including power and

commodity prices, heat rates, and demand conditions, in addition to operating performance

and dispatch characteristics of our generating fleet.  Our simulation model and the

assumptions therein are subject to change.  For example, actual market conditions and the

dispatch profile of our generation fleet in future periods will likely differ – and may differ

significantly – from the assumptions underlying the simulation results included in the slides.

In addition, the forward-looking information included in the following slides will likely change

over time due to continued refinement of our simulation model and changes in our views on

future market conditions.

20

Portfolio Management Objective

Align Hedging Activities with Financial Commitments

Power Team utilizes several product types

and channels to market

•

Wholesale and retail sales

•

Block products

•

Load-following products

and load auctions

•

Put/call options

Exelon’s hedging program is designed to

protect the long-term value of our

generating fleet and maintain an

investment-grade balance sheet

•

Hedge enough commodity risk to meet future cash

requirements if prices drop

•

Consider:  financing policy (credit rating objectives,

capital structure, liquidity); spending (capital and

O&M); shareholder value return policy

Consider market, credit, operational risk

Approach to managing volatility

•

Increase hedging as delivery approaches

•

Have enough supply to meet peak load

•

Purchase fossil fuels as power is sold

•

Choose hedging products based on generation

portfolio –

sell what we own

•

Heat rate options

•

Fuel products

•

Capacity

•

Renewable credits

% Hedged

High End of Profit

Low End of Profit

Open Generation

with LT Contracts

Portfolio

Optimization

Portfolio

Management

Portfolio Management Over Time

21

Percentage of Expected

Generation Hedged

•

How many equivalent MW have been

hedged at forward market prices;  all hedge

products used are converted to an

equivalent average MW volume

•

Takes ALL

hedges into account whether

they are power sales or financial products

Equivalent MWs Sold

Expected Generation

=

Our normal practice is to hedge commodity risk on a ratable basis

over the three years leading to the spot market

•

Carry operational length into spot market to manage forced outage and load-following

risks

•

By

using

the

appropriate

product

mix,

expected

generation

hedged

approaches the

mid-90s percentile as the delivery period approaches

•

Participation in larger procurement events, such as utility auctions, and some flexibility

in the timing of hedging may mean the hedge program is not strictly ratable from

quarter to quarter

Exelon Generation Hedging Program

22

2011

2012

2013

Estimated Open Gross Margin ($ millions)

(1)(2)

$5,450

$5,000

$5,600

Open gross margin assumes all expected generation is sold

at the Reference Prices listed below

Reference Prices

(1)

Henry Hub Natural Gas ($/MMBtu)

NI-Hub ATC Energy Price ($/MWh)

PJM-W ATC Energy Price ($/MWh)    

ERCOT

North

ATC

Spark

Spread

($/MWh)

(3)

$4.37

$33.18

$46.07

$3.77

$4.84

$33.10

$46.02

$1.40

$5.16

$34.45

$47.45

$2.27

Exelon Generation Open Gross Margin and

Reference Prices

(1)

Based on June 30, 2011 market conditions. 

(2)

(3)

ERCOT North ATC spark spread using Houston Ship Channel Gas, 7,200 heat rate, $2.50 variable O&M.

Gross margin is defined as operating revenues less fuel expense and purchased power expense, excluding the impact of decommissioning and other incidental revenues.

Open gross margin is estimated based upon an internal model that is developed by dispatching our expected generation to current market power and fossil fuel prices.  Open

gross margin assumes there is no hedging in place other than fixed assumptions for capacity cleared in the RPM auctions and uranium costs for nuclear power plants.  Open

gross margin contains assumptions for other gross margin line items such as various ISO bill and ancillary revenues and costs and PPA capacity revenues and payments.  The

estimation of open gross margin incorporates management discretion and modeling assumptions that are subject to change.

23

2011

2012

2013

Expected Generation

(GWh)

(1)

166,100

165,600

163,000

Midwest

99,000

97,900

95,800

Mid-Atlantic

56,300

57,100

56,500

South & West

10,800

10,600

10,700

Percentage of Expected Generation Hedged

(2)

95-98%

82-85%

49-52%

Midwest

95-98

81-84

48-51

Mid-Atlantic

96-99

85-88

50-53

South & West

86-89

63-66

45-48

Effective Realized Energy Price

($/MWh)

(3)

Midwest

$43.00

$41.00

$40.00

Mid-Atlantic

$57.00

$50.00

$50.50

South & West

$4.50

$0.00

($2.00)

Generation Profile

(1)

Expected generation represents the amount of energy estimated to be generated or purchased through owned or contracted for capacity.  Expected generation is based

upon a simulated dispatch model that makes assumptions regarding future market conditions, which are calibrated to market quotes for power, fuel, load following products,

and options. Expected generation assumes 12 refueling outages in 2011 and 10 refueling outages in 2012 and 2013 at Exelon-operated nuclear plants and Salem.  Expected

generation assumes capacity factors of 93.0%, 93.4% and 93.2% in 2011, 2012 and 2013 at Exelon-operated nuclear plants. These estimates of expected generation in

2012 and 2013 do not represent guidance or a forecast of future results as Exelon has not completed its planning or optimization processes for those years.

(2)

Percent of expected generation hedged is the amount of equivalent sales divided by the expected generation.  Includes all hedging products, such as wholesale and retail

sales of power, options, and swaps.  Uses expected value on options. Reflects decision to permanently retire Cromby Station and Eddystone Units 1&2 as of May 31, 2011.

(3)

Effective realized energy price is representative of an all-in hedged price, on a per MWh basis, at which expected generation has been hedged.  It is developed by

considering the energy revenues and costs associated with our hedges and by considering the fossil fuel that has been purchased to lock in margin. It excludes uranium

costs and RPM capacity revenue, but includes the mark-to-market value of capacity contracted at prices other than RPM clearing prices including our load obligations.  It can

be compared with the reference prices used to calculate open gross margin in order to determine the mark-to-market value of Exelon Generation's energy hedges.

24

Gross Margin Sensitivities with Existing Hedges ($ millions)

(1)

Henry Hub Natural Gas

+ $1/MMBtu

-

$1/MMBtu

NI-Hub ATC Energy Price

+$5/MWH

-$5/MWH

PJM-W ATC Energy Price

+$5/MWH

-$5/MWH

Nuclear Capacity Factor

+1% / -1%

2011

$5

$(5)

$5

$(5)

$5

$(5)

+/-

$25

2012

$85

$(35)

$95

$(75)

$55

$(55)

+/-

$45

2013

$340

$(290)

$250

$(245)

$155

$(150)

+/-

$50

Exelon Generation Gross Margin Sensitivities

(with Existing Hedges)

(1)

Based on June 30, 2011 market conditions and hedged position. Gas price sensitivities are based on an assumed gas-power relationship derived from an internal

model that is updated periodically.

Power prices sensitivities are derived by adjusting the power price assumption while keeping all other prices inputs constant. Due

to

correlation

of

the

various

assumptions,

the

hedged

gross

margin

impact

calculated

by

aggregating

individual

sensitivities

may

not

be

equal

to

the

hedged

gross

margin impact calculated when correlations between the various assumptions are also considered.

25

95% case

5% case

$5,500

$7,100

$6,900

$6,000

Exelon Generation Gross Margin Upside / Risk

(with Existing Hedges)

$3,000

$4,000

$5,000

$6,000

$7,000

$8,000

$9,000

2011

2012

2013

$6,800

$5,200

(1)

Represents an approximate range of expected gross margin, taking into account hedges in place, between the 5th and 95th percent confidence levels assuming all

unhedged supply is sold into the spot market.  Approximate gross margin ranges are based upon an internal simulation model and are subject to change based upon market

inputs, future transactions and potential modeling changes. These ranges of approximate gross margin in 2012 and 2013 do not represent earnings guidance or a forecast of

future results as Exelon has not completed its planning or optimization processes for those years. The price distributions that generate this range are calibrated to market

quotes for power, fuel, load following products, and options as of June 30, 2011.

26

Midwest

Mid-Atlantic

South & West

Step 1

Start

with

fleetwide

open

gross

margin

$5.45 billion

Step 2

Determine

the

mark-to-market

value

of 

energy hedges

99,000GWh * 96% *

($43.00/MWh-$33.18MWh)

= $0.93 billion

56,300GWh * 97% *

($57.00/MWh-$46.07MWh)

= $0.60 billion

10,800GWh * 87% *

($4.50/MWh-$3.77MWh)

= $0.00 billion

Step 3

Estimate

hedged

gross

margin

by

adding open gross margin to mark-to-

market value of energy hedges

Open gross margin:

MTM value of energy hedges:             

Estimated hedged gross margin:

Illustrative Example

of Modeling Exelon Generation 2011 Gross Margin

(with Existing Hedges)

$0.93 billion + $0.60 billion + $0.00 billion

$5.45 billion

$6.98 billion

Market Price Snapshot

20

25

30

35

40

45

7/10

8/10

9/10

10/10

11/10

12/10

1/11

2/11

3/11

4/11

5/11

6/11

7/11

35

40

45

50

55

60

65

70

75

7/10

8/10

9/10

10/10

11/10

12/10

1/11

2/11

3/11

4/11

5/11

6/11

7/11

4.0

4.5

5.0

5.5

6.0

6.5

7.0

7/10

8/10

9/10

10/10

11/10

12/10

1/11

2/11

3/11

4/11

5/11

6/11

7/11

50

55

60

65

70

75

80

85

90

95

7/10

8/10

9/10

10/10

11/10

12/10

1/11

2/11

3/11

4/11

5/11

6/11

7/11

Forward NYMEX Natural Gas

PJM-West and Ni-Hub On-Peak Forward Prices

PJM-West and Ni-Hub Wrap Forward Prices

2012

$4.79

2013  $5.16

Forward NYMEX Coal

2012

$81.91

2013

$86.11

2012 Ni-Hub  $42.20

2013 Ni-Hub

$44.54

2013 PJM-West  $56.95

2012 PJM-West

$54.64

2012 Ni-Hub

$27.02

2013 Ni-Hub

$28.96

2013 PJM-West

$42.06

2012 PJM-West

$39.97

27

Rolling

12

months,

as

of

July

21    2011.

Source:

OTC

quotes

and

electronic

trading

system.

Quotes

are

daily.

st

4.5

5.5

6.5

7.5

8.5

9.5

10.5

11.5

12.5

13.5

7/10

8/10

9/10

10/10

11/10

12/10

1/11

2/11

3/11

4/11

5/11

6/11

7/11

8.2

8.4

8.6

8.8

9.0

9.2

9.4

9.6

9.8

10.0

10.2

10.4

7/10

8/10

9/10

10/10

11/10

12/10

1/11

2/11

3/11

4/11

5/11

6/11

7/11

35

40

45

50

55

60

65

7/10

8/10

9/10

10/10

11/10

12/10

1/11

2/11

3/11

4/11

5/11

6/11

7/11

3.5

4.0

4.5

5.0

5.5

6.0

6.5

7.0

7/10

8/10

9/10

10/10

11/10

12/10

1/11

2/11

3/11

4/11

5/11

6/11

7/11

Market Price Snapshot

2013

10.13

2012

9.91

2012

$46.86

2013

$51.26

2012

$4.73

2013

$5.06

Houston Ship Channel Natural Gas

Forward Prices

ERCOT North On-Peak Forward Prices

ERCOT North On-Peak v. Houston Ship Channel

Implied Heat Rate

2012

$10.24

2013

$12.25

ERCOT North On Peak Spark Spread

Assumes a 7.2 Heat Rate, $1.50 O&M, and $.15 adder

28

Rolling

12

months,

as

of

July

21    2011.

Source:

OTC

quotes

and

electronic

trading

system.

Quotes

are

daily.

st

29

Appendix

30

EPA Regulations are Moving Forward

2010

2011

2012

2013

2014

2015

2016

2017

2018

PJM RPM Auction

14/15

15/16

16/17

17/18

Hazardous Air

Pollutants

Criteria

Pollutants

Greenhouse

Gases

Coal

Combustion

By-Products

Cooling Water

Effluents

Develop Toxics Rule

Pre Compliance Period

Compliance With Toxics Rule

Compliance With Cross-State Air Pollution Rule (CSAPR)

Interim CAIR

Develop CSAPR (2)

Estimated Compliance

Develop Criteria

NSPS revision

Compliance with Revised Criteria NSPS

Develop Revised

NAAQS

SIP provisions developed in response to revised NAAQS

(e.g., Ozone, PM2.5, SO2, NO2, NOx/SOx, CO)

Compliance with Federal GHG Reporting Rule

PSD/BACT and Title V Apply to GHG Emissions (PSD only for new and modified sources)

Develop GHG NSPS

Pre Compliance Period

Compliance With GHG NSPS

Develop Coal Combustion

By-Products Rule

Pre Compliance Period

Compliance With Federal CCB Regulations

Develop 316(b) Regulations

Pre Compliance Period

Phase In Of Compliance

Develop Effluent Regulations

Pre Compliance Period

Phase In Of

Compliance

Develop Cross-

State Air Pollution

Rule

Notes: RPM auctions take place annually in May.

For definition of the EPA regulations referred to on this slide, please see the EPA’s Terms of Environment (http://www.epa.gov/OCEPAterms/).

Wolf Hollow Acquisition

31

Wolf Hollow Overview

Diversifies generation portfolio

•

Expands geographic and fuel characteristics

of fleet

•

Advances Exelon and Constellation merger

strategy of matching load with generation in

key competitive markets

Creates value for shareholders

•

$305M purchase price compares favorably to

cost of other recent transactions

•

Free cash flow accretive beginning in 2012;

earnings and credit neutral

•

Eliminates current above market purchase

power agreement (PPA) with Wolf Hollow

•

Enhances opportunity to benefit from future

market heat rate expansion in ERCOT

Transaction expected to close in Q3 2011

Location

Granbury, Texas

Commercial Operation Date

August 2003

Nominal Net Operating Capacity

720MW

Equipment Technology

2 Mitsubishi combined-cycle gas

turbines

Primary Fuel

Natural Gas

Secondary Fuel

None

ERCOT = Electric Reliability Council of Texas

32

Exelon Nuclear Fleet Overview -

IL

Plant

Location

Type/

Containment

Water Body

License Extension

Status / License

Expiration

(1)

Ownership

Spent Fuel Storage/

Date to lose full

core discharge

capacity

(2)

Braidwood, IL

(Units 1 and 2)

PWR

Concrete/Steel

Lined

Kankakee

River

Expect to file

application in 2013/

2026, 2027

100%

Dry Cask (Summer

2011)

Byron, IL

(Units 1 and 2)

PWR

Concrete/Steel

Lined

Rock River

Expect to file

application in 2013/

2024, 2026

100%

Dry Cask

Clinton, IL

(Unit 1)

BWR

Concrete/Steel

Lined

Clinton Lake

2026

100%

2018

Dresden, IL

(Units 2 and 3)

BWR

Steel Vessel

Kankakee

River

Renewed / 2029,

2031

100%

Dry cask

LaSalle, IL

(Units 1 and 2)

BWR

Concrete/Steel

Lined

Illinois River

2022, 2023

100%

Dry Cask

Quad Cities, IL

(Units 1 and 2)

BWR

Steel Vessel

Mississippi

River

Renewed / 2032

75% Exelon, 25%

Mid-American

Holdings

Dry cask

(1)

Operating license renewal process takes approximately 4-5 years from commencement until completion of NRC review.

(2)

Exelon pursues license extensions well in advance of expiration to ensure adequate time 

for review by the NRC

The date for loss of full core reserve identifies when the on-site storage pool will no longer have sufficient space to receive a full complement of fuel

from the reactor core. Dry cask storage will be in operation at those sites prior to losing full core discharge capacity in their on-site storage pools.

33

Exelon Nuclear Fleet Overview –

PA and NJ

Plant, Location

Type,

Containment

Water Body

License Extension

Status / License

Expiration

(1)

Ownership

Spent Fuel Storage/

Date to lose full

core discharge

capacity

(2)

Limerick, PA

(Units 1 and 2)

BWR

Concrete/Steel

Lined

Schuylkill

River

Filed application in

June 2011

(decision expected

in 2013)/ 2024,

2029

100%

Dry cask

Oyster Creek, NJ

(Unit 1)

BWR

Steel Vessel

Barnegat Bay

Renewed / 2029

(3)

100%

Dry cask

Peach Bottom, PA

(Units 2 and 3)

BWR

Steel Vessel

Susquehanna

River

Renewed / 2033,

2034

50% Exelon,

50% PSEG

Dry cask

TMI, PA (Unit 1)

PWR

Concrete/Steel

Lined

Susquehanna

River

Renewed / 2034

100%

2023

Salem, NJ (Units 1

and 2)

PWR

Concrete/Steel

Lined

Delaware

River

Renewed / 2036,

2040

42.6% Exelon,

57.4% PSEG

Dry Cask

(1)

Operating license renewal process takes approximately 4-5 years from commencement until completion of NRC review.

(2)

The date for loss of full core reserve identifies when the on-site storage pool will no longer have sufficient space to receive a full complement of fuel from the

reactor

(3)

On December 8, 2010, Exelon announced that Generation will permanently cease generation operations at Oyster Creek by December 31, 2019. The current

NRC license for Oyster Creek expires in 2029.

Exelon pursues license extensions well in advance of expiration to ensure adequate time 

for review by the NRC

core. Dry cask storage will be in operation at those sites prior to losing full core discharge capacity in their on-site storage pools.

ComEd 2010 Rate Case Final Order

(ICC Docket No. 10-0467)

On 5/24/11, the Illinois Commerce Commission (ICC) issued an order in ComEd’s

2010 distribution rate case –

new rates went into effect in June 2011

Rate Case Details

ICC Order

(5/24/11)

ComEd Reply Brief

(2/23/11)

Revenue Requirement Increase

$143M

(1)

$343M

Rate Base

$6,549M

$7,349M

ROE

10.50%

11.30%

(2)

Equity Ratio

47.28%

47.28%

(1)

Reflects ~$(13)M adjustment to ICC Order

(2)

Included 40 bp adder for energy efficiency, not approved by ICC

34

ComEd Load Trends

Chicago

U.S.

Unemployment rate

(1)

9.3%

9.2%

2011 annualized growth in

gross

domestic/metro

product

(2)

2.5%

2.7%

Note: C&I = Commercial & Industrial

Weather-Normalized Load Year-over-Year 

Key Economic Indicators

Weather-Normalized Load

2010 

2Q11      2011E

Average Customer Growth

0.2%  

0.4%    

0.4%

Average Use-Per-Customer

(1.4)%

(2.0)%

0.0%

Total Residential

(1.2)%   

(1.6)%       0.4%

Small C&I

(0.6)%

(0.2)%    

(0.3)%

Large C&I

2.6%  

(0.9)%     

0.0%

All Customer Classes

0.2%   

(0.8)%     

0.0%

(1)

Source:  U.S. Dept. of Labor (June 2011) and Illinois

Department of Security (June 2011)

(2)  Source: Global Insight (May 2011)

35

6.0%

3.0%

0.0%

-3.0%

-6.0%

6.0%

3.0%

0.0%

-3.0%

-6.0%

1Q10

2Q10

3Q10

4Q10

1Q11

2Q11

3Q11

4Q11

All Customer Classes

Residential

Large C&I

Gross Metro Product

Illinois Power Agency (IPA)

RFP Procurement

June 2012

June 2013

June 2014

Financial Swap Agreement with ExGen

(ATC baseload energy –

notional quantity

3,000 MW)

Standard Products and Annual REC Procurement held in

May 2011

–

Effective ATC of $34.77/MWh for 9 winning Standard Product

suppliers for the 2011-12 plan-year

–

2.12 million MWh of renewable resources for the 2011-12 plan-year

from 12 winning suppliers

–

Provisions included:

•

Annual energy procurements over a three-year time frame

•

Target a 35%/35%/30% laddered procurement approach

•

No additional Energy Efficiency, Demand Response purchases

•

No additional long-term contracts for renewables

•

No 10% overprocurement for summer peak energy

June 2015

Delivery

Period

Peak

Off-Peak

June 2011 -

May 2012

5,118

4,001

June 2012 -

May 2013

1,129

358

June 2013 -

May 2014

6,494

6,062

Volume procured in the 2011 IPA

Procurement Event (GWh)

Term

Fixed Price

($/MWh)

1/1/11-12/31/11

$51.26

1/1/12-12/31/12

$52.37

1/13/13-5/31/13

$53.48

36

June 2011

Financial Swap

2010 RFP

2011 RFP

2011 RFP

2011 RFP

2012 RFP

2012 RFP

2012 RFP

2013 RFP

2013 RFP

2014 RFP

Note: Chart is for illustrative purposes only.

REC = Renewable Energy Credit; RFP = request for proposal; ATC = Around the Clock

37

PECO Load Trends

Philadelphia

U.S.

Unemployment rate

(1)

7.9%

9.2%               

2011 annualized growth in

gross domestic/metro product

(2)

2.4%                   2.7%

Note: C&I = Commercial & Industrial

Weather-Normalized Load Year-over-Year 

Key Economic Indicators

Weather-Normalized Load

2010

2Q11     2011E

Average Customer Growth

0.3%  

0.5%    

0.4%

Average Use-Per-Customer

0.3%

2.8%

1.7%

Total Residential

0.5%   

3.2%       2.2%

Small C&I

(1.9)%

1.7%        0.7%

Large C&I

0.8%  

(3.3)%      (2.3)%

All Customer Classes

0.1%   

(0.1)%      (0.0)%

(1)  Source:

U.S

Dept.

of

Labor

data

June

2011

-

US

U.S

Dept.

of

Labor

prelim.

data

February

2011

-

Philadelphia

(2)  Source: Global Insight May 2011

38

PECO Procurement Plan

Customer Class

Products

Residential

75% full requirements

20% block energy

5% energy only spot

Small Commercial

(peak demand <100 kW)

90% full requirements

10% full requirements spot

Medium Commercial

(peak demand >100 kW but

<= 500 kW)

85% full requirements

15% full requirements spot

Large Commercial &

Industrial (peak demand

>500 kW)

Fixed-Priced full

requirements

(2)

Hourly full requirements

PECO

Procurement Plan

(1)

Residential –

weighted average wholesale prices

80 MW of baseload (24x7) block energy product (for Jan-Dec 2012) –

$51.52/MWh

70 MW of Jun-Aug 2011 summer on-peak block energy product –

$67.24/MWh

40 MW of Dec 2011-Feb 2012 winter on-peak block energy product –

$63.05/MWh

Large Commercial and Industrial (Hourly) –

weighted average

wholesale price

36%

of

hourly

full

requirements

product

(for

Jun

2011-May

2012)

(3)

–

$4.97/MWh

(4) 

May 2, 2011

RFP

-

Fifth

in

a

series

of nine

procurements for the PUC-approved

Default Service Plan

Spring

2011

RFP

was

held

on

May

2,

2011,

with

results

announced

on

May

18

th

(1)

See PECO Procurement website (http://www.pecoprocurement.com) for additional details regarding PECO’s procurement plan and RFP results.

(2)

For Large C&I customers who previously opted to participate in the 2011 fixed-priced full requirements product. 

(3)

Large C&I tranches which were not fully subscribed in the fall 2010 procurement.

(4)

The price for the hourly full requirements product includes only ancillary services/Alternative Energy Portfolio Standard (AEPS) and miscellaneous costs.  The price does not

include energy and capacity costs.  Energy costs will be based on the PECO Zone Day-Ahead locational marginal pricing (LMP) price, and capacity will be based on the

PJM RPM price per day. 

39

Sufficient Liquidity

($ millions)

Exelon

(3)

Aggregate Bank Commitments

(1)

$1,000

$600

$5,600

$7,700

Outstanding Facility Draws

--

--

--

--

Outstanding Letters of Credit

(195)

(1)

(121)

(324)

Available Capacity Under Facilities

(2)

805

599

5,479

7,376

Outstanding Commercial Paper

--

--

--

(139)

Available Capacity Less Outstanding

Commercial Paper

$805

$599

$5,479

$7,237

Exelon bank facilities are largely untapped

(1)  Excludes commitments from Exelon’s Community and Minority Bank Credit Facility

(2)  Available Capacity Under Facilities represents the unused bank commitments under the borrower’s credit agreements net of outstanding letters of credit and facility draws.  The

amount of commercial paper outstanding does not reduce the available capacity under the credit agreements.

(3)  Includes Exelon Corporate’s

$500M credit facility, letters of credit and commercial paper outstanding.

Available Capacity Under Bank Facilities as of July 14, 2011

40

Key Credit Metrics

0.0x

2.0x

4.0x

6.0x

8.0x

10.0x

12.0x

2009A

2010A

2011E

ExGen/Corp

ComEd

PECO

Exelon

0%

5%

10%

15%

20%

25%

30%

35%

40%

45%

50%

2009A

2010A

2011E

ExGen/Corp

ComEd

PECO

Exelon

FFO / Debt

(1)

(1)

See slide 41 for reconciliations to GAAP.

(2)

Current senior unsecured ratings for Exelon and Exelon Generation and senior secured ratings for ComEd and PECO as of July 22, 2011.

(3)

FFO/Debt Target Range reflects Generation FFO/Debt in addition to the debt obligations of Exelon Corp.

(4)

Moody’s placed Exelon and Generation under review for a possible downgrade after the proposed merger with Constellation Energy was announced.

Moody’s

Credit

Ratings

(2)

S&P

Credit

Ratings

(2)

Fitch

Credit

Ratings

(2)

FFO / Debt

Target

Range

(2)

Exelon:

Baa1

(4)

BBB-

BBB+

ComEd:

Baa1

A-

BBB+

15-18%

PECO:

A1

A-

A

15-18%

Generation:

A3

(4)

BBB

BBB+

30-35%

(3)

Interest Coverage

(1)

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%

2009A

2010A

2011E

ExGen/Corp

ComEd

PECO

Exelon

Debt / Cap

(1)

41

Exelon Consolidated Metric Calculations and Ratios

(1)

Includes changes in A/R, Inventories, A/P and other accrued expenses, option premiums,

counterparty collateral and income taxes.  Impact to FFO is opposite of impact to cash flow

(2)

Reflects retirement of variable interest entity + change in restricted cash

(3)

Reflects

net

capacity

payment

–

interest

on

PV

of

PPAs

(using

weighted

average

cost

of debt)

(4)

Reflects

employer

contributions

–

(service

costs

+

interest

costs

+

expected

return

on

assets),

net of

taxes at 35%

(5)

Reflects

operating

lease

payments

–

interest

on

PV

of

future

operating

lease

payments

(using

weighted average cost of debt)

(6)

Includes AFUDC / capitalized interest

(7)

Reflects PV of net capacity purchases (using weighted average cost of debt)

$ in millions

(8)

Reflects unfunded status, net of taxes at 35%

(9)

Reflects PV of minimum future operating lease payments (using weighted average cost of debt)

(10)

Nuclear decommissioning trust fund balance > asset retirement obligation.  No debt imputed

(11)

Includes accrued interest less securities qualifying for hybrid treatment (50% debt / 50% equity)

(12)

Reflects interest on PV of minimum future operating lease payments (using weighted average cost

of debt)

(13)

Reflects interest on PV of PPAs

(using weighted average cost of debt)

(14)

Includes

AFUDC

/

capitalized

interest

and

interest

on

securities

qualifying

for

hybrid

treatment

(50% debt / 50% equity)

(15)

Includes interest on securities qualifying for hybrid treatment (50% debt / 50% equity)

FFO / Debt Coverage =

FFO (a)

Adjusted Debt (b)

FFO Interest Coverage =

FFO (a) + Adjusted Interest (c)

Adjusted Interest (c)

Adjusted Capitalization (e) =

Adjusted Debt (b) + Adjusted Equity (d)

=

32,606

Rating Agency Debt Ratio =

Adjusted Debt (b)

Adjusted Capitalization (e)

32%

7.2x

58%

=

=

=

2010A Credit Metrics

Exelon 2010 YE Adjustments

FFO Calculation

2010 YE

Source -

2010 Form 10-K (.pdf

version)

Net Cash Flows provided by Operating Activities

5,244

Pg 159 -

Stmt. of Cash Flows

+/-

Change in Working Capital

644

Pg 159 -

Stmt. of Cash Flows

(1)

-

PECO Transition Bond Principal Paydown

(392)

Pg 174 -

Stmt. of Cash Flows

(2)

+    PPA Depreciation Adjustment

207

Pg 295 -

Commitments and Contingencies

(3)

+/-

Pension/OPEB Contribution Normalization

448

Pg 268-269 -

Post-retirement Benefits

(4)

+    Operating Lease Depreciation Adjustment

35

Pg 299 -

Commitments and Contingencies

(5)

+/-

Decommissioning activity

(143)

Pg 159-

Stmt. of Cash Flows

+/-

Other Minor FFO Adjustments

(6)

(54)

= FFO (a)

5,989

Debt Calculation

Long-term Debt (incl. Current Maturities and A/R agreement)

12,828

Pg 161 -

Balance Sheet

Short-term debt (incl. Notes Payable / Commercial Paper)

-

Pg 161 -

Balance Sheet

-

PECO Transition Bond Principal Paydown

-

N/A -

no debt outstanding at year-end

+    PPA Imputed Debt

1,680

Pg 295 -

Commitments and Contingencies

(7)

+    Pension/OPEB Imputed Debt

3,825

Pg 268 -

Post-retirement benefits

(8)

+    Operating Lease Imputed Debt

428

Pg 299 -

Commitments and Contingencies

(9)

+    Asset Retirement Obligation

-

Pg 261-267 -

Asset Retirement Obligations

(10)

+/-

Other Minor Debt Equivalents

(11)

84

= Adjusted Debt (b)

18,845

Interest Calculation

Net Interest Expense

817

Pg 158 -

Statement of Operations

-

PECO Transition Bond Interest Expense

(22)

Pg 182 -

Significant Accounting Policies

+   Interest  on Present Value (PV) of Operating Leases

29

Pg 299 -

Commitments and Contingencies

(12)

+   Interest  on PV of Purchased Power Agreements (PPAs)

99

Pg 295 -

Commitments and Contingencies

(13)

+/-

Other Minor Interest Adjustments

(14)

37

= Adjusted Interest (c)

960

Equity Calculation

Total Equity

13,563

Pg 161 -

Balance Sheet

+    Preferred Securities of Subsidaries

87

Pg 161 -

Balance Sheet

+/-

Other Minor Equity Equivalents

(15)

111

= Adjusted Equity (d)

13,761

42

2Q GAAP EPS Reconciliation

Three Months Ended June 30, 2011

ExGen

ComEd

PECO

Other

Exelon

2011 Adjusted (non-GAAP) Operating Earnings (Loss) Per Share

$0.79

$0.15

$0.13

$(0.01)

$1.05

Mark-to-market impact of economic hedging activities

(0.12)

-

-

-

(0.12)

Unrealized gains related to nuclear decommissioning trust funds

0.01

-

-

-

0.01

Retirement of fossil generating units

(0.02)

-

-

-

(0.02)

Recovery of costs pursuant to distribution rate case order

-

0.03

-

-

0.03

Constellation merger costs

-

-

-

(0.02)

(0.02)

2Q 2011 GAAP Earnings (Loss) Per Share

$0.67

$0.17

$0.13

$(0.03)

$0.93

NOTE:  All amounts shown are per Exelon share and represent contributions to Exelon's EPS.  Amounts may not add due to rounding.

Three Months Ended June 30, 2010

ExGen

ComEd

PECO

Other

Exelon

2010 Adjusted (non-GAAP) Operating Earnings (Loss) Per Share

$0.69

$0.18

$0.15

$(0.02)

$0.99

2007 Illinois electric rate settlement

(0.01)

-

-

-

(0.01)

Mark-to-market impact of economic hedging activities

(0.11)

-

-

-

(0.11)

Unrealized losses related to nuclear decommissioning trust funds

(0.08)

-

-

-

(0.08)

Retirement of fossil generating units

(0.02)

-

-

-

(0.02)

Non-cash remeasurement of income tax uncertainties

0.10

(0.16)

(0.03)

(0.01)

(0.10)

2Q 2010 GAAP Earnings (Loss) Per Share

$0.57

$0.02

$0.11

$(0.03)

$0.67

43

YTD GAAP EPS Reconciliation

Six Months Ended June 30, 2011

ExGen

ComEd

PECO

Other

Exelon

2011 Adjusted (non-GAAP) Operating Earnings (Loss) Per Share

$1.69

$0.26

$0.32

$(0.04)

$2.22

Mark-to-market impact of economic hedging activities

(0.25)

-

-

-

(0.25)

Unrealized gains related to nuclear decommissioning trust funds

0.04

-

-

-

0.04

Retirement of fossil generating units

(0.04)

-

-

-

(0.04)

Non-cash charge resulting from Illinois tax rate change legislation

(0.03)

(0.01)

-

-

(0.04)

Recovery of costs pursuant to distribution rate case order

-

0.03

-

-

0.03

Constellation merger costs

-

-

-

(0.02)

(0.02)

YTD 2011 GAAP Earnings (Loss) Per Share

$1.41

$0.28

$0.32

$(0.06)

$1.94

NOTE:  All amounts shown are per Exelon share and represent contributions to Exelon's EPS.  Amounts may not add due to rounding.

Six Months Ended June 30, 2010

ExGen

ComEd

PECO

Other

Exelon

2010 Adjusted (non-GAAP) Operating Earnings (Loss) Per Share

$1.35

$0.37

$0.31

$(0.04)

$1.99

2007 Illinois electric rate settlement

(0.01)

-

-

-

(0.01)

Mark-to-market impact of economic hedging activities

0.10

-

-

-

0.10

Unrealized losses related to nuclear decommissioning trust funds

(0.05)

-

-

-

(0.05)

Non-cash charge resulting from health care legislation

(0.04)

(0.02)

(0.02)

(0.02)

(0.10)

Non-cash charge remeasurement of income tax uncertainties

0.10

(0.16)

(0.03)

(0.01)

(0.10)

Retirement of fossil generating units

(0.03)

-

-

-

(0.03)

YTD 2010 GAAP Earnings (Loss) Per Share

$1.42

$0.19

$0.26

$(0.07)

$1.80

44

GAAP to Operating Adjustments

Exelon’s 2011 adjusted (non-GAAP) operating earnings outlook excludes the

earnings effects of the following:

•

Mark-to-market adjustments from economic hedging activities

•

Unrealized gains and losses from nuclear decommissioning trust fund investments to the extent

not offset by contractual accounting as described in the notes to the consolidated financial

statements

•

Significant impairments of assets, including goodwill

•

Changes in decommissioning obligation estimates

•

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

•

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 Exelon’s proposed merger with Constellation

•

Other unusual items

•

Significant changes to GAAP

Operating

earnings

guidance

assumes

normal

weather

for

remainder

of

the

year