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Form 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 24, 2009

Date of Report (Date of earliest event reported)


Commission File Number	Exact Name of Registrant as Specified in Its Charter; State of Incorporation; Address of Principal Executive Offices; and Telephone Number	IRS Employer Identification Number
1-16169	EXELON CORPORATION	23-2990190
	(a Pennsylvania corporation)
	10 South Dearborn Street
	P.O. Box 805379
	Chicago, Illinois 60680-5379
	(312) 394-7398

333-85496	EXELON GENERATION COMPANY, LLC	23-3064219
	(a Pennsylvania limited liability company)
	300 Exelon Way
	Kennett Square, Pennsylvania 19348-2473
	(610) 765-5959

1-1839	COMMONWEALTH EDISON COMPANY	36-0938600
	(an Illinois corporation)
	440 South LaSalle Street
	Chicago, Illinois 60605-1028
	(312) 394-4321

000-16844	PECO ENERGY COMPANY	23-0970240
	(a Pennsylvania corporation)
	P.O. Box 8699
	2301 Market Street
	Philadelphia, Pennsylvania 19101-8699
	(215) 841-4000

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 24, 2009, Exelon Corporation (Exelon) announced via press release Exelon’s results for the second quarter ended June 30, 2009. A copy of the press release and related attachments is attached hereto as Exhibit 99.1. Also attached as Exhibit 99.2 to this Current Report on Form 8-K are the presentation slides to be used at the second quarter 2009 earnings conference call. This Form 8-K and the attached exhibits are provided under Items 2.02, 7.01 and 9.01 of Form 8-K and are furnished to, but not filed with, the Securities and Exchange Commission (SEC).

Section 9 – Financial Statements and Exhibits

Item 9.01.

Financial Statements and Exhibits.

(d)	Exhibits.


Exhibit No.		Description
99.1		Press release and earnings release attachments

99.2		Earnings conference call presentation slides

* * * * *

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

This Current Report includes forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995 that are subject to risks and uncertainties. The factors that could cause actual results to differ materially from these forward-looking statements include those discussed herein as well as those discussed in (1) Exelon’s 2008 Annual Report on Form 10-K in (a) ITEM 1A. Risk Factors, (b) ITEM 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations and (c) ITEM 8. Financial Statements and Supplementary Data: Note 18; (2) Exelon’s Second Quarter 2009 Quarterly Report on Form 10-Q (to be filed on July 24, 2009) in (a) Part II, Other Information, ITEM 1A. Risk Factors and (b) Part I, Financial Information, ITEM 1. Financial Statements: Note 14; and (3) other factors discussed in filings with the SEC by the Registrants. Readers are cautioned not to place undue reliance on these forward-looking statements, which apply only as of the date of this Current Report. None of the Registrants undertakes any obligation to publicly release any revision to its forward-looking statements to reflect events or circumstances after the date of this Current Report.

SIGNATURES

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

EXELON CORPORATION

EXELON GENERATION COMPANY, LLC

/s/ Matthew F. Hilzinger

Matthew F. Hilzinger

Senior Vice President and Chief Financial Officer

Exelon Corporation

COMMONWEALTH EDISON COMPANY

/s/ Joseph R. Trpik, Jr.

Joseph R. Trpik, Jr.

Senior Vice President, Chief Financial Officer and Treasurer

Commonwealth Edison Company

PECO ENERGY COMPANY

/s/ Phillip S. Barnett

Phillip S. Barnett

Senior Vice President and Chief Financial Officer

PECO Energy Company

July 24, 2009

EXHIBIT INDEX


Exhibit No.		Description
99.1		Press release and earnings release attachments

99.2		Earnings conference call presentation slides

Press release and earnings release attachments

EXHIBIT 99.1

LOGO


Contact:	Karie Anderson	FOR IMMEDIATE RELEASE
	Investor Relations
	312-394-4255

	Kathleen Cantillon
	Corporate Communications
	312-394-7417

Exelon Announces Second Quarter Results;

Reaffirms Full Year 2009 Earnings Guidance

CHICAGO (July 24, 2009) – Exelon Corporation (NYSE: EXC) today announced that its second quarter 2009 consolidated earnings prepared in accordance with GAAP were $657 million, or $0.99 per diluted share, compared with earnings of $748 million, or $1.13 per share, in the second quarter of 2008.

Exelon’s adjusted (non-GAAP) operating earnings for the second quarter of 2009 were $683 million, or $1.03 per diluted share, compared with $746 million, or $1.13 per diluted share, for the same period in 2008.

“We delivered very good earnings in the second quarter despite the weak economy and lower demand,” said John W. Rowe, Exelon’s chairman and CEO. “Not only did we continue to operate extremely well, but Exelon again showed its ability to deliver on its commitments by reducing expenses and setting additional cost reduction targets for 2010. Our performance allows me to reaffirm our full year operating earnings guidance range of $4.00 to $4.30 per share.”

The decrease in second quarter 2009 adjusted (non-GAAP) operating earnings to $1.03 per share from $1.13 per share in second quarter 2008 was primarily due to:

•

Lower operating income at Exelon Generation Company, LLC (Generation) largely due to revenue in 2008 from certain long option gains in the proprietary trading portfolio and income recognized in 2008 related to a legal settlement of a uranium supply contract;

•

Lower energy gross margins at Generation largely due to unfavorable portfolio and market conditions and higher nuclear fuel costs;

•

Reduced load at Commonwealth Edison Company (ComEd) and PECO Energy Company (PECO), primarily driven by current economic conditions and the impact of unfavorable weather conditions in the PECO service territory; and

•

Increased depreciation and amortization expense primarily related to the higher scheduled competitive transition charge (CTC) amortization at PECO and increased depreciation across the operating companies due to ongoing capital expenditures.

Lower second quarter 2009 earnings were partially offset by:

•

Increased electric distribution revenue at ComEd resulting from the September 2008 distribution rate case order;

•

Decreased operating and maintenance expense largely due to savings achieved through the ongoing cost management initiative and lower uncollectible accounts expense at PECO, partially offset by increased pension and other postretirement benefits (OPEB) expense; and

•

Increased distribution revenue at PECO, partially reflecting new rates effective January 1, 2009, resulting from the 2008 gas distribution rate case.

Adjusted (non-GAAP) operating earnings for the second quarter of 2009 do not include the following items (after-tax) that were included in reported GAAP earnings:

•

Mark-to-market losses of $106 million, or $0.16 per diluted share, primarily from Generation’s economic hedging activities;

•

Federal and state income tax benefits of $66 million, or $0.10 per diluted share, primarily reflecting the non-cash remeasurement of income tax uncertainties and a reassessment of state deferred income taxes;

•

Unrealized gains of $64 million, or $0.10 per diluted share, related to nuclear decommissioning trust (NDT) fund investments;

•

A charge of $20 million, or $0.03 per diluted share, for the costs associated with the 2007 Illinois electric rate settlement agreement;

•

A charge of $24 million, or $0.04 per diluted share, for severance costs as a result of headcount reductions as part of Exelon’s cost reduction program announced in June 2009; and

•

External costs of $6 million, or $0.01 per diluted share, related to Exelon’s proposed acquisition of NRG Energy, Inc. (NRG).

Adjusted (non-GAAP) operating earnings for the second quarter of 2008 did not include the following items (after-tax) that were included in reported GAAP earnings:

•

Mark-to-market gains of $62 million, or $0.09 per diluted share, primarily from Generation’s economic hedging activities;

•

A charge of $45 million, or $0.07 per diluted share, for the costs associated with the 2007 Illinois electric rate settlement agreement; and

•

Unrealized losses of $15 million, or $0.02 per diluted share, related to NDT fund investments.

2009 Earnings Outlook

Exelon reaffirmed its guidance range for 2009 adjusted (non-GAAP) operating earnings of $4.00 to $4.30 per share. Exelon expects adjusted (non-GAAP) operating earnings for the third quarter of 2009 to be in the range of $0.90 to $1.00 per share. Operating earnings guidance is based on the assumption of normal weather for the remainder of the year.

The outlook for 2009 adjusted (non-GAAP) operating earnings for Exelon and its subsidiaries excludes the following items:

•

Mark-to-market adjustments from economic hedging activities

•

Unrealized gains and losses from NDT fund investments primarily related to the Clinton, Oyster Creek and Three Mile Island nuclear plants (the former AmerGen Energy Company, LLC units)

•

Significant impairments of assets, including goodwill

•

Changes in decommissioning obligation estimates

•

Costs associated with the 2007 Illinois electric rate settlement agreement

•

Costs associated with ComEd’s 2007 settlement with the City of Chicago

•

Costs incurred for employee severance related to the cost reduction program announced in June 2009

•

External costs associated with the proposed acquisition of NRG

•

Non-cash remeasurement of income tax uncertainties and reassessment of state deferred income taxes

•

Other unusual items

•

Significant future changes to GAAP

Second Quarter and Recent Highlights

•

Proposal to Acquire NRG: On July 21, 2009, Exelon announced that it terminated its pending offer to acquire all of the outstanding shares of NRG common stock. Exelon believes it could have been successful in completing the transaction but was unwilling to raise its price to a level that would undermine its own value proposition.

•

First Anniversary of Exelon 2020: Exelon 2020 is the company’s comprehensive strategy announced one year ago to reduce, offset or displace more than 15 million metric tons of greenhouse gas (GHG) emissions per year by 2020 by greening its own operations, helping customers and the communities Exelon serves reduce their GHG emissions, and offering more low-carbon electricity in the marketplace. The 2009 update reports that Exelon so far has reduced more than one-third, or 6 million metric tons, of its GHG emissions.

Exelon has relied on greening its operations to achieve the bulk of its emissions reductions to date. It also has announced plans to offer substantial new low-carbon electricity in the marketplace by raising the output of Exelon nuclear plants and investing in new renewable energy projects. Going forward, the company will increase its investment in customer initiatives to continue progress toward its 2020 goal. ComEd and PECO will spend more than $350 million through 2011 on energy efficiency and demand response programs that will help residential and business customers reduce their energy consumption by more than 1.6 million megawatt-hours (MWhs) and reduce peak load by 226 megawatts (MWs).

•

Nuclear Operations: Generation’s nuclear fleet, including its owned output from the Salem Generating Station operated by PSEG Nuclear LLC, produced 34,995 gigawatt-hours (GWhs) in the second quarter of 2009, compared with 35,069 GWhs in the second quarter of 2008. The Exelon-operated nuclear plants achieved a 93.9 percent capacity factor for the second quarter of 2009 compared with 95.8 percent for the second quarter of 2008. The Exelon-operated nuclear plants completed three scheduled refueling outages in the second quarter of 2009, compared with completing two scheduled refueling outages in the second quarter of 2008. The number of

refueling outage days totaled 57 and 40, respectively, in the second quarter of 2009 and 2008. Also contributing to lower total nuclear output was a higher number of non-refueling outage days at the Exelon-operated plants, which totaled 21 days in the second quarter of 2009, compared to 3 days in the second quarter of 2008.

•

Fossil and Hydro Operations: Generation’s fossil fleet commercial availability was 98.6 percent in the second quarter of 2009, compared with 92.8 percent in the second quarter of 2008, primarily reflecting the impact of recent capital investments and enhanced inspection programs across the fleet. The equivalent availability factor for the hydroelectric facilities was 98.8 percent in the second quarter of 2009, compared with 94.4 percent in the second quarter of 2008, primarily due to an earlier than planned annual inspection at Muddy Run in the first quarter of 2009 and the overhaul of Conowingo Unit 2 in 2008.

•

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, 2009 is 95-98 percent for 2009, 87-90 percent for 2010 and 59-62 percent for 2011. The primary objective of Exelon’s hedging program is to manage market risks and protect the value of its generation and its investment grade balance sheet while preserving its ability to participate in improving long-term market fundamentals.

•

Nuclear Uprate Program: On June 12, 2009, Exelon announced the completion of an approximate 38-MW increase in output at its Quad Cities plant in Illinois and launched a series of planned power uprates across its nuclear fleet that will generate between 1,300 and 1,500 MWs of additional generation capacity within eight years through equipment upgrades and efficiency improvements. Exelon’s uprate projects use proven technologies and are overseen by the Nuclear Regulatory Commission. Uprate projects are already underway at a number of Exelon’s nuclear stations, which are expected to produce nearly a quarter of the new MWs. The remainder of uprate MWs will come from additional projects across Exelon’s nuclear fleet beginning in 2010 and ending in 2017.

•

Cost Reduction Program: On June 18, 2009, Exelon announced a reorganization of its senior executive team and structure to reflect a leaner corporate management model. These and related changes are being driven by economic challenges confronting all parts of Exelon’s business and industry, including the need for continued focus on cost management through enhanced efficiency and productivity. The company announced major spending cuts which will achieve approximately $350 million in operations and maintenance expense savings in 2010. These savings are expected to result in a nearly 3.5 percent reduction in year-over-year operating and maintenance spending, from $4.5 billion in 2009 to $4.35 billion in 2010. The spending cuts include the elimination of approximately 500 positions, mostly in corporate support functions. The company expects over half of the $350 million in cost savings to be sustainable. Exelon incurred a second quarter 2009 after-tax severance charge of approximately $24 million associated with the elimination of the 500 positions.

•

ComEd Energy Procurement: On January 7, 2009, the Illinois Commerce Commission approved the Illinois Power Agency’s plan for procurement of ComEd’s expected energy requirements from June 2009 through May 2010. The procurement plan includes approximately 38 percent of ComEd’s expected energy requirements purchased through the spot market with a significant portion of the purchases hedged by the financial swap contract with Generation and 33 percent being met through existing supplier contracts. The remaining energy requirements were met through the standard products purchased as a result of the 2009 request for proposal (RFP) process completed in May 2009. Approximately 8 percent of ComEd’s energy requirements from June 2010 through May 2011 were also procured through the contracts entered into as a result of the 2009 RFP process.

•

PECO Energy Procurement: On June 2, 2009, the Pennsylvania Public Utility Commission (PAPUC) approved the settlement of PECO’s default service provider program, under which PECO will provide default electric service following the expiration of electric generation rate caps on December 31, 2010.

During 2009 and 2010, PECO will conduct four procurements for the residential class and for full requirements fixed price products and block products for electric generation supply commencing in 2011. During 2009 and 2010, PECO will also conduct three procurements for the small commercial and medium commercial classes for full requirements fixed price products and one procurement for full requirements spot price products. For the large commercial and industrial class, PECO will conduct one procurement for full requirements fixed price products and one procurement for full requirements spot price products.

On June 17, 2009, the PAPUC approved the results of PECO’s first competitive procurement RFP. The June 2009 electric generation procurements were for service to the residential class and included full requirements fixed price contracts for 17-month and 29-month periods beginning January 1, 2011, and block contracts to procure electric generation for the 12-month period beginning January 1, 2011. On July 15, 2009, PECO announced the results of the first competitive procurements, which accounted for approximately 21 percent of the electricity needed for PECO’s residential customers. The purchases resulted in a price of 10.1 cents per kilowatt hour (kWh), indicating a 9 percent energy price increase for an average residential customer beginning in 2011. PECO’s next residential purchase and initial generation supply purchases for the small and medium commercial classes will take place in September 2009.

•

Credit Rating Actions: Following the termination of Exelon’s proposed offer for NRG, the rating agencies took the following actions.

On July 21, 2009, Fitch Ratings, Ltd. removed Exelon Corp. and Generation from Ratings Watch Negative. The ratings for Exelon and Generation were affirmed and each entity was assigned a Stable Ratings Outlook.

On July 22, 2009, Standard & Poor’s Ratings Services (S&P) affirmed its corporate credit rating on Exelon Corp., Generation and PECO of “BBB” and removed their ratings from CreditWatch with negative implications. In addition, S&P raised the corporate credit rating of ComEd to “BBB” from “BBB-”, raised its debt and preferred stock ratings and removed its ratings from CreditWatch with negative implications. An S&P research report cited “improvement in both ComEd’s business risk profile and its financial measures”. The outlook for ratings of all the Exelon entities is stable.

On July 23, 2009, Moody’s Investors Service (Moody’s) confirmed the ratings of Exelon Corp. and Generation and assigned a stable outlook. Moody’s also confirmed the long-term debt rating of PECO but downgraded its short-term rating to “P-2” from “P-1” and changed the outlook on PECO’s long-term debt to negative.

OPERATING COMPANY RESULTS

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

Second quarter 2009 net income was $512 million compared with $653 million in the second quarter of 2008. Second quarter 2009 net income included (all after tax) mark-to-market losses of $106 million from economic hedging activities before the elimination of intercompany transactions, unrealized gains of $64 million related to NDT fund investments, the benefit from a reassessment of state deferred income taxes of $38 million, a charge of $18 million for the costs associated with the 2007 Illinois electric rate settlement and a charge of $9 million for the costs incurred for severance. Second quarter 2008 net income included (all after tax) mark-to-market gains of $47 million from economic hedging activities, a charge of $44 million for the costs associated with the 2007 Illinois electric rate settlement and unrealized losses of $15 million related to NDT fund investments. Excluding the impact of these items, Generation’s net income in the second quarter of 2009 decreased $122 million compared with the same quarter last year primarily due to:

•

Income recognized in the second quarter of 2008 related to certain long option gains in the proprietary trading portfolio and a uranium contract settlement;

•

Lower energy gross margins, largely due to unfavorable portfolio and market conditions and higher nuclear fuel costs; and

•

Higher operating and maintenance expense, primarily reflecting increased pension and OPEB expense.

Generation’s average realized margin on all electric sales, including sales to affiliates and excluding trading activity, was $38.96 per MWh in the second quarter of 2009 compared with $40.53 per MWh in the second quarter of 2008.

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

ComEd recorded net income of $116 million in the second quarter of 2009, compared with net income of $35 million in the second quarter of 2008. Second quarter 2009 net income included (all after tax) the benefit from a non-cash remeasurement of income tax uncertainties of $40 million, a charge of $11 million for the costs incurred for severance, and $2 million for the costs associated with the Illinois electric rate settlement. Second quarter 2008 net income included an after-tax charge of $1 million for the costs associated with the Illinois electric rate settlement. Excluding the impact of these items, ComEd’s net income in the second quarter of 2009 increased $53 million from the same quarter last year primarily due to:

•

Increased distribution revenue due to the September 2008 distribution rate case order; and

•

Lower operating and maintenance expense, which primarily reflected the impact of the cost reduction initiative and decreased storm costs, partially offset by increased pension and OPEB expense.

The increase in net income was partially offset by:

•

Reduced load, primarily driven by current economic conditions.

In the second quarter of 2009, cooling degree-days in the ComEd service territory were down 7.8 percent relative to the same period in 2008, but were 21.0 percent below normal. ComEd’s total retail kilowatt-hour (kWh) deliveries decreased by 4.3 percent quarter over quarter, with declines in deliveries to all major customer classes. In addition, the number of residential customers being served in the ComEd region decreased 0.4 percent from the second quarter of 2008.

Weather-normalized retail kWh deliveries decreased by 4.1 percent from the second quarter of 2008. For ComEd, weather had an unfavorable after-tax impact of $1.2 million on second quarter 2009 earnings relative to 2008 and an unfavorable after-tax impact of $5.2 million relative to normal weather that was incorporated in earnings guidance.

PECO consists of the electricity transmission and distribution operations and the retail natural gas distribution business in southeastern Pennsylvania.

PECO’s net income in the second quarter of 2009 was $71 million, up from $58 million in the second quarter of 2008. Second quarter 2009 net income included (after tax) a charge of $3 million for the costs incurred for severance. Excluding the impact of this item, PECO’s net income in the second quarter of 2009 increased by $16 million compared with the same quarter last year primarily due to:

•

Lower uncollectible accounts expense; and

•

Higher distribution revenue, partially reflecting new rates effective January 1, 2009, resulting from the 2008 gas distribution rate case.

The increase in net income was partially offset by:

•

Reduced load, primarily driven by current economic conditions and the impact of unfavorable weather conditions; and

•

Higher CTC amortization, which was in accordance with PECO’s 1998 restructuring settlement with the PAPUC. As expected, the increase in amortization expense exceeded the increase in CTC revenues.

In the second quarter of 2009, cooling degree-days in the PECO service territory were down 10.4 percent from 2008, but were 6.0 percent above normal. Heating degree-days were up 1.0 percent from 2008 and were 9.6 percent below normal. Total retail kWh deliveries were down 5.5 percent from last year, largely reflecting a decline in deliveries to residential and large commercial and industrial customers, primarily driven by current economic conditions and the impact of unfavorable weather conditions. The number of residential electric customers being served in the PECO region decreased 0.3 percent from the second quarter of 2008.

Weather-normalized retail kWh deliveries decreased by 2.6 percent from the second quarter of 2008, primarily reflecting decreased residential and large commercial and industrial deliveries. For PECO, weather had an unfavorable after-tax impact of $13 million on second quarter 2009 earnings relative to 2008 and an unfavorable after-tax impact of $8 million relative to normal weather that was incorporated in earnings guidance.

Adjusted (non-GAAP) Operating Earnings

Adjusted (non-GAAP) operating earnings, which generally exclude significant one-time charges or credits that are not normally associated with ongoing operations, mark-to-market adjustments from economic hedging activities and unrealized gains and losses from NDT fund investments, are provided as a supplement to results reported in accordance with GAAP. Management uses such adjusted (non-GAAP) operating earnings measures internally to evaluate the company’s performance and manage its operations. Reconciliation of GAAP to adjusted (non-GAAP) operating earnings for historical periods is attached. Additional earnings release attachments, which include the reconciliation on page 7, are posted on Exelon’s Web site: www.exeloncorp.com and have been filed with the Securities and Exchange Commission on Form 8-K on July 24, 2009.

Conference call information: Exelon has scheduled a conference call for 11 AM ET (10 AM CT) on July 24, 2009. The call-in number in the U.S. and Canada is 800-690-3108, and the international call-in number is 973-935-8753. If requested, the conference ID number is 20118989. Media representatives are invited to participate on a listen-only basis. The call will be web-cast and archived on Exelon’s Web site: www.exeloncorp.com. (Please select the Investor Relations page.)

Telephone replays will be available until 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 20118989.

Forward Looking Statements

This press release includes forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995, that are subject to risks and uncertainties. The factors that could cause actual results to differ materially from these forward-looking statements include those discussed herein as well as those discussed in (1) Exelon’s 2008 Annual Report on Form 10-K in (a) ITEM 1A. Risk Factors, (b) ITEM 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations and (c) ITEM 8. Financial Statements and Supplementary Data: Note 18; (2) Exelon’s Second Quarter 2009 Quarterly Report on Form 10-Q (to be filed on July 24, 2009) in (a) Part II, Other Information, ITEM 1A. Risk Factors and (b) Part I, Financial Information, ITEM 1. Financial Statements: Note 14; and (3) other factors discussed in filings with the Securities and Exchange Commission (SEC) by Exelon Corporation, Commonwealth Edison Company, PECO Energy Company and Exelon Generation Company, LLC (Companies). Readers are cautioned not to place undue reliance on these forward-looking statements, which apply only as of the date of this press release. None of the Companies undertakes any obligation to publicly release any revision to its forward-looking statements to reflect events or circumstances after the date of this press release.

###

Exelon Corporation is one of the nation’s largest electric utilities with approximately 5.4 million customers and $19 billion in annual revenues. The company has one of the industry’s largest portfolios of electricity generation capacity, with a nationwide reach and strong positions in the Midwest and Mid-Atlantic. Exelon distributes electricity to approximately 5.4 million customers in Illinois and Pennsylvania and natural gas to approximately 485,000 customers in southeastern Pennsylvania. Exelon is headquartered in Chicago and trades on the NYSE under the ticker EXC.

EXELON CORPORATION

Earnings Release Attachments

Table of Contents


Consolidating Statements of Operations - Three Months Ended June 30, 2009 and 2008		1

Consolidating Statements of Operations - Six Months Ended June 30, 2009 and 2008		2

Business Segment Comparative Statements of Operations - Generation and ComEd - Three and Six Months Ended June 30, 2009 and 2008		3

Business Segment Comparative Statements of Operations - PECO and Other - Three and Six Months Ended June 30, 2009 and 2008		4

Consolidated Balance Sheets - June 30, 2009 and December 31, 2008		5

Consolidated Statements of Cash Flows - Six Months Ended June 30, 2009 and 2008		6

Reconciliation of Adjusted (non-GAAP) Operating Earnings to GAAP Consolidated Statements of Operations - Exelon - Three Months Ended June 30, 2009 and 2008		7

Reconciliation of Adjusted (non-GAAP) Operating Earnings to GAAP Consolidated Statements of Operations - Exelon - Six Months Ended June 30, 2009 and 2008		8

Reconciliation of Adjusted (non-GAAP) Operating Earnings to GAAP Earnings By Business Segment - Three Months Ended June 30, 2009 and 2008		9

Reconciliation of Adjusted (non-GAAP) Operating Earnings to GAAP Earnings By Business Segment - Six Months Ended June 30, 2009 and 2008		10

Reconciliation of Adjusted (non-GAAP) Operating Earnings to GAAP Consolidated Statements of Operations - Generation - Three and Six Months Ended June 30, 2009 and 2008		11

Reconciliation of Adjusted (non-GAAP) Operating Earnings to GAAP Consolidated Statements of Operations - ComEd - Three and Six Months Ended June 30, 2009 and 2008		12

Reconciliation of Adjusted (non-GAAP) Operating Earnings to GAAP Consolidated Statements of Operations - PECO - Three and Six Months Ended June 30, 2009 and 2008		13

Reconciliation of Adjusted (non-GAAP) Operating Earnings to GAAP Consolidated Statements of Operations - Other - Three and Six Months Ended June 30, 2009 and 2008		14

Exelon Generation Statistics - Three Months Ended June 30, 2009, March 31, 2009, December 31, 2008, September 30, 2008 and June 30, 2008		15

Exelon Generation Statistics - Six Months Ended June 30, 2009 and 2008		16

ComEd Statistics - Three and Six Months Ended June 30, 2009 and 2008		17

PECO Statistics - Three and Six Months Ended June 30, 2009 and 2008		18

EXELON CORPORATION

Consolidating Statements of Operations

(unaudited)

(in millions)


	Three Months Ended June 30, 2009
	Generation			ComEd			PECO			Other			Exelon Consolidated
Operating revenues	$	2,378		$	1,389		$	1,204		$	(830	)	$	4,141

Operating expenses
Purchased power		485			715			547			(826	)		921
Fuel		406			—			55			(1	)		460
Operating and maintenance		689			270			149			2			1,110
Operating and maintenance for regulatory required programs (a)		—			14			—			—			14
Depreciation and amortization		72			124			230			13			439
Taxes other than income		50			57			69			4			180


Total operating expenses		1,702			1,180			1,050			(808	)		3,124


Operating income (loss)		676			209			154			(22	)		1,017


Other income and deductions
Interest expense, net		(24	)		(75	)		(49	)		(32	)		(180	)
Equity in losses of unconsolidated affiliates and investments		—			—			(6	)		—			(6	)
Other, net		215			55			3			(16	)		257


Total other income and deductions		191			(20	)		(52	)		(48	)		71


Income (loss) from continuing operations before income taxes		867			189			102			(70	)		1,088

Income taxes		355			73			31			(29	)		430


Income (loss) from continuing operations		512			116			71			(41	)		658

Loss from discontinued operations		—			—			—			(1	)		(1	)


Net income (loss)	$	512		$	116		$	71		$	(42	)	$	657


	Three Months Ended June 30, 2008
	Generation			ComEd			PECO			Other			Exelon Consolidated
Operating revenues	$	2,756		$	1,425		$	1,277		$	(836	)	$	4,622

Operating expenses
Purchased power		612			820			594			(860	)		1,166
Fuel		271			—			80			1			352
Operating and maintenance		615			274			196			(5	)		1,080
Operating and maintenance for regulatory required programs (a)		—			6			—			—			6
Depreciation and amortization		73			113			205			11			402
Taxes other than income		47			71			64			4			186


Total operating expenses		1,618			1,284			1,139			(849	)		3,192


Operating income		1,138			141			138			13			1,430


Other income and deductions
Interest expense, net		(38	)		(87	)		(58	)		(31	)		(214	)
Equity in losses of unconsolidated affiliates and investments		(1	)		(3	)		(4	)		—			(8	)
Other, net		(63	)		5			7			11			(40	)


Total other income and deductions		(102	)		(85	)		(55	)		(20	)		(262	)


Income (loss) from continuing operations before income taxes		1,036			56			83			(7	)		1,168

Income taxes		383			21			25			(10	)		419


Income from continuing operations		653			35			58			3			749

Loss from discontinued operations		—			—			—			(1	)		(1	)


Net income	$	653		$	35		$	58		$	2		$	748

(a)	Includes amounts for various legislative and/or regulatory programs that are recoverable from customers on a full and current basis through a reconcilable automatic adjustment clause. An equal and offsetting amount has been reflected in operating revenues during the period.

EXELON CORPORATION

Consolidating Statements of Operations

(unaudited)

(in millions)


	Six Months Ended June 30, 2009
	Generation			ComEd			PECO			Other			Exelon Consolidated
Operating revenues	$	4,979		$	2,942		$	2,718		$	(1,776	)	$	8,863

Operating expenses
Purchased power		660			1,598			1,116			(1,770	)		1,604
Fuel		915			—			321			—			1,236
Operating and maintenance		1,617			522			327			6			2,472
Operating and maintenance for regulatory required programs (a)		—			25			—			—			25
Depreciation and amortization		149			246			455			25			875
Taxes other than income		100			136			135			9			380


Total operating expenses		3,441			2,527			2,354			(1,730	)		6,592


Operating income (loss)		1,538			415			364			(46	)		2,271


Other income and deductions
Interest expense, net		(52	)		(159	)		(99	)		(57	)		(367	)
Equity in losses of unconsolidated affiliates and investments		(1	)		—			(12	)		(1	)		(14	)
Other, net		133			87			6			(7	)		219


Total other income and deductions		80			(72	)		(105	)		(65	)		(162	)


Income (loss) from continuing operations before income taxes		1,618			343			259			(111	)		2,109

Income taxes		577			113			76			(26	)		740


Net income (loss)	$	1,041		$	230		$	183		$	(85	)	$	1,369


	Six Months Ended June 30, 2008
	Generation			ComEd			PECO			Other			Exelon Consolidated
Operating revenues	$	5,238		$	2,865		$	2,754		$	(1,718	)	$	9,139

Operating expenses
Purchased power		1,176			1,661			1,165			(1,763	)		2,239
Fuel		542			—			348			—			890
Operating and maintenance		1,399			523			365			(14	)		2,273
Operating and maintenance for regulatory required programs (a)		—			6			—			—			6
Depreciation and amortization		143			224			411			21			799
Taxes other than income		100			140			129			10			379


Total operating expenses		3,360			2,554			2,418			(1,746	)		6,586


Operating income		1,878			311			336			28			2,553


Other income and deductions
Interest expense, net		(74	)		(192	)		(116	)		(54	)		(436	)
Equity in losses of unconsolidated affiliates and investments		(1	)		(5	)		(7	)		—			(13	)
Other, net		(128	)		9			11			10			(98	)


Total other income and deductions		(203	)		(188	)		(112	)		(44	)		(547	)


Income (loss) from continuing operations before income taxes		1,675			123			224			(16	)		2,006

Income taxes		584			47			69			(24	)		676


Income from continuing operations		1,091			76			155			8			1,330

Loss from discontinued operations		(1	)		—			—			—			(1	)


Net income	$	1,090		$	76		$	155		$	8		$	1,329

(a)	Includes amounts for various legislative and/or regulatory programs that are recoverable from customers on a full and current basis through a reconcilable automatic adjustment clause. An equal and offsetting amount has been reflected in operating revenues during the period.

EXELON CORPORATION

Business Segment Comparative Statements of Operations

(unaudited)

(in millions)


	Generation

	Three Months Ended June 30,									Six Months Ended June 30,
	2009			2008			Variance			2009			2008			Variance
Operating revenues	$	2,378		$	2,756		$	(378	)	$	4,979		$	5,238		$	(259	)

Operating expenses
Purchased power		485			612			(127	)		660			1,176			(516	)
Fuel		406			271			135			915			542			373
Operating and maintenance		689			615			74			1,617			1,399			218
Depreciation and amortization		72			73			(1	)		149			143			6
Taxes other than income		50			47			3			100			100			—


Total operating expenses		1,702			1,618			84			3,441			3,360			81


Operating income		676			1,138			(462	)		1,538			1,878			(340	)


Other income and deductions
Interest expense, net		(24	)		(38	)		14			(52	)		(74	)		22
Equity in losses of investments		—			(1	)		1			(1	)		(1	)		—
Other, net		215			(63	)		278			133			(128	)		261


Total other income and deductions		191			(102	)		293			80			(203	)		283


Income from continuing operations before income taxes		867			1,036			(169	)		1,618			1,675			(57	)

Income taxes		355			383			(28	)		577			584			(7	)


Income from continuing operations		512			653			(141	)		1,041			1,091			(50	)

Loss from discontinued operations		—			—			—			—			(1	)		1


Net income	$	512		$	653		$	(141	)	$	1,041		$	1,090		$	(49	)


	ComEd

	Three Months Ended June 30,									Six Months Ended June 30,
	2009			2008			Variance			2009			2008			Variance
Operating revenues	$	1,389		$	1,425		$	(36	)	$	2,942		$	2,865		$	77

Operating expenses
Purchased power		715			820			(105	)		1,598			1,661			(63	)
Operating and maintenance		270			274			(4	)		522			523			(1	)
Operating and maintenance for regulatory required programs (a)		14			6			8			25			6			19
Depreciation and amortization		124			113			11			246			224			22
Taxes other than income		57			71			(14	)		136			140			(4	)


Total operating expenses		1,180			1,284			(104	)		2,527			2,554			(27	)


Operating income		209			141			68			415			311			104


Other income and deductions
Interest expense, net		(75	)		(87	)		12			(159	)		(192	)		33
Equity in losses of unconsolidated affiliates		—			(3	)		3			—			(5	)		5
Other, net		55			5			50			87			9			78


Total other income and deductions		(20	)		(85	)		65			(72	)		(188	)		116


Income before income taxes		189			56			133			343			123			220

Income taxes		73			21			52			113			47			66


Net income	$	116		$	35		$	81		$	230		$	76		$	154

(a)	Includes amounts for various legislative and/or regulatory programs that are recoverable from customers on a full and current basis through a reconcilable automatic adjustment clause. An equal and offsetting amount has been reflected in operating revenues during the period.

EXELON CORPORATION

Business Segment Comparative Statements of Operations

(unaudited)

(in millions)


		PECO

	Three Months Ended June 30,									Six Months Ended June 30,
	2009			2008			Variance			2009			2008			Variance
Operating revenues	$	1,204		$	1,277		$	(73	)	$	2,718		$	2,754		$	(36	)

Operating expenses
Purchased power		547			594			(47	)		1,116			1,165			(49	)
Fuel		55			80			(25	)		321			348			(27	)
Operating and maintenance		149			196			(47	)		327			365			(38	)
Depreciation and amortization		230			205			25			455			411			44
Taxes other than income		69			64			5			135			129			6


Total operating expenses		1,050			1,139			(89	)		2,354			2,418			(64	)


Operating income		154			138			16			364			336			28


Other income and deductions
Interest expense, net		(49	)		(58	)		9			(99	)		(116	)		17
Equity in losses of unconsolidated affiliates		(6	)		(4	)		(2	)		(12	)		(7	)		(5	)
Other, net		3			7			(4	)		6			11			(5	)


Total other income and deductions		(52	)		(55	)		3			(105	)		(112	)		7


Income before income taxes		102			83			19			259			224			35

Income taxes		31			25			6			76			69			7


Net income	$	71		$	58		$	13		$	183		$	155		$	28


		Other (a)

	Three Months Ended June 30,									Six Months Ended June 30,
	2009			2008			Variance			2009			2008			Variance
Operating revenues	$	(830	)	$	(836	)	$	6		$	(1,776	)	$	(1,718	)	$	(58	)

Operating expenses
Purchased power		(826	)		(860	)		34			(1,770	)		(1,763	)		(7	)
Fuel		(1	)		1			(2	)		—			—			—
Operating and maintenance		2			(5	)		7			6			(14	)		20
Depreciation and amortization		13			11			2			25			21			4
Taxes other than income		4			4			—			9			10			(1	)


Total operating expenses		(808	)		(849	)		41			(1,730	)		(1,746	)		16


Operating income (loss)		(22	)		13			(35	)		(46	)		28			(74	)


Other income and deductions
Interest expense, net		(32	)		(31	)		(1	)		(57	)		(54	)		(3	)
Equity in losses of unconsolidated affiliates and investments		—			—			—			(1	)		—			(1	)
Other, net		(16	)		11			(27	)		(7	)		10			(17	)


Total other income and deductions		(48	)		(20	)		(28	)		(65	)		(44	)		(21	)


Loss from continuing operations before income taxes		(70	)		(7	)		(63	)		(111	)		(16	)		(95	)

Income taxes		(29	)		(10	)		(19	)		(26	)		(24	)		(2	)


Income (loss) from continuing operations		(41	)		3			(44	)		(85	)		8			(93	)

Loss from discontinued operations		(1	)		(1	)		—			—			—			—


Net income (loss)	$	(42	)	$	2		$	(44	)	$	(85	)	$	8		$	(93	)

(a)	Other primarily includes eliminating and consolidating adjustments, Exelon’s corporate operations, shared service entities and other financing and investment activities, including investments in synthetic fuel-producing facilities.

EXELON CORPORATION

Consolidated Balance Sheets

(unaudited)

(in millions)


	June 30, 2009			December 31, 2008
Current assets
Cash and cash equivalents	$	1,838		$	1,271
Restricted cash and investments		46			75
Accounts receivable, net
Customer		1,536			1,928
Other		492			324
Mark-to-market derivative assets		627			410
Inventories, net
Fossil fuel		188			315
Materials and supplies		562			528
Other		536			517


Total current assets		5,825			5,368


Property, plant and equipment, net		26,305			25,813

Deferred debits and other assets
Regulatory assets		5,452			5,940
Nuclear decommissioning trust (NDT) funds		5,850			5,500
Investments		723			715
Goodwill		2,625			2,625
Mark-to-market derivative assets		663			507
Other		1,536			1,349


Total deferred debits and other assets		16,849			16,636


Total assets	$	48,979		$	47,817


Liabilities and equity
Current liabilities
Short-term borrowings	$	45		$	211
Long-term debt due within one year		413			29
Long-term debt to PECO Energy Transition Trust due within one year		390			319
Accounts payable		1,144			1,416
Mark-to-market derivative liabilities		294			214
Accrued expenses		1,045			1,151
Deferred income taxes		176			77
Other		659			663


Total current liabilities		4,166			4,080


Long-term debt		11,240			11,397
Long-term debt to PECO Energy Transition Trust		404			805
Long-term debt to other financing trusts		390			390

Deferred credits and other liabilities
Deferred income taxes and unamortized investment tax credits		5,260			4,939
Asset retirement obligations		3,841			3,734
Pension obligations		4,149			4,111
Non-pension postretirement benefits obligations		2,197			2,255
Spent nuclear fuel obligation		1,016			1,015
Regulatory liabilities		2,689			2,520
Mark-to-market derivative liabilities		74			24
Other		1,313			1,413


Total deferred credits and other liabilities		20,539			20,011

Total liabilities		36,739			36,683


Preferred securities of subsidiary		87			87

Shareholders’ equity
Common stock		8,870			8,816
Treasury stock, at cost		(2,338	)		(2,338	)
Retained earnings		7,494			6,820
Accumulated other comprehensive loss, net		(1,873	)		(2,251	)


Total shareholders’ equity		12,153			11,047


Total liabilities and shareholders’ equity	$	48,979		$	47,817

EXELON CORPORATION

Consolidated Statements of Cash Flows

(unaudited)

(in millions)


	Six Months Ended June 30,
	2009			2008
Cash flows from operating activities
Net income	$	1,369		$	1,329
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation, amortization and accretion, including nuclear fuel amortization		1,253			1,096
Impairment of long-lived assets		223			—
Deferred income taxes and amortization of investment tax credits		149			99
Net fair value changes related to derivatives and NDT funds		(15	)		(149	)
Other non-cash operating activities		411			383
Changes in assets and liabilities:
Accounts receivable		286			94
Inventories		75			(40	)
Accounts payable, accrued expenses and other current liabilities		(404	)		(137	)
Counterparty collateral received (posted), net		246			(763	)
Income taxes		(177	)		277
Restricted cash		(2	)		11
Pension and non-pension postretirement benefit contributions		(68	)		(56	)
Other assets and liabilities		(299	)		(470	)

Net cash flows provided by operating activities		3,047			1,674


Cash flows from investing activities
Capital expenditures		(1,444	)		(1,511	)
Proceeds from NDT fund sales		10,150			10,515
Investment in NDT funds		(10,279	)		(10,679	)
Change in restricted cash		31			(22	)
Other investing activities		(4	)		(2	)

Net cash flows used in investing activities		(1,546	)		(1,699	)


Cash flows from financing activities
Issuance of long-term debt		485			1,969
Retirement of long-term debt		(255	)		(1,185	)
Retirement of long-term debt to financing affiliates		(330	)		(596	)
Change in short-term debt		(166	)		857
Dividends paid on common stock		(692	)		(659	)
Proceeds from employee stock plans		19			105
Purchase of treasury stock		—			(436	)
Purchase of forward contract in relation to certain treasury stock		—			(64	)
Other financing activities		5			55

Net cash flows (used in) provided by financing activities		(934	)		46


Increase in cash and cash equivalents		567			21
Cash and cash equivalents at beginning of period		1,271			311

Cash and cash equivalents at end of period	$	1,838		$	332

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, 2009									Three Months Ended June 30, 2008
	GAAP (a)			Adjustments			Adjusted Non-GAAP			GAAP (a)			Adjustments			Adjusted Non-GAAP
Operating revenues	$	4,141		$	32	(c)	$	4,173		$	4,622		$	72	(c)	$	4,694

Operating expenses
Purchased power		921			(161	)(d)		760			1,166			(20	)(d)		1,146
Fuel		460			(13	)(d)		447			352			123	(d)		475
Operating and maintenance		1,110			(54	)(e),(f)		1,056			1,080			44	(h)		1,124
Operating and maintenance for regulatory required programs (b)		14			—			14			6			—			6
Depreciation and amortization		439			—			439			402			—			402
Taxes other than income		180			—			180			186			—			186


Total operating expenses		3,124			(228	)		2,896			3,192			147			3,339


Operating income		1,017			260			1,277			1,430			(75	)		1,355


Other income and deductions
Interest expense, net		(180	)		9	(g)		(171	)		(214	)		—			(214	)
Equity in losses of unconsolidated affiliates and investments		(6	)		—			(6	)		(8	)		—			(8	)
Other, net		257			(252	)(g),(h)		5			(40	)		95	(h)		55


Total other income and deductions		71			(243	)		(172	)		(262	)		95			(167	)


Income from continuing operations before income taxes		1,088			17			1,105			1,168			20			1,188

Income taxes		430			(9	)(c),(d),(e),(f),(g),(h)		421			419			22	(c),(d),(h)		441


Income from continuing operations		658			26			684			749			(2	)		747

Loss from discontinued operations		(1	)		—			(1	)		(1	)		—			(1	)


Net income	$	657		$	26		$	683		$	748		$	(2	)	$	746


Effective tax rate		39.5	%					38.1	%		35.9	%					37.1	%

Earnings per average common share
Basic:
Income from continuing operations	$	1.00		$	0.04		$	1.04		$	1.14		$	—		$	1.14
Income from discontinued operations		—			—			—			—			—			—

Net income	$	1.00		$	0.04		$	1.04		$	1.14		$	—		$	1.14


Diluted:
Income from continuing operations	$	0.99		$	0.04		$	1.03		$	1.13		$	—		$	1.13
Income from discontinued operations		—			—			—			—			—			—

Net income	$	0.99		$	0.04		$	1.03		$	1.13		$	—		$	1.13


Average common shares outstanding
Basic		659						659			657						657
Diluted		661						661			662						662

Effect of adjustments on earnings per average diluted common share recorded in accordance with GAAP:
2007 Illinois electric rate settlement (c)				$	0.03								$	0.07
Mark-to-market impact of economic hedging activities (d)					0.16									(0.09	)
NRG acquisition costs (e)					0.01									—
2009 severance charges (f)					0.04									—
Non-cash income tax matters and state taxes (g)					(0.10	)								—
Unrealized losses related to NDT fund investments (h)					(0.10	)								0.02

Total adjustments				$	0.04								$	—

(a)	Results reported in accordance with accounting principles generally accepted in the United States (GAAP).

(b)	Includes amounts for various legislative and/or regulatory programs that are recoverable from customers on a full and current basis through a reconcilable automatic adjustment clause. An equal and offsetting amount has been reflected in operating revenues during the period.

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

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

(e)	Adjustment to exclude external costs in 2009 associated with Exelon’s proposed acquisition of NRG Energy, Inc. (NRG).

(f)	Adjustment to exclude 2009 severance charges.

(g)	Adjustment to exclude 2009 remeasurements of tax uncertainties and a change in state deferred income taxes.

(h)	Adjustment to exclude the unrealized gains in 2009 and unrealized losses in 2008 associated with Generation’s NDT fund investments and the associated contractual accounting relating to income taxes.

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, 2009									Six Months Ended June 30, 2008
	GAAP (a)			Adjustments			Adjusted Non-GAAP			GAAP (a)			Adjustments			Adjusted Non-GAAP
Operating revenues	$	8,863		$	65	(c)	$	8,928		$	9,139		$	146	(c)	$	9,285

Operating expenses
Purchased power		1,604			40	(d)		1,644			2,239			(96	)(d)		2,143
Fuel		1,236			(28	)(d)		1,208			890			287	(d)		1,177
Operating and maintenance		2,472			(291	)(c),(e),(f),(g)		2,181			2,273			(4	)(c)		2,269
Operating and maintenance for regulatory required programs (b)		25			—			25			6			—			6
Depreciation and amortization		875			—			875			799			—			799
Taxes other than income		380			—			380			379			—			379


Total operating expenses		6,592			(279	)		6,313			6,586			187			6,773


Operating income		2,271			344			2,615			2,553			(41	)		2,512


Other income and deductions
Interest expense, net		(367	)		9	(h)		(358	)		(436	)		—			(436	)
Equity in losses of unconsolidated affiliates and investments		(14	)		—			(14	)		(13	)		—			(13	)
Other, net		219			(156	)(h),(i)		63			(98	)		165	(i)		67


Total other income and deductions		(162	)		(147	)		(309	)		(547	)		165			(382	)


Income before income taxes		2,109			197			2,306			2,006			124			2,130

Income taxes		740			87	(c),(d),(e),(f),(g),(h),(i)		827			676			87	(c),(d),(i)		763


Income from continuing operations		1,369			110			1,479			1,330			37			1,367

Loss from discontinued operations		—			—			—			(1	)		—			(1	)


Net Income	$	1,369		$	110		$	1,479		$	1,329		$	37		$	1,366


Effective tax rate		35.1	%					35.9	%		33.7	%					35.8	%

Earnings per average common share
Basic:
Income from continuing operations	$	2.08		$	0.17		$	2.25		$	2.02		$	0.06		$	2.08
Income from discontinued operations		—			—			—			—			—			—

Net income	$	2.08		$	0.17		$	2.25		$	2.02		$	0.06		$	2.08


Diluted:
Income from continuing operations	$	2.07		$	0.17		$	2.24		$	2.01		$	0.05		$	2.06
Income from discontinued operations		—			—			—			—			—			—

Net income	$	2.07		$	0.17		$	2.24		$	2.01		$	0.05		$	2.06


Average common shares outstanding
Basic		659						659			658						658
Diluted		661						661			663						663

Effect of adjustments on earnings per average diluted common share recorded in accordance with GAAP:
2007 Illinois electric rate settlement (c)				$	0.06								$	0.14
Mark-to-market impact of economic hedging activities (d)					(0.01	)								(0.17	)
NRG acquisition costs (e)					0.03									—
Impairment of certain generating assets (f)					0.20									—
2009 Severance Charges (g)					0.04									—
Non-cash income tax matters and state taxes (h)					(0.10	)								—
Unrealized losses related to NDT fund investments (i)					(0.05	)								0.08

Total adjustments				$	0.17								$	0.05

(a)	Results reported in accordance with GAAP.

(b)	Includes amounts for various legislative and/or regulatory programs that are recoverable from customers on a full and current basis through a reconcilable automatic adjustment clause. An equal and offsetting amount has been reflected in operating revenues during the period.

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

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

(e)	Adjustment to exclude external costs in 2009 associated with Exelon’s proposed acquisition of NRG.

(f)	Adjustment to exclude the impairment of certain of Generation’s Texas plants recorded during the first quarter of 2009.

(g)	Adjustment to exclude 2009 severance charges.

(h)	Adjustment to exclude 2009 remeasurements of tax uncertainties and a change in state deferred income taxes.

(i)

Adjustment to exclude the unrealized gains in 2009 and unrealized losses in 2008 associated with Generation’s NDT fund investments and the associated contractual accounting relating to income taxes. Beginning in the second quarter of 2008, reflects $66 million of an offsetting adjustment to other, net and income taxes related to the contractual elimination of unrealized gains and losses associated Generation’s NDT fund investments, including $44 million recast from the first quarter of 2008.

EXELON CORPORATION

Reconciliation of Adjusted (non-GAAP) Operating Earnings

to GAAP Earnings By Business Segment (in millions)

Three Months Ended June 30, 2009 and 2008


	Exelon Earnings per Diluted Share			Generation			ComEd			PECO			Other			Exelon
2008 GAAP Earnings	$	1.13		$	653		$	35		$	58		$	2		$	748

2008 Adjusted (non-GAAP) Operating Earnings (Loss) Adjustments:
2007 Illinois Electric Rate Settlement		0.07			44			1			—			—			45
Mark-to-Market Impact of Economic Hedging Activities		(0.09	)		(47	)		—			—			(15	)		(62	)
Unrealized Losses Related to NDT Fund Investments		0.02			15			—			—			—			15


2008 Adjusted (non-GAAP) Operating Earnings (Loss)		1.13			665			36			58			(13	)		746

Year Over Year Effects on Earnings:
Generation Energy Margins, Excluding Mark-to-Market (1)		(0.16	)		(109	)		—			—			—			(109	)
ComEd and PECO Margins:
Weather (2)		(0.02	)		—			(1	)		(13	)		—			(14	)
Other Energy Delivery (3)		0.07			—			39			13			—			52
Operating and Maintenance Expense:
Bad Debt (4)		0.05			—			(3	)		35			—			32
Labor, Contracting and Materials (5)		0.02			3			12			(3	)		—			12
Other Operating and Maintenance Expense (6)		0.05			11			14			5			8			38
Pension and Non-Pension Postretirement Benefits Expense (7)		(0.04	)		(14	)		(8	)		(1	)		(5	)		(28	)
Planned Nuclear Refueling Outages (8)		(0.01	)		(8	)		—			—			—			(8	)
Depreciation and Amortization (9)		(0.04	)		1			(7	)		(18	)		(1	)		(25	)
Income Taxes (10)		(0.02	)		(5	)		4			1			(10	)		(10	)
Other		—			(1	)		3			(3	)		(2	)		(3	)


2009 Adjusted (non-GAAP) Operating Earnings (Loss)		1.03			543			89			74			(23	)		683

2009 Adjusted (non-GAAP) Operating Earnings (Loss) Adjustments:
2007 Illinois Electric Rate Settlement		(0.03	)		(18	)		(2	)		—			—			(20	)
Mark-to-Market Impact of Economic Hedging Activities		(0.16	)		(106	)		—			—			—			(106	)
Unrealized Gains Related to NDT Fund Investments		0.10			64			—			—			—			64
NRG Acquisition Costs (11)		(0.01	)		—			—			—			(6	)		(6	)
2009 Severance Charges (12)		(0.04	)		(9	)		(11	)		(3	)		(1	)		(24	)
Non-Cash Remeasurement of Income Tax Uncertainties and Reassessment of State Deferred Income Taxes (13)		0.10			38			40			—			(12	)		66


2009 GAAP Earnings (Loss)	$	0.99		$	512		$	116		$	71		$	(42	)	$	657

(1)	Primarily reflects revenue from certain long options in Generation’s proprietary trading portfolio in 2008, the impact of gains related to the settlement of uranium supply agreements in 2008 and, in 2009, unfavorable portfolio and market conditions and higher nuclear fuel costs.

(2)	Primarily reflects the impact of unfavorable 2009 weather conditions, compared to favorable 2008 weather conditions, in the PECO service territory.

(3)	Primarily reflects in 2009 the impact of increased distribution rates at ComEd effective September 2008 and increased gas distribution rates at PECO effective January 2009, partially offset by reduced load at ComEd and PECO.

(4)	Primarily reflects the impact of PECO’s improved accounts receivable aging resulting from increased collection activities initiated by PECO in 2008.

(5)

Primarily reflects Exelon’s ongoing cost savings initiative and lower planned outage costs at Generation’s non-nuclear generating plants, partially offset by inflation related to labor, contracting and materials expenses (exclusive of planned nuclear refueling outages as disclosed in number 8 below).

(6)	Primarily reflects decreased storm costs in 2009 in the ComEd and PECO service territories and decreased nuclear refueling outage costs related to Generation’s ownership interest in Salem Generating Station.

(7)	Reflects increased pension and non-pension postretirement benefits expense primarily due to lower than expected asset returns in 2008.

(8)	Reflects increased operating and maintenance expense related to nuclear refueling outage costs associated with a higher number of planned refueling outage days during 2009 as compared to 2008, excluding Salem.

(9)

Reflects increased amortization at PECO due to increased scheduled competitive transition charge (CTC) amortization and increased depreciation across the operating companies due to ongoing capital expenditures, partially offset at Generation by reduced depreciation associated with the impaired generating assets.

(10)	Primarily reflects an increase in 2009 state income taxes due to an increase in the current portion of Pennsylvania state apportionment factors.

(11)	Reflects external costs in 2009 associated with Exelon’s proposed acquisition of NRG.

(12)	Reflects expenses associated with the elimination of management and staff positions pursuant to Exelon’s 2009 cost management plan to achieve sustainable cost savings.

(13)	Reflects the impacts of the 2009 remeasurement of tax uncertainties related to ComEd’s 1999 sale of fossil generating assets and a change in state deferred tax rates resulting from a reassessment of anticipated apportionment of Exelon’s income.

EXELON CORPORATION

Reconciliation of Adjusted (non-GAAP) Operating Earnings to

GAAP Earnings By Business Segment (in millions)

Six Months Ended June 30, 2009 and 2008


	Exelon Earnings per Diluted Share			Generation			ComEd			PECO			Other			Exelon
2008 GAAP Earnings	$	2.01		$	1,090		$	76		$	155		$	8		$	1,329

2008 Adjusted (non-GAAP) Operating Earnings (Loss) Adjustments:
2007 Illinois Electric Rate Settlement		0.14			90			4			—			—			94
Mark-to-Market Impact of Economic Hedging Activities		(0.17	)		(84	)		—			—			(30	)		(114	)
Unrealized Losses Related to NDT Fund Investments		0.08			57			—			—			—			57


2008 Adjusted (non-GAAP) Operating Earnings (Loss)		2.06			1,153			80			155			(22	)		1,366

Year Over Year Effects on Earnings:
Generation Energy Margins, Excluding Mark-to-Market (1)		(0.06	)		(42	)		—			—			—			(42	)
ComEd and PECO Margins:
Weather		—			—			(3	)		2			—			(1	)
Other Energy Delivery (2)		0.16			—			79			26			—			105
Operating and Maintenance Expense:
Bad Debt (3)		0.04			—			(2	)		30			—			28
Labor, Contracting and Materials (4)		—			(7	)		13			(4	)		—			2
Other Operating and Maintenance Expense (5)		0.07			12			15			8			7			42
Pension and Non-Pension Postretirement Benefits Expense (6)		(0.07	)		(26	)		(16	)		(3	)		(3	)		(48	)
Planned Nuclear Refueling Outages (7)		0.05			31			—			—			—			31
Depreciation and Amortization (8)		(0.08	)		(4	)		(14	)		(31	)		(3	)		(52	)
NDT Activity (9)		0.01			9			—			—			—			9
Benefit From Illinois Tax Ruling (10)		0.06			8			36			—			(1	)		43
Income Taxes (11)		(0.03	)		(2	)		9			5			(37	)		(25	)
Other (12)		0.03			15			6			(2	)		2			21


2009 Adjusted (non-GAAP) Operating Earnings (Loss)		2.24			1,147			203			186			(57	)		1,479

2009 Adjusted (non-GAAP) Operating Earnings (Loss) Adjustments:
2007 Illinois Electric Rate Settlement		(0.06	)		(39	)		(2	)		—			—			(41	)
Mark-to-Market Impact of Economic Hedging Activities		0.01			7			—			—			—			7
Unrealized Gains Related to NDT Fund Investments		0.05			32			—			—			—			32
NRG Acquisition Costs (13)		(0.03	)		—			—			—			(15	)		(15	)
Impairment of Certain Generating Assets (14)		(0.20	)		(135	)		—			—			—			(135	)
2009 Severance Charges (15)		(0.04	)		(9	)		(11	)		(3	)		(1	)		(24	)
Non-Cash Remeasurement of Income Tax Uncertainties and Reassessment of State Deferred Income Taxes (16)		0.10			38			40			—			(12	)		66


2009 GAAP Earnings (Loss)	$	2.07		$	1,041		$	230		$	183		$	(85	)	$	1,369

(1)

Primarily reflects revenue from certain long options in Generation’s proprietary trading portfolio in 2008, the impact of gains related to the settlement of uranium supply agreements in 2008 and higher nuclear fuel costs, partially offset by 2009 favorable portfolio and market conditions and increased nuclear output as a result of fewer refueling outage days in 2009.

(2)	Primarily reflects in 2009 the impact of increased distribution rates at ComEd effective September 2008 and increased gas distribution rates at PECO effective January 2009, partially offset by reduced load at ComEd and PECO.

(3)	Primarily reflects the impact of PECO’s improved accounts receivable aging resulting from increased collection activities initiated by PECO in 2008.

(4)

(5)	Primarily reflects decreased nuclear refueling outage costs related to Generation’s ownership interest in Salem Generating Station and the impact of decreased storm costs in 2009 in the ComEd and PECO service territories.

(6)	Reflects increased pension and non-pension postretirement benefits expense primarily due to lower than expected asset returns in 2008.

(7)	Reflects decreased operating and maintenance expense related to nuclear refueling outage costs associated with a lower number of planned refueling outage days during 2009 as compared to 2008, excluding Salem.

(8)	Primarily reflects increased amortization at PECO due to increased scheduled CTC amortization and increased depreciation across the operating companies due to ongoing capital expenditures, partially offset at Generation by reduced depreciation associated with the impaired generating assets.

(9)	Primarily reflects the impact of realized NDT fund losses related to a tax planning strategy in 2008, partially offset by realized NDT fund losses related to market conditions in 2009.

(10)	Reflects benefits associated with an Illinois Supreme Court decision granting Illinois Investment Tax Credits to Exelon.

(11)	Primarily reflects income from 2008 state tax settlements and an increase in 2009 state income taxes due to an increase in the current portion of Pennsylvania state apportionment factors, partially offset by 2009 tax planning opportunities.

(12)

Primarily reflects decreased interest expense due to lower outstanding debt at ComEd and PECO (including to PECO Energy Transition Trust) and lower interest rates on Generation’s spent nuclear fuel obligation, partially offset by income in 2008 related to the termination of a gas supply guarantee at Generation and the impact of 2008 income tax benefits associated with Exelon’s tax method of capitalizing overhead costs.

(13)	Reflects external costs in 2009 associated with Exelon’s proposed acquisition of NRG.

(14)	Reflects the impairment of certain of Generation’s Texas plants recorded during the first quarter of 2009.

(15)	Reflects expenses associated with the elimination of management and staff positions pursuant to Exelon’s 2009 cost management plan to achieve sustainable cost savings.

(16)	Reflects the impacts of the 2009 remeasurement of tax uncertainties related to ComEd’s 1999 sale of fossil generating assets and a change in state deferred tax rates resulting from a reassessment of anticipated apportionment of Exelon’s income.

EXELON CORPORATION

Reconciliation of Adjusted (non-GAAP) Operating Earnings to

GAAP Consolidated Statements of Operations

(unaudited)

(in millions)


		Generation

	Three Months Ended June 30, 2009									Three Months Ended June 30, 2008
	GAAP (a)			Adjustments			Adjusted Non-GAAP			GAAP (a)			Adjustments			Adjusted Non-GAAP
Operating revenues	$	2,378		$	30	(b)	$	2,408		$	2,756		$	70	(b)	$	2,826

Operating expenses
Purchased power		485			(161	)(c)		324			612			(46	)(c)		566
Fuel		406			(13	)(c)		393			271			123	(c)		394
Operating and maintenance		689			(15	)(d)		674			615			44	(e)		659
Depreciation and amortization		72			—			72			73			—			73
Taxes other than income		50			—			50			47			—			47


Total operating expenses		1,702			(189	)		1,513			1,618			121			1,739


Operating income		676			219			895			1,138			(51	)		1,087


Other income and deductions
Interest expense, net		(24	)		—			(24	)		(38	)		—			(38	)
Equity in losses of investments		—			—			—			(1	)		—			(1	)
Other, net		215			(202	)(e),(f)		13			(63	)		95	(e)		32


Total other income and deductions		191			(202	)		(11	)		(102	)		95			(7	)


Income before income taxes		867			17			884			1,036			44			1,080

Income taxes		355			(14	)(b),(c),(d),(e),(f)		341			383			32	(b),(c),(e)		415


Net Income	$	512		$	31		$	543		$	653		$	12		$	665


	Six Months Ended June 30, 2009									Six Months Ended June 30, 2008
	GAAP (a)			Adjustments			Adjusted Non-GAAP			GAAP (a)			Adjustments			Adjusted Non-GAAP
Operating revenues	$	4,979		$	63	(b)	$	5,042		$	5,238		$	143	(b)	$	5,381

Operating expenses
Purchased power		660			40	(c)		700			1,176			(147	)(c)		1,029
Fuel		915			(28	)(c)		887			542			287	(c)		829
Operating and maintenance		1,617			(238	)(d),(g)		1,379			1,399			—			1,399
Depreciation and amortization		149			—			149			143			—			143
Taxes other than income		100			—			100			100			—			100


Total operating expenses		3,441			(226	)		3,215			3,360			140			3,500


Operating income		1,538			289			1,827			1,878			3			1,881


Other income and deductions
Interest expense, net		(52	)		—			(52	)		(74	)		—			(74	)
Equity in losses of investments		(1	)		—			(1	)		(1	)		—			(1	)
Other, net		133			(106	)(e),(f)		27			(128	)		166	(e)		38


Total other income and deductions		80			(106	)		(26	)		(203	)		166			(37	)


Income from continuing operations before income taxes		1,618			183			1,801			1,675			169			1,844

Income taxes		577			77	(b),(c),(d),(e),(f),(g)		654			584			106	(b),(c),(e)		690


Income from continuing operations		1,041			106			1,147			1,091			63			1,154

Loss from discontinued operations		—			—			—			(1	)		—			(1	)


Net income	$	1,041		$	106		$	1,147		$	1,090		$	63		$	1,153

(a)	Results reported in accordance with GAAP.

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

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

(d)	Adjustment to exclude 2009 severance charges.

(e)

(f)	Adjustment to exclude a change in state deferred income taxes.

(g)	Adjustment to exclude the impairment of certain of Generation’s Texas plants recorded during the first quarter of 2009.

EXELON CORPORATION

Reconciliation of Adjusted (non-GAAP) Operating Earnings to

GAAP Consolidated Statements of Operations

(unaudited)

(in millions)


	ComEd
	Three Months Ended June 30, 2009									Three Months Ended June 30, 2008
	GAAP (a)			Adjustments			Adjusted Non-GAAP			GAAP (a)			Adjustments			Adjusted Non-GAAP
Operating revenues	$	1,389		$	2	(c)	$	1,391		$	1,425		$	2	(c)	$	1,427

Operating expenses
Purchased power		715			—			715			820			—			820
Operating and maintenance		270			(20	)(c),(d)		250			274			—			274
Operating and maintenance for regulatory required programs (b)		14			—			14			6			—			6
Depreciation and amortization		124			—			124			113			—			113
Taxes other than income		57			—			57			71			—			71


Total operating expenses		1,180			(20	)		1,160			1,284			—			1,284


Operating income		209			22			231			141			2			143


Other income and deductions
Interest expense, net		(75	)		(6	)(e)		(81	)		(87	)		—			(87	)
Equity in losses of unconsolidated affiliates		—			—			—			(3	)		—			(3	)
Other, net		55			(60	)(e)		(5	)		5			—			5


Total other income and deductions		(20	)		(66	)		(86	)		(85	)		—			(85	)


Income before income taxes		189			(44	)		145			56			2			58

Income taxes		73			(17	)(c),(d),(e)		56			21			1	(c)		22


Net income	$	116		$	(27	)	$	89		$	35		$	1		$	36


	Six Months Ended June 30, 2009									Six Months Ended June 30, 2008
	GAAP (a)			Adjustments			Adjusted Non-GAAP			GAAP (a)			Adjustments			Adjusted Non-GAAP
Operating revenues	$	2,942		$	2	(c)	$	2,944		$	2,865		$	3	(c)	$	2,868

Operating expenses
Purchased power		1,598			—			1,598			1,661			—			1,661
Operating and maintenance		522			(20	)(c),(d)		502			523			(4	)(c)		519
Operating and maintenance for regulatory required programs (b)		25			—			25			6						6
Depreciation and amortization		246			—			246			224			—			224
Taxes other than income		136			—			136			140			—			140


Total operating expenses		2,527			(20	)		2,507			2,554			(4	)		2,550


Operating income		415			22			437			311			7			318


Other income and deductions
Interest expense, net		(159	)		(6	)(e)		(165	)		(192	)		—			(192	)
Equity in losses of unconsolidated affiliates		—			—			—			(5	)		—			(5	)
Other, net		87			(60	)(e)		27			9			—			9


Total other income and deductions		(72	)		(66	)		(138	)		(188	)		—			(188	)


Income before income taxes		343			(44	)		299			123			7			130

Income taxes		113			(17	)(c),(d),(e)		96			47			3	(c)		50


Net income	$	230		$	(27	)	$	203		$	76		$	4		$	80

(a)	Results reported in accordance with GAAP.

(b)	Includes amounts for various legislative and/or regulatory programs that are recoverable from customers on a full and current basis through a reconcilable automatic adjustment clause. An equal and offsetting amount has been reflected in operating revenues during the period.

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

(d)	Adjustment to exclude 2009 severance charges.

(e)	Adjustment to exclude 2009 remeasurements of income tax uncertainties.

EXELON CORPORATION

Reconciliation of Adjusted (non-GAAP) Operating Earnings to

GAAP Consolidated Statements of Operations

(unaudited)

(in millions)


	PECO
	Three Months Ended June 30, 2009									Three Months Ended June 30, 2008
	GAAP (a)			Adjustments			Adjusted Non-GAAP			GAAP (a)			Adjustments		Adjusted Non-GAAP
Operating revenues	$	1,204		$	—		$	1,204		$	1,277		$	—	$	1,277

Operating expenses
Purchased power		547			—			547			594			—		594
Fuel		55			—			55			80			—		80
Operating and maintenance		149			(5	)(b)		144			196			—		196
Depreciation and amortization		230			—			230			205			—		205
Taxes other than income		69			—			69			64			—		64


Total operating expenses		1,050			(5	)		1,045			1,139			—		1,139


Operating income		154			5			159			138			—		138


Other income and deductions
Interest expense, net		(49	)		—			(49	)		(58	)		—		(58	)
Equity in losses of unconsolidated affiliates		(6	)		—			(6	)		(4	)		—		(4	)
Other, net		3			—			3			7			—		7


Total other income and deductions		(52	)		—			(52	)		(55	)		—		(55	)


Income before income taxes		102			5			107			83			—		83

Income taxes		31			2	(b)		33			25			—		25


Net income	$	71		$	3		$	74		$	58		$	—	$	58


	Six Months Ended June 30, 2009									Six Months Ended June 30, 2008
	GAAP (a)			Adjustments			Adjusted Non-GAAP			GAAP (a)			Adjustments		Adjusted Non-GAAP
Operating revenues	$	2,718		$	—		$	2,718		$	2,754		$	—	$	2,754

Operating expenses
Purchased power		1,116			—			1,116			1,165			—		1,165
Fuel		321			—			321			348					348
Operating and maintenance		327			(5	)(b)		322			365			—		365
Depreciation and amortization		455			—			455			411			—		411
Taxes other than income		135			—			135			129			—		129


Total operating expenses		2,354			(5	)		2,349			2,418			—		2,418


Operating income		364			5			369			336			—		336


Other income and deductions
Interest expense, net		(99	)		—			(99	)		(116	)		—		(116	)
Equity in losses of unconsolidated affiliates		(12	)		—			(12	)		(7	)		—		(7	)
Other, net		6			—			6			11			—		11


Total other income and deductions		(105	)		—			(105	)		(112	)		—		(112	)


Income before income taxes		259			5			264			224			—		224

Income taxes		76			2	(b)		78			69			—		69


Net income	$	183		$	3		$	186		$	155		$	—	$	155

(a)	Results reported in accordance with GAAP.

(b)	Adjustment to exclude 2009 severance charges.

EXELON CORPORATION

Reconciliation of Adjusted (non-GAAP) Operating Earnings to

GAAP Consolidated Statements of Operations

(unaudited)

(in millions)


	Other
	Three Months Ended June 30, 2009									Three Months Ended June 30, 2008
	GAAP (a)			Adjustments			Adjusted Non-GAAP			GAAP (a)			Adjustments			Adjusted Non-GAAP
Operating revenues	$	(830	)	$	—		$	(830	)	$	(836	)	$	—		$	(836	)

Operating expenses
Purchased power		(826	)		—			(826	)		(860	)		26	(f)		(834	)
Fuel		(1	)		—			(1	)		1			—			1
Operating and maintenance		2			(14	)(b),(c)		(12	)		(5	)		—			(5	)
Depreciation and amortization		13			—			13			11			—			11
Taxes other than income		4			—			4			4			—			4


Total operating expenses		(808	)		(14	)		(822	)		(849	)		26			(823	)


Operating income (loss)		(22	)		14			(8	)		13			(26	)		(13	)


Other income and deductions
Interest expense, net		(32	)		15	(d)		(17	)		(31	)		—			(31	)
Equity in losses of unconsolidated affiliates and investments		—			—			—			—			—			—
Other, net		(16	)		10	(d)		(6	)		11			—			11


Total other income and deductions		(48	)		25			(23	)		(20	)		—			(20	)


Loss from continuing operations before income taxes		(70	)		39			(31	)		(7	)		(26	)		(33	)

Income taxes		(29	)		20	(b),(c),(d),(e)		(9	)		(10	)		(11	)(f)		(21	)


Income (loss) from continuing operations		(41	)		19			(22	)		3			(15	)		(12	)

Loss from discontinued operations		(1	)		—			(1	)		(1	)		—			(1	)


Net income (loss)	$	(42	)	$	19		$	(23	)	$	2		$	(15	)	$	(13	)


	Six Months Ended June 30, 2009									Six Months Ended June 30, 2008
	GAAP (a)			Adjustments			Adjusted Non-GAAP			GAAP (a)			Adjustments			Adjusted Non-GAAP
Operating revenues	$	(1,776	)	$	—		$	(1,776	)	$	(1,718	)	$	—		$	(1,718	)

Operating expenses
Purchased power		(1,770	)		—			(1,770	)		(1,763	)		51	(f)		(1,712	)
Fuel		—			—			—			—			—			—
Operating and maintenance		6			(28	)(b),(c)		(22	)		(14	)		—			(14	)
Depreciation and amortization		25			—			25			21			—			21
Taxes other than income		9			—			9			10			—			10


Total operating expenses		(1,730	)		(28	)		(1,758	)		(1,746	)		51			(1,695	)


Operating income (loss)		(46	)		28			(18	)		28			(51	)		(23	)


Other income and deductions
Interest expense, net		(57	)		15	(d)		(42	)		(54	)		—			(54	)
Equity in losses of unconsolidated affiliates and investments		(1	)		—			(1	)		—			—			—
Other, net		(7	)		10	(d)		3			10			—			10


Total other income and deductions		(65	)		25			(40	)		(44	)		—			(44	)


Loss from continuing operations before income taxes		(111	)		53			(58	)		(16	)		(51	)		(67	)

Income taxes		(26	)		25	(b),(c),(d),(e)		(1	)		(24	)		(21	)(f)		(45	)


Net income (loss)	$	(85	)	$	28		$	(57	)	$	8		$	(30	)	$	(22	)

(a)	Results reported in accordance with GAAP.

(b)	Adjustment to exclude external costs associated with Exelon’s proposed acquisition of NRG.

(c)	Adjustment to exclude 2009 severance charges.

(d)	Adjustment to exclude 2009 remeasurements of income tax uncertainties.

(e)	Adjustment to exclude a change in state deferred income taxes.

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

EXELON CORPORATION

Exelon Generation Statistics


	Three Months Ended
	Jun. 30, 2009		Mar. 31, 2009		Dec. 31, 2008		Sept. 30, 2008		Jun. 30, 2008
Supply (in GWhs)
Nuclear		34,995		35,382		34,887		36,451		35,069
Purchased Power		5,276		6,077		6,100		8,761		5,575
Fossil and Hydro		2,701		2,765		2,162		2,685		2,910

Power Team Supply		42,972		44,224		43,149		47,897		43,554


	Three Months Ended
	Jun. 30, 2009		Mar. 31, 2009		Dec. 31, 2008		Sept. 30, 2008		Jun. 30, 2008
Electric Sales (in GWhs)
ComEd (a)		4,215		5,537		5,261		6,629		5,218
PECO (a)		9,277		10,223		9,760		11,333		9,761
Market and Retail (a)		29,480		28,464		28,128		29,935		28,575

Total Electric Sales (b) (c)		42,972		44,224		43,149		47,897		43,554


Average Margin ($/MWh)
Average Realized Revenue
ComEd (a)	$	63.58	$	63.21	$	63.30	$	64.41	$	63.82
PECO (a)		51.74		49.30		49.28		53.03		52.04
Market and Retail (a)		54.27		57.12		54.18		65.98		61.91
Total Electric Sales		54.64		56.08		54.18		62.70		59.93
Average Purchased Power and Fuel Cost (d)	$	15.68	$	16.82	$	15.90	$	26.16	$	19.40
Average Margin (d)	$	38.96	$	39.25	$	38.28	$	36.54	$	40.53

Around-the-clock Market Prices ($/MWh) (e)
PJM West Hub	$	33.70	$	49.18	$	52.62	$	77.37	$	75.65
NiHub		26.11		34.09		38.06		53.28		51.39

(a)

$69 million, $31 million and $20 million of pre-tax revenue, and $15 million and $7 million of a pre-tax reduction in revenue, resulting from the settlement of the ComEd swap starting in June 2008, have been excluded from ComEd and included in Market and Retail sales for the quarters ended June 30, 2009, March 31, 2009, December 31, 2008, September, 30, 2008 and June 30, 2008, respectively. Additionally, $7 million (209 GWhs), $58 million (898 GWhs), and $29 million (486 GWhs) of pre-tax revenue, resulting from sales to ComEd under the RFP, which started in September 2008, have been excluded from ComEd and included in Market and Retail sales for the quarters ended June 30, 2009, March 31, 2009, and December 31, 2008, respectively. In addition, renewable energy credits sales to affiliates have been included within Market and Retail Sales.

(b)	Excludes retail gas activity, trading portfolio and other operating revenue.

(c)	Total sales do not include trading volume of 2,003 GWhs, 2,331 GWhs, 2,153 GWhs, 3,092 GWhs and 1,784 GWhs for the three months ended June 30, 2009, March 31, 2009, December 31, 2008, September 30, 2008, and June 30, 2008, respectively.

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

(e)	Represents the average for the quarter.

EXELON CORPORATION

Exelon Generation Statistics

Six Months Ended June 30, 2009 and 2008


	June 30, 2009		June 30, 2008
Supply (in GWhs)
Nuclear		70,377		68,003
Purchased Power		11,353		11,403
Fossil and Hydro		5,466		5,722

Power Team Supply		87,196		85,128


	June 30, 2009		June 30, 2008
Electric Sales (in GWhs)
ComEd (a)		9,752		11,310
PECO (a)		19,500		19,873
Market and Retail (a)		57,944		53,945

Total Electric Sales (b) (c)		87,196		85,128


Average Margin ($/MWh)
Average Realized Revenue
ComEd (a)	$	63.37	$	63.48
PECO (a)		50.46		50.37
Market and Retail (a)		55.64		59.69
Total Electric Sales		55.35		58.02
Average Purchased Power and Fuel Cost (d)	$	16.26	$	18.35
Average Margin (d)	$	39.09	$	39.67

Around-the-clock Market Prices ($/MWh) (e)
PJM West Hub	$	41.40	$	72.09
NiHub		30.07		52.37

(a)

$100 million of pre-tax revenue, and $7 million of a pre-tax reduction in revenue, resulting from the settlement of the ComEd swap starting in June 2008, have been excluded from ComEd and included in Market and Retail sales for the six months ended June 30, 2009 and June 30, 2008, respectively. Additionally, $65 million (1,107 GWhs) of pre-tax revenue, resulting from sales to ComEd under the RFP, which started in September 2008, have been excluded from ComEd and included in Market and Retail sales for the six months ended June 30, 2009. In addition, renewable energy credits sales to affiliates have been included within Market and Retail Sales.

(b)	Excludes retail gas sales, trading portfolio and other operating revenue.

(c)	Total sales do not include trading volume of 4,334 GWhs and 3,646 GWhs for the six months ended June 30, 2009 and 2008, respectively.

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

(e)	Represents the average for the year.

EXELON CORPORATION

ComEd Statistics

Three Months Ended June 30, 2009 and 2008


	Electric Deliveries (in GWhs)				Revenue (in millions)
	2009	2008	% Change		2009		2008		% Change
Full Service (a)
Residential	6,032	6,119	(1.4	%)	$	731	$	732	(0.1	%)
Small Commercial & Industrial	3,272	3,543	(7.6	%)		328		379	(13.5	%)
Large Commercial & Industrial	258	174	48.3	%		14		18	(22.2	%)
Public Authorities & Electric Railroads	101	133	(24.1	%)		11		10	10.0	%


Total Full Service	9,663	9,969	(3.1	%)		1,084		1,139	(4.8	%)

Delivery Only (b)
Residential	—	—	n.	m.		—		—	n.	m.
Small Commercial & Industrial	4,467	4,522	(1.2	%)		83		72	15.3	%
Large Commercial & Industrial	6,210	6,830	(9.1	%)		79		71	11.3	%
Public Authorities & Electric Railroads	174	119	46.2	%		3		1	n.	m.

Total Delivery Only	10,851	11,471	(5.4	%)		165		144	14.6	%

Total Retail	20,514	21,440	(4.3	%)		1,249		1,283	(2.7	%)


Other Revenue (d)						140		142	(1.4	%)


Total Revenues					$	1,389	$	1,425	(2.5	%)


Purchased Power					$	715	$	820	(12.8	%)


Heating and Cooling Degree-Days (e)	2009	2008	Normal
Heating Degree-Days	768	755	766
Cooling Degree-Days	177	192	224

(a)	Reflects deliveries to customers purchasing electricity from ComEd.

(b)	Reflects customers electing to purchase electricity from an alternative electric generation supplier.

(c)	There are a minimal number of residential customers being served by alternative suppliers with total activity of less than 1 GWh and $1 million.

(d)	Other revenue primarily includes transmission revenue from PJM Interconnection, LLC (PJM). Other items include late payment charges and mutual assistance program revenues.

(e)	Reflects the impact of the leap year day in 2008.

n.m.	Not meaningful.

Six Months Ended June 30, 2009 and 2008


	Electric Deliveries (in GWhs)				Revenue (in millions)
	2009	2008	% Change		2009		2008		% Change
Full Service (a)
Residential	13,095	13,407	(2.3	%)	$	1,577	$	1,493	5.6	%
Small Commercial & Industrial	6,951	7,345	(5.4	%)		705		741	(4.9	%)
Large Commercial & Industrial	629	484	30.0	%		39		43	(9.3	%)
Public Authorities & Electric Railroads	207	313	(33.9	%)		22		27	(18.5	%)


Total Full Service	20,882	21,549	(3.1	%)		2,343		2,304	1.7	%

Delivery Only (b)
Residential	—	—	n.	m.		—		—	n.	m.
Small Commercial & Industrial	8,938	9,097	(1.7	%)		155		136	14.0	%
Large Commercial & Industrial	12,613	13,754	(8.3	%)		153		136	12.5	%
Public Authorities & Electric Railroads	414	286	44.8	%		7		3	n.	m.

Total Delivery Only	21,965	23,137	(5.1	%)		315		275	14.5	%

Total Retail	42,847	44,686	(4.1	%)		2,658		2,579	3.1	%


Other Revenue (d)						284		286	(0.7	%)


Total Revenues					$	2,942	$	2,865	2.7	%


Purchased Power					$	1,598	$	1,661	(3.8	%)


Heating and Cooling Degree-Days (e)	2009	2008	Normal
Heating Degree-Days	4,088	4,172	3,974
Cooling Degree-Days	177	192	224

(a)	Reflects deliveries to customers purchasing electricity from ComEd.

(b)	Reflects customers electing to purchase electricity from an alternative electric generation supplier.

(c)	There are a minimal number of residential customers being served by alternative suppliers with total activity of less than 1 GWh and $1 million.

(d)	Other revenue primarily includes transmission revenue from PJM Interconnection, LLC (PJM). Other items include late payment charges and mutual assistance program revenues.

(e)	Reflects the impact of the leap year day in 2008.

n.m.	Not meaningful.

EXELON CORPORATION

PECO Statistics

Three Months Ended June 30, 2009 and 2008


	Electric and Gas Deliveries				Revenue (in millions)
	2009	2008	% Change		2009		2008		% Change
Electric (in GWhs)
Full Service (a)
Residential	2,759	2,941	(6.2	%)	$	415	$	442	(6.1	%)
Small Commercial & Industrial	1,929	1,960	(1.6	%)		256		261	(1.9	%)
Large Commercial & Industrial	3,877	4,142	(6.4	%)		338		359	(5.8	%)
Public Authorities & Electric Railroads	222	226	(1.8	%)		22		22	0.0	%

Total Full Service	8,787	9,269	(5.2	%)		1,031		1,084	(4.9	%)


Delivery Only (b)
Residential	5	7	(28.6	%)		1		1	0.0	%
Small Commercial & Industrial	84	115	(27.0	%)		4		6	(33.3	%)
Large Commercial & Industrial	1	—	100.0	%		—		—	0.0	%

Total Delivery Only	90	122	(26.2	%)		5		7	(28.6	%)


Total Electric Retail	8,877	9,391	(5.5	%)		1,036		1,091	(5.0	%)

Other Revenue (c)						67		71	(5.6	%)


Total Electric Revenue						1,103		1,162	(5.1	%)

Gas (in mmcfs)
Retail Sales	7,136	6,838	4.4	%		95		109	(12.8	%)
Transportation and Other	6,105	6,158	(0.9	%)		6		6	0.0	%

Total Gas	13,241	12,996	1.9	%		101		115	(12.2	%)


Total Electric and Gas Revenues					$	1,204	$	1,277	(5.7	%)

Purchased Power					$	547	$	594	(7.9	%)
Fuel						55		80	(31.3	%)

Total Purchased Power and Fuel					$	602	$	674	(10.7	%)


Heating and Cooling Degree-Days (d)	2009	2008	Normal
Heating Degree-Days	414	410	458
Cooling Degree-Days	352	393	332
Six Months Ended June 30, 2009 and 2008

	Electric and Gas Deliveries				Revenue (in millions)
	2009	2008	% Change		2009		2008		% Change
Electric (in GWhs)
Full Service (a)
Residential	6,287	6,348	(1.0	%)	$	881	$	894	(1.5	%)
Small Commercial & Industrial	4,027	4,000	0.7	%		501		501	0.0	%
Large Commercial & Industrial	7,667	8,075	(5.1	%)		657		698	(5.9	%)
Public Authorities & Electric Railroads	469	460	2.0	%		45		44	2.3	%

Total Full Service	18,450	18,883	(2.3	%)		2,084		2,137	(2.5	%)


Delivery Only (b)
Residential	12	15	(20.0	%)		1		1	0.0	%
Small Commercial & Industrial	182	239	(23.8	%)		9		13	(30.8	%)
Large Commercial & Industrial	2	2	0.0	%		—		—	0.0	%

Total Delivery Only	196	256	(23.4	%)		10		14	(28.6	%)


Total Electric Retail	18,646	19,139	(2.6	%)		2,094		2,151	(2.6	%)

Other Revenue (c)						135		135	0.0	%


Total Electric Revenue						2,229		2,286	(2.5	%)

Gas (in mmcfs)
Retail Sales	35,750	33,185	7.7	%		475		452	5.1	%
Transportation and Other	13,983	14,351	(2.6	%)		14		16	(12.5	%)

Total Gas	49,733	47,536	4.6	%		489		468	4.5	%


Total Electric and Gas Revenues					$	2,718	$	2,754	(1.3	%)

Purchased Power					$	1,116	$	1,165	(4.2	%)
Fuel						321		348	(7.8	%)

Total Purchased Power and Fuel					$	1,437	$	1,513	(5.0	%)


Heating and Cooling Degree-Days (d)	2009	2008	Normal
Heating Degree-Days	2,948	2,732	2,968
Cooling Degree-Days	352	393	332

(a)	Full service reflects deliveries to customers purchasing electricity directly from PECO. Revenue reflects the cost of energy, the cost of the transmission and the distribution of the energy and a CTC.

(b)	Delivery only service reflects deliveries to customers electing to receive electric generation service from a competitive electric generation supplier. Revenue reflects a distribution charge and a CTC.

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

(d)	Reflects the impact of the leap year day in 2008.

Earnings conference call presentation slides

Earnings Conference Call •

Quarter 2009

July 24, 2009

EXHIBIT 99.2

Forward-Looking Statements

This presentation includes forward-looking statements within the meaning of the Private

Securities Litigation Reform Act of 1995, that are subject to risks and uncertainties. The factors

that could cause actual results to differ materially from these forward-looking statements

include those discussed herein as well as those discussed in (1) Exelon’s 2008 Annual Report

on Form 10-K in (a) ITEM 1A. Risk Factors, (b) ITEM 7. Management’s Discussion and Analysis

of Financial Condition and Results of Operations and (c) ITEM 8. Financial Statements and

Supplementary Data: Note 18; (2) Exelon’s Second Quarter 2009 Quarterly Report on Form

10-Q (to be filed on July 24, 2009) in (a) Part II, Other Information, ITEM 1A. Risk Factors and (b)

Part I, Financial Information, ITEM 1. Financial Statements: Note 14 and (3) other factors

discussed in filings with the Securities and Exchange Commission (SEC) by Exelon

Corporation, Commonwealth Edison Company, PECO Energy Company and Exelon Generation

Company, LLC (Companies). Readers are cautioned not to place undue reliance on these

forward-looking statements, which apply only as of the date of this presentation. None of the

Companies undertakes any obligation to publicly release any revision to its forward-looking

statements to reflect events or circumstances after the date of this presentation.

This presentation includes references to adjusted (non-GAAP) operating earnings and non-

GAAP cash flows that exclude the impact of certain factors. We believe that these adjusted

operating earnings and cash flows are representative of the underlying operational results of

the Companies. Please refer to the attachments to the earnings release and the appendix to

this presentation for a reconciliation of adjusted (non-GAAP) operating earnings to GAAP

earnings. Please refer to the footnotes of the following slides for a reconciliation non-GAAP

cash flows to GAAP cash flows.

Carbon

Cost

Reductions

Procurement

Nuclear

Uprates

Lowest

carbon

intensity

the

sector

$1.1

billion

(2)

and

growing

annual

upside

Exelon revenues from implementation of Waxman-Markey legislation

Developing business plan for transmission company to improve reliability, reduce

congestion, mitigate oversupply and allow our Midwest fleet to maintain its

baseload value

$350 million in announced O&M reductions for 2010, more than half of which is

sustainable

1,300 MW -

1,500 MW in Exelon nuclear uprates by 2017, the equivalent of a

new nuclear plant at roughly ½

the cost of new build and no incremental

operating costs

$101.30/MWh

(1)

result

June

PECO

power

procurement

suggests

higher

margins at Exelon Generation in 2011 and beyond

ComEd

and

PECO

plan

make

up to

billion

investments

build

smart

grid infrastructure over the coming years, providing for a regulated return on

investment

(1) Reflects retail price including line losses and gross receipts tax

(2) Assumes $15/tonne carbon pricing.

Exelon’s Long-Term Growth Proposition

Remains the Best in the Industry

Transmission

Smart Grid

Key Financial Messages

Q2 operating results of $1.03/share driven by:

Exceptional nuclear operations –

93.9% capacity factor

Increased electric distribution rates at ComEd effective September 2008 and gas

distribution revenues at PECO effective January 2009

Reduction in O&M expenses of over $50 million in second quarter reflecting the impact of

Exelon’s cost management initiatives

Reaffirming 2009 operating earnings guidance of $4.00-$4.30/share

95-98% of 2009 expected generation hedged

(1)

On track to keep 2009 operating O&M

(2)

costs flat to 2008 at $4.5 billion

Well-positioned for continued financial strength going forward

Strong

cash

flow

from

operations

(3)

–

forecasted

$5.4

billion

for

2009,

increase

$700 million over original guidance assumptions

Committed

additional

$350

million

reduction

operating

O&M

(2)

expense

2010,

nearly

3.5%

decline

from

2009

levels

(4)

Refer

Earnings

Release

Attachments

for

additional

details

and

the

Appendix

for

reconciliation

adjusted

(non-GAAP)

operating

EPS

GAAP

EPS.

(1) As of June 30, 2009.

(2) Operating O&M excludes Decommissioning impact. ComEd and PECO operating O&M excludes energy efficiency spend recoverable under a rider.

(3) Cash Flow from Operations primarily includes net cash flows provided by operating activities (excluding counterparty collateral activity) and net cash flows used in

investing activities other than capital expenditures.

(4)

Exelon projects a nearly 3.5% decrease in year-over-year O&M spending, from approximately $4.5 billion in 2009 to $4.35 billion in 2010. These reductions represent

over $350 million of O&M savings in 2010, as Exelon anticipated a 4% increase in O&M absent these actions.

Note: Information contained on this slide is rounded.

$1.01

$0.09

$0.82

$0.11

$0.05

$0.13

2008

2009

Operating EPS

$1.74

$0.23

$1.74

$0.28

$0.12

$0.31

2008

2009

HoldCo/Other

ExGen

PECO

ComEd

Quarter (Q2)

(1)

As expected, second quarter results were driven by higher quarter-over-quarter earnings at

ComEd and PECO, offset by lower operating earnings at Exelon Generation

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

$1.13

$0.99

GAAP EPS

Year-to-Date (YTD)

(1)

$2.24

$2.06

$2.01

$2.07

$1.03

$1.13

Exelon Generation

Operating EPS Contribution

2009

2008

Key Drivers –

Q2 ’09 vs. Q2 ’08

(1)

‘08

Proprietary

trading

gains:

($0.07)

‘08 Uranium contract settlement:

($0.04)

Unfavorable portfolio/market

conditions:

($0.02)

Higher

nuclear

fuel

costs:

($0.02)

Higher O&M primarily due to pension

and OPEB expense and inflation

partially offset by cost savings

initiatives:

($0.01)

Income taxes:

($0.01)

(1)

Refer

the

Earnings

Release

Attachments

for

additional

details

and

the

Appendix

for

reconciliation

adjusted

(non-GAAP)

operating

EPS

GAAP

EPS

(2) Outage days exclude Salem.

Refueling

Non-refueling

Q2 2009

Q2 2008

Outage

Days

(2)

YTD

$1.01

$0.82

$1.74

Key Drivers –

Q2 ’09 vs. Q2 ’08

(1)

Higher electric distribution rates:

+$0.06

Lower O&M due to cost savings

initiatives and decreased storm costs

partially offset by higher pension and

OPEB expense and inflation:

$0.02

Reduced load:

($0.01)

ComEd Operating EPS Contribution

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

2009

2008

YTD

$0.05

$0.13

$0.31

$0.12

PECO Operating EPS Contribution

Key Drivers –

Q2 ’09 vs. Q2 ’08

(1)

Lower bad debt expense:

+$0.05

Higher distribution revenues

(2)

+$0.03

Competitive Transition Charge (CTC)

amortization:

($0.02)

Reduced load:

($0.02)

Weather:

($0.02)

2009

2008

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

(2) Includes the impact of higher gas distribution rates effective January 2009 of $0.01.

YTD

$0.09

$0.11

$0.28

$0.23

ComEd Load Trends

Weather-Normalized Load

Customer Usage by Revenue Class

Key Economic Indicators

Top 380 Customer Usage by Segment

Other

Residential

31%

Small C&I

36%

380 Large

C&I

18%

Other Large

C&I

13%

Leisure & Hospitality

Trade, Transportation & Utilities

11%

Finance, Professional &

Business Services

12%

Health & Educational Services

13%

Government

52%

Manufacturing

Chicago

U.S.

Unemployment rate

(1)

10.6%

9.5%

Q2 2009 annualized growth in

gross domestic/metro product

(2)

(3.5)% (1.8)%

4/09 Home price index

(3)

(18.7)% (18.1)%

(1) Source: Illinois Dept. of Employment Security and U.S. Dept. of Labor

(July 2009 reports)

(2)

Source: Moody’s Economy.com

(3)

Source: S&P Case-Shiller Index

(4)

Adjusted for leap year impact

(5)

Not adjusted for leap year impact

Q1 2009

(4)

2009

2009E

(5)

Customer Growth

(0.2)%

(0.4)% (0.4)%

Average Use-Per-Customer

(1.0)%

(0.9)%

(1.0)%

Total Residential

(1.2)%

(1.3)% (1.4)%

Small C&I

(1.3)%

(3.7)% (2.0)%

Large C&I

(5.3)%

(7.5)% (5.9)%

All Customer Classes

(2.5)%

(4.1)% (3.0)%

Note: C&I = Commercial & Industrial

PECO Load Trends

Other

Other Large

C&I

21%

150 Large

C&I

21%

Small C&I

22%

Residential

34%

Weather-Normalized Electric Load

2009

(3)

2009

2009E

(4)

Customer Growth

0.1%

(0.3)%

0.1%

Average Use-Per-Customer

0.1%

(1.7)%

(0.5)%

Total Residential

0.2% (2.0)%

(0.4)%

Small C&I

0.0% (0.7)%

(1.1)%

Large C&I

(3.3)% (4.0)% (3.5)%

All Customer Classes

(1.1)% (2.6)%

(1.8)%

Customer Usage by Revenue Class

Philadelphia

U.S.

Unemployment rate

(1)

8.4% 9.5%

Q2 2009 annualized growth in

gross domestic/metro product

(2)

(2.8)% (1.8)%

Key Economic Indicators

Top 150 Customer Usage by Segment

18%

Health & Educational Services

19%

Manufacturing

21%

Petroleum

Retail Trade

Other

Transportation, Communication

& Utilities

13%

Finance, Insurance & Real

Estate

13%

Pharmaceuticals

(1) Source: Moody's Economy.com (June 2009) and U.S Dept. of Labor (July

2009)

(2) Source: Moody’s Economy.com

(3) Adjusted for leap year impact

(4) Not adjusted for leap year impact

(1)

Represents

approximate

range

expected

gross

margin,

taking

into

account

hedges

place,

between

the

5th

and

95th

percent

confidence

levels.

Approximate

gross

margin

ranges

are

based

upon

internal

simulation

model

and

are

subject

change

based

upon

market

inputs,

future

transactions

and

potential

modeling

changes.

These

ranges

approximate

gross

margin

2010

and

2011

not

represent

earnings

guidance

forecast

future

results

Exelon

has

not

completed

its

planning

optimization

processes

for

those

years.

The

price

distributions

that

generate

this

range

are

calibrated

market

quotes

for

power,

fuel,

load

following

products

and

options

June

30,

2009.

(2)

Percent

expected

generation

hedged

represents

how

many

equivalent

have

been

hedged

forward

market

prices

June

30,

2009;

all

hedge

products

used

are

converted

equivalent

average

volume

and

the

calculation

considers

whether

hedges

are

power

sales

financial

products.

Hedging Update

The primary objective of Exelon’s hedging program is to manage market risks and protect

the value of our generation and our investment-grade balance sheet while preserving our

ability to participate in improving long-term market fundamentals

•

We typically follow a 36-month ratable

hedging program.

•

As we execute our hedging program, our

percent of expected generation hedged

increases and our potential range of

earnings outcomes narrows as we move

closer to the delivery year

2009

2010

2011

Percentage of Expected

Generation Hedged

(2)

95-98%

87-90%

59-62%

Midwest

96-99

87-90

63-66

Mid-Atlantic

95-98

91-94

56-59

South

90-93

68-71

34-37

•

For 2011, we are above our targeted

hedge ratio primarily due to additional

natural gas and power put options within

the portfolio.

•

Put options allow us to reduce market risk

while preserving upside potential

95% case

5% case

$6,700

$6,500

$6,100

$6,700

$6,100

$8,400

$4,000

$5,000

$6,000

$7,000

$8,000

$9,000

$10,000

2009

2010

2011

2009 Operating Earnings Guidance

2009E

2008A

$0.49

$3.46

$4.20

ComEd

PECO

Exelon

Generation

ComEd distribution revenue

PECO gas revenue

O&M and other

Pension/OPEB

Inflation

Cost reduction initiatives

Bad debt expense

Nuclear fuel costs

Depreciation and amortization

PECO CTC

2009 Earnings Drivers

ComEd

PECO

Exelon

Generation

Holdco

Exelon

$0.33

Exelon

$4.00 -

$4.30

(1)

$0.45 -

$0.55

$0.45 -

$0.55

$3.10 -

$3.35

(1)

Adjusted

(non-GAAP)

Operating

Earnings

Guidance.

Excludes

the

earnings

impact

certain

items

disclosed

the

Appendix.

Note:

Actual;

Estimate

Reaffirming

2009

operating

earnings

guidance

$4.00-$4.30/share

(1)

–

expect third quarter 2009 results between $0.90

to $1.00/share

Cost Management

Exelon remains committed to holding 2009 O&M spending flat to 2008, which includes realizing

$150 million of cost savings this year

•

Year-to-date Exelon has realized $68 million of cost savings across the company, or 45% of our 2009

commitment

•

100% of our remaining 2009 commitment has been identified

Exelon

also

announced

spending

cuts

which

will

save

$350

million

2010

from

original

planning

assumptions,

resulting

nearly

3.5%

reduction

total

spending

from

2009

levels

(1)

•

Clearly defining our governance and oversight structure and streamlining corporate functions will result in

the elimination of 400 positions across Exelon. Separately, and continuing its efforts to enhance operating

efficiencies, ComEd will eliminate 100 management level positions

•

Additional

costs

savings

will

achieved

through

changes

the

company’s

compensation

program and

other reductions in spending across each operating company

•

Exelon expects that half of the total O&M savings in 2010, or $175 million, will be sustainable

Exelon is responding to today’s challenging environment by driving productivity and cost

reductions while maintaining superior operations

$4,500

$700

$1,050

$2,750

2009E

$4,350

$4,500

Exelon Consolidated

(3)

$700

$750

PECO

$1,000

$1,100

ComEd

$2,700

Exelon Generation

2010E

2008A

O&M Expense

(2)

(in millions)

(1) Exelon projects a nearly 3.5% decrease in year-over-year O&M spending, from approximately $4.5 billion in 2009 to $4.35 billion in 2010. These reductions represent

over $350 million of O&M savings in 2010, as Exelon anticipated a 4% increase in O&M absent these actions.

(2) Reflects

operating

O&M

data

and

excludes

Decommissioning

impact.

ComEd

and

PECO

operating

O&M

exclude

energy

efficiency

spend

recoverable

under

rider.

(3) Exelon Consolidated includes operating O&M expense from Holding Company.

(4) Reflects ~$175

million increase in operating O&M expense from 2008A to 2009E due to higher pension and OPEB expense.

Note: Information contained on this slide is rounded.

(4)

Appendix

Dollars shown are nominal, reflecting 6% escalation, in millions.

Project plan includes off-ramps to defer or cancel as needed.

MW Recovery and Component Upgrades are the replacement of major components in the plant that occur in the normal life cycle process – with

newer technology, replacements result in increased efficiency. Equipment includes generators, turbines, motors and transformers. MW Recovery

and Component Upgrades must conform to NRC standards, but do not require additional NRC approval.

MUR (Measurement Uncertainty Recapture). Through the use of advanced techniques and more precise instrumentation, reactor power can be

more accurately calculated. These uprates achieve up to 1.7 percent additional output. MUR uprates require NRC approval.

EPU (Extended Power Uprate). Through a combination of more sophisticated analysis and upgrades to plant equipment, uprates can be obtained

for as much as 20 percent of original licensed power level. EPU uprates require NRC approval.

Exelon Nuclear Uprate

Plan

Year Uprates

Become Operational

•

Incremental 1,300 –

1,500 MWs

of nuclear uprates

are safe, economical and proven methods to

improve efficiency and output

•

Exelon has substantial experience managing successful uprate

projects with 1,100 MWs

increased nuclear capacity over the past 10 years

•

Exelon’s $2,200 –

2,500 / kW overnight cost for its uprate

projects is better value than the cost for a

nuclear new build that has been estimated as high as $4,500 / kW

(2007 dollars)

Exelon’s Uprate

Plan

(2)

EPUs

(5)

MURs

(4)

MW Recovery and

Component Upgrades

(3)

Maximum

Potential MWs

200

400

600

800

1000

1200

1400

1600

1999-

2008

2009

2010

2011

2012

2013

2014

2015

2016

2017

2009-

2017

1,100 MWs

1,300 –

1,500 MW

Average Overnight Cost

Estimate: $2,200 -

2,500/KW

Planned Capital

Spend

(1)

($ millions)

$150

2017

$625

2013

$675

2012

$550

2011

$350

2010

$725

2015

$725

2014

$400

2016

$4,425

2008 -

2017

$225

2008 -

2009

Note: Information contained on this slide is rounded.

(1)

(2)

(3)

(5)

(4)

Reliability Pricing Model Auction

PJM RPM Auction ($/MW-day)

(1)

All generation values are approximate and not inclusive of wholesale transactions.

(2)

All capacity values are in installed capacity terms (summer ratings) located in the areas.

(3)

EMAAC and MAAC obligation consists of load obligations from PECO. PECO PPA

expires December 2010.

(4)

RTO obligation represents the remainder of the ComEd auction load that ends in May 2010.

(5)

MAAC = Mid-Atlantic Area Council; APS = Allegheny Power System.

Exelon Generation Participation within PJM Reliability Pricing Model

(1)

2009/2010

2010/2011

2011/2012

2012/2013

in MW

Capacity

(2)

Obligation

Capacity

(2)

Obligation

Capacity

(2)

Capacity

(2)

RTO

12,800

3,800 -

4,100

(4)

12,800

23,200

12,100

EMAAC

9,800

9,300 -

9,400

(3)

9,500

MAAC + APS

1,500

MAAC

11,100

9,300 -

9,400

(3)

1,500

40.80

197.67

148.80

111.92

191.32

102.04

174.29

110.00

133.37

139.73

16.46

RTO

Eastern MAAC

MAAC + APS

MAAC

2007/2008

2008/2009

2009/2010

2010/2011

2011/2012

2012-2013

(5)

Note: Information contained on this slide is rounded.

Illinois Power Agency RFP Procurement

•

On May 1, 2009, the Illinois Commerce Commission approved the bids from the RFP

Procurement held on April 29, 2009, for the remaining ComEd 2009-2010 load (~29% of the

total) and a portion of its 2010-2011 load (~8% of the total)

–

Contracts were awarded to 10 successful bidders

–

$33.23 average ATC price for 2009-2010 planning year, in addition to:

•

Financial

Swap

price

(ATC

baseload

energy

only)

$49.04

for

June

2009

–

December

2009

and

$50.15

for

January 2010 –

May 2010,

•

Auction clearing price of $63.33

(1)

(fixed price contract, which includes energy, ancillary, load shape, etc.)

NOTE: Chart is for illustrative purposes only. Information on this slide is rounded

Jun

2007

Jun

2008

Jun

2009

Jun

2010

Jun

2011

Jun

2012

Jun

2013

Future Procurement by

Illinois Power Agency

Auction

Contracts

Financial

Swap

4/09

RFP

2010

2011

2012

2011

Volumes secured in 2009 IPA

Procurement Event (GWh)

Off-Peak

Peak

Contract Period

2,461

7,673

983

June 2010 –

May 2011

5,712

June 2009 –

May 2010

The procurement event included monthly peak and

off-peak standard wholesale block energy products

(in 50 MW blocks) to be delivered to NiHub

4/09

RFP

3/08

RFP

Next RFP to be held in Spring 2010

(1)

CPP

-41-Month

Auction

Product

for

period

Jan.

2007

–

May

31,

2010.

PECO Procurement Results

With a successful residential procurement in June, PECO has made

progress toward

purchasing the power needed to serve customers beginning in 2011

On June 17, 2009, the PAPUC approved the bids from the RFP held on June 15, 2009, which

included

21%

PECO’s

residential

default

service

load

for

2011

and

portion

its

load

obligation for 2012 and 2013

Contracts were awarded to two bidders out of eleven total bidders

RFP

for

full

requirements

(1)

resulted

average

wholesale

price

$88.61($/MWh)

Based on the results of its initial RFP, PECO estimates the average residential bill would increase by 9%

beginning Jan.1, 2011

(1) Full requirements product includes load following energy, capacity, ancillary transmission services and Alternative Energy Portfolio Standard requirements.

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

Residential

23% of planned full requirements

contracts (17 and 29-mo terms)

40MW of baseload (24x7) energy

block products (12-mo duration)

Small Commercial

24% of planned full requirements

contracts (17-mo term)

Medium Commercial & Industrial

16% of planned full requirements

contracts (17-mo term)

85% full requirements

15% full requirements spot

Medium Commercial &

Industrial

(peak demand >100 kW

but <= 500 kW)

100% full requirements spot

Large Commercial &

Industrial

(peak demand >500 kW)

90% full requirements

10% full requirements spot

75% full requirements

20% energy block

5% energy only spot

Products

Small Commercial

(peak demand <100 kW)

Residential

Customer Class

Residential

26% of planned full requirements

contracts

•

17 month (Jan 2011 –

May 2012)

•

29 month (Jan 2011-

May 2013)

40MW of baseload (24x7) energy

block products

•

12 month (Jan 2011-

Dec 2011)

PECO

Procurement

Plan

(2)

Fall 2009 RFP

Spring 2009 RFP

5.03

0.51

6.26

2.57

10.13

PECO Average Residential Electric Rates

(1)

Average of PECO’s residential rates

(2)

Provided for illustration only. Only represents 21% of PECO’s residential procurement for 2011.

(3)

Average wholesale price for full requirements products.

2011

2010

Energy / Capacity

Competitive Transition

Charge (CTC)

Transmission

Distribution

14.37¢

(1)

Unit Rates (¢/kWh)

Electric Restructuring

Settlement

~9%

15.67¢

Assumptions

Illustrative Rate Increase Based on

Average PECO Residential Full-

Requirements Procurement Results

(2)

•

2011 illustrative residential rate based on

Spring 2009 RFP full requirements

product prices

•

2011 default service residential rate will

reflect associated full requirements costs,

block energy costs, and spot market

purchases, all of which will be acquired

through multiple procurements

•

Rates will vary by customer class

•

Retail rate components include line losses

and gross receipts taxes

Residential

Spring 2009

$88.61 / MWH

PECO Procurement Results

(3)

Impact of Spring 2009 Procurement

$20

$40

$60

$80

$100

$120

PA Gross Receipts Tax (5.90%)

Distribution Losses (7.35%)

Full Requirements Cost

PJM Whub ATC Forward Energy Price

Average PECO Full Requirements

Residential Price

$101.30/MWh

(2)

$31.00 -

$32.00

$56.00 -

$57.00

Full Requirements Costs ($/MWh)

Average Full-Requirements

Retail

Sales

Price

(1)

Load Shape &

Ancillary Services

$9.00

Capacity

$12.00

Transmission &

Congestion

$8.00 -

$9.00

Renewable

Energy

Credits

$1.00

Migration &

Volumetric

Risk & Other

$1.00

~$7.00

~$6.00

(1) Term of sale is January 1, 2011 to May 31, 2013.

(2)

June

17,

2009

Generation

disclosed

estimated

retail

price

$100-102/MWh.

July

15,

2009

PECO

disclosed

average

full-requirements

retail

sales

price

$101.30/MWh

for

its Spring 2009 RFP (i.e., inclusive of Pennsylvania Gross Receipts Tax and adjustment for PECO distribution losses, but not Network Transmission Service).

(3) On July 15, 2009 the Independent Evaluator (NERA) announced an average wholesale winning bid price of $88.61/MWh for PECO’s Spring 2009 RFP (reflecting residential full-

requirements products only with delivery beginning January 1, 2011).

(1) Term of sale is January 1, 2011 to May 31, 2013.

(2)

June

17,

2009

Generation

disclosed

estimated

retail

price

$100-102/MWh.

July

15,

2009

PECO

disclosed

average

full-requirements

retail

sales

price

$101.30/MWh

for

its Spring 2009 RFP (i.e., inclusive of Pennsylvania Gross Receipts Tax and adjustment for PECO distribution losses, but not Network Transmission Service).

(3) On July 15, 2009 the Independent Evaluator (NERA) announced an average wholesale winning bid price of $88.61/MWh for PECO’s Spring 2009 RFP (reflecting residential full-

requirements products only with delivery beginning January 1, 2011).

Average

Wholesale

Energy Price

(3)

$88.61

Q2 07

Q2 08

Q2 09

ComEd and PECO Accounts Receivable

>60 days

31-60 days

0-30 days

ComEd Accounts

Receivable

(1)

Through the second quarter of 2009, ComEd has experienced only slight deterioration in

its accounts receivable aging; PECO has experienced some improvement

% of AR

Q2 07

Q2 08

Q2 09

PECO Accounts

Receivable

(1)

% of AR

$781M

$768M

$755M

$761M

$827M

$740M

(1) Accounts receivable amounts include unbilled receivables and are gross of allowance for uncollectible accounts at ComEd and PECO and long-term receivables at PECO.

>60 days

31-60 days

0-30 days

Note: Information contained on this slide is rounded.

2009 Projected Sources and Uses of Cash

5,450

3,300

950

1,200

Cash Flow from Operations

(1)

(100)

250

(50)

Other

(600)

(250)

(50)

Net Financing (excluding Dividend):

(2)

250

Planned Debt Issuances

(3)(4)

Net Financing (excluding Dividend):

(2)

(750)

Planned Debt Retirements

(5)

$500

$400

$50

Beginning Cash Balance

(3,400)

(2,050)

(400)

(875)

Capital Expenditures

$1,950

$1,650

$350

$325

Cash Available before Dividend

(1,400)

Dividend

(6)

$550

Cash Available after Dividend

Exelon

(7)

($ in Millions)

(1)

Cash

Flow

from

Operations

primarily

includes

net

cash

flows

provided

operating

activities

(excluding

counterparty

collateral

activity)

and

net

cash

flows

used

investing

activities

other

than

capital

expenditures.

PECO

Cash

Flow

from

Operations

includes

$500M

for

Competitive

Transition

Charges.

(2)

Net

Financing

(excluding

Dividend)

Net

cash

flows

used

financing

activities

excluding

dividends

paid

common

and

preferred

stock.

(3)

Excludes

Exelon

Generation

and

ComEd

tax-exempt

bonds

that

are

backed

letters

credit

(LOCs).

ComEd

reissued

$191M

tax

exempt

debt

May

backed

LOCs.

Generation

plans

remarket

their

bonds

into

different

interest

rate

mode

and

refinance

with

new

tax-exempt

bonds,

both

not

expected

utilize

credit

enhancement

(4)

Excludes

PECO’s

Accounts

Receivable

Agreement

with

Bank

Tokyo.

Assumes

PECO’s

A/R

Agreement

extended

accordance

with

its

terms

beyond

September

18,

2009.

(5)

Planned

Debt

Retirements

are

$17M,

$721M,

and

$12M

for

ComEd,

PECO,

and

ExGen,

respectively.

Includes

securitized

debt.

(6)

Assumes

2009

Dividend

$2.10

per

share.

Dividends

are

subject

declaration

the

board

directors.

(7)

Includes

cash

flow

activity

from

Holding

Company,

eliminations,

and

other

corporate

entities.

Note: Information contained on this slide is rounded.

Sufficient Liquidity

(1) Excludes previous commitment from Lehman Brothers Bank.

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

(0)

Outstanding Facility Draws

(513)

(160)

(10)

(337)

Outstanding Letters of Credit

$7,317

$4,834

$574

$952

Aggregate Bank Commitments

(1)

6,804

4,674

564

615

Available

Capacity

Under

Facilities

(2)

(0)

Outstanding Commercial Paper

$6,804

$4,674

$564

$615

Available Capacity Less Outstanding

Commercial Paper

Exelon

(3)

($ in Millions)

Exelon has no commercial paper outstanding and its bank facilities are largely untapped

Available Capacity Under Bank Facilities as of July 17, 2009

Notes: Exelon and PECO metrics exclude securitization debt. See following slide for FFO (Funds from Operations)/Interest, FFO/Debt and Adjusted Book Debt Ratio reconciliations to

GAAP.

(1)

Reflects S&P updated guidelines, which include imputed debt and interest related to purchased power agreements (PPA), unfunded pension and other postretirement benefits

(OPEB) obligations, capital adequacy for energy trading, operating lease obligations, and other off-balance sheet debt. Debt is imputed for estimated pension and OPEB

obligations by operating company.

(2)

Excludes items listed in note (1) above.

(3)

Current senior unsecured ratings for Exelon and Exelon Generation and senior secured ratings for ComEd and PECO as of July 23, 2009. On July 21, 2009,

following the termination of Exelon’s offer to acquire NRG, Fitch removed Exelon and Exelon Generation from Rating Watch Negative and assigned their rating’s

outlook as stable. On July 22, 2009, S&P removed Exelon, ComEd, PECO and Exelon Generation rating’s outlook from CreditWatch with negative implications to

stable for all entities. On July 23, 2009, Moody’s confirmed the ratings of Exelon and Exelon Generation and assigned their rating outlook as stable. Moody’s also confirmed

PECO’s long-term debt rating but changed the outlook to negative.

Projected 2009 Key Credit Measures

BBB

A-

BBB-

S&P Credit

Ratings

(3)

BBB+

BBB

BBB+

Fitch Credit

Ratings

(3)

Baa2

Baa1

Moody’s Credit

Ratings

(3)

4.3x

FFO / Interest

ComEd:

21%

16%

FFO / Debt

42%

49%

Rating Agency Debt Ratio

3.4x

3.3x

FFO / Interest

PECO:

15%

12%

FFO / Debt

48%

53%

Rating Agency Debt Ratio

25%

47%

Rating Agency Debt Ratio

128%

51%

FFO / Debt

31.2x

11.2x

FFO / Interest

Exelon

Generation:

50%

36%

7.4x

Without PPA &

Pension / OPEB

(2)

61%

Rating Agency Debt Ratio

25%

FFO / Debt

6.0x

FFO / Interest

Exelon

Consolidated:

With PPA & Pension /

OPEB

(1)

FFO Calculation and Ratios

FFO

Calculation

= FFO

PECO Transition Bond Principal Paydown

Gain

Sale,

Extraordinary

Items

and

Other

Non-Cash

Items

(3)

+ Change in Deferred Taxes

Depreciation,

amortization

(including

nucl

fuel

amortization),

AFUDC/Cap.

Interest

Add back non-cash items:

Net Income

Adjusted Interest

FFO + Adjusted Interest

= Adjusted Interest

+ 7% of Present Value (PV) of Operating Leases

+ Interest on imputed debt related to PV of Purchased Power Agreements

(PPA), unfunded Pension and Other Postretirement Benefits (OPEB)

obligations,

and

Capital

Adequacy

for

Energy

Trading

(2)

applicable

PECO Transition Bond Interest Expense

Net Interest Expense (Before AFUDC & Cap. Interest)

FFO Interest Coverage

Capital

Adequacy

for

Energy

Trading

(2)

FFO

= Adjusted Debt

+ PV of Operating Leases

100%

Purchased

Power

Agreements

(2)

Unfunded

Pension

and

OPEB

obligations

(2)

+ A/R Financing

Add off-balance sheet debt equivalents:

PECO Transition Bond Principal Balance

+ STD

+ LTD

Debt:

Adjusted

Debt

(1)

FFO

Debt

Coverage

Rating Agency Capitalization

Rating Agency Debt

Total Adjusted Capitalization

Adjusted Book Debt

= Total Rating Agency Capitalization

Off-balance

sheet

debt

equivalents

(2)

Total Adjusted Capitalization

= Rating Agency Debt

Off-balance

sheet

debt

equivalents

(2)

Adjusted Book Debt

= Total Adjusted Capitalization

+ Adjusted Book Debt

+ Preferred Securities of Subsidiaries

+ Total Shareholders' Equity

Capitalization:

= Adjusted Book Debt

Transition Bond Principal Balance

+ STD

+ LTD

Debt:

Debt to Total Cap

Note: Reflects S&P guidelines and company forecast. FFO and Debt related to non-recourse debt are excluded from the calculations.

(1)

Uses current year-end adjusted debt balance.

(2)

Includes debt equivalents for A/R Financings, operating lease obligations, imputed debt related to PV of PPAs, underfunded Pension and OPEB obligations, and Capital

Adequacy for Energy Trading.

(3)

Reflects depreciation adjustment for PPAs and decommissioning interest income and contributions.

Q2 GAAP EPS Reconciliation

NOTE: All amounts shown are per Exelon share and represent contributions to Exelon's EPS.

(0.04)

(0.02)

2009 severance charges

0.10

Unrealized gains related to nuclear decommissioning trust funds

(0.01)

NRG acquisition costs

(0.03)

2007 Illinois electric rate settlement

(0.16)

Mark-to-market adjustments from economic hedging activities

0.10

(0.02)

0.06

Non-cash remeasurement of income tax uncertainties and reassessment

of state deferred income taxes

$0.99

$(0.06)

$0.11

$0.17

$0.77

Q2 2009 GAAP Earnings (Loss) Per Share

$1.03

$(0.03)

$0.11

$0.13

$0.82

2009 Adjusted (non-GAAP) Operating Earnings (Loss) Per Share

Exelon

Other

PECO

ComEd

ExGen

Three Months Ended June 30, 2009

$1.13

$0.09

$0.05

$0.99

Q2 2008 GAAP Earnings Per Share

$1.13

$(0.02)

$0.09

$0.05

$1.01

2008 Adjusted (non-GAAP) Operating Earnings (Loss) Per Share

(0.07)

2007 Illinois Electric Rate Settlement

0.09

0.02

0.07

Mark-to-market adjustments from economic hedging activities

(0.02)

Unrealized losses related to nuclear decommissioning trust funds

Exelon

Other

PECO

ComEd

ExGen

Three Months Ended June 30, 2008

YTD GAAP EPS Reconciliation

NOTE: All amounts shown are per Exelon share and represent contributions to Exelon's EPS.

$2.01

$0.01

$0.23

$0.12

$1.65

YTD 2008 GAAP Earnings Per Share

2.06

$(0.03)

$0.23

$0.12

$1.74

2008 Adjusted (non-GAAP) Operating Earnings (Loss) Per Share

(0.14)

2007 Illinois Electric Rate Settlement

0.17

0.04

0.13

Mark-to-market adjustments from economic hedging activities

(0.08)

Unrealized losses related to nuclear decommissioning trust funds

Exelon

Other

PECO

ComEd

ExGen

Six Months Ended June 30, 2008

(0.20)

Impairment of certain generating assets

(0.04)

(0.02)

2009 severance charges

0.05

Unrealized gains related to nuclear decommissioning trust funds

(0.03)

NRG acquisition costs

(0.06)

2007 Illinois electric rate settlement

0.01

Mark-to-market adjustments from economic hedging activities

0.10

(0.02)

0.06

Non-cash remeasurement of income tax uncertainties and reassessment of

state deferred income taxes

$2.07

$(0.14)

$0.28

$0.35

$1.58

YTD 2009 GAAP Earnings (Loss) Per Share

$2.24

$(0.09)

$0.28

$0.31

$1.74

2009 Adjusted (non-GAAP) Operating Earnings (Loss) Per Share

Exelon

Other

PECO

ComEd

ExGen

Six Months Ended June 30, 2009

2009 Earnings Outlook

•

Exelon’s 2009 adjusted (non-GAAP) operating earnings

outlook excludes the earnings impacts of the following:

•

Mark-to-market adjustments from economic hedging activities

•

Unrealized gains and losses from nuclear decommissioning trust fund investments

primarily related to the Clinton, Oyster Creek, and Three Mile Island nuclear plants (the

former AmerGen Energy Company, LLC units)

•

Any significant impairments of assets, including goodwill

•

Any changes in decommissioning obligation estimates

•

Costs

associated

with

the

2007

Illinois

electric

rate

settlement

agreement,

including

ComEd’s previously announced customer rate relief programs

•

Costs associated with ComEd’s 2007 settlement with the City of Chicago

•

Costs incurred for employee severance related to the cost reduction program announced in

June 2009

•

Certain costs associated with the proposed offer to acquire NRG Energy, Inc.

•

Non-cash remeasurement of income tax uncertainties and reassessment of state deferred

income taxes

•

Other unusual items

•

Significant future changes to GAAP

•

Operating earnings guidance assumes normal weather for the remainder

of the year

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

the

following

slides

not

intended

represent

earnings

guidance

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, 2009. Exelon plans to update these

hedging disclosures on a quarterly basis.

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

incorporates assumptions regarding future market conditions, including power and commodity

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

characteristics of our generating fleet. Our simulation model and the assumptions therein are

subject to change. For example, actual market conditions and the dispatch profile of our

generation

fleet

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

the

following

slides

will

likely

change

over

time

due

continued refinement of our simulation model and changes in our views on future market

conditions.

Portfolio Management Objective

Align Hedging Activities with Financial Commitments

•

Power Team utilizes several product

types and channels to market

•

Wholesale and retail sales

•

Block products

•

Load-following products

and load auctions

•

Put/call options

•

Exelon’s hedging program is designed to

protect the long-term value of our

generating fleet and maintain an

investment-grade balance sheet

•

Hedge enough commodity risk to meet future cash

requirements if prices drop

•

Consider: financing policy (credit rating objectives,

capital structure, liquidity); spending (capital and

O&M); shareholder value return policy

•

Consider market, credit, operational risk

•

Approach to managing volatility

•

Increase hedging as delivery approaches

•

Have enough supply to meet peak load

•

Purchase fossil fuels as power is sold

•

Choose hedging products based on generation

portfolio –

sell what we own

•

Heat rate options

•

Fuel products

•

Capacity

•

Renewable credits

By design, our hedging program allows us to weather short-term, adverse market conditions

while positioning us to participate in long-term upside potential

% Hedged

High End of Profit

Low End of Profit

Open Generation

with LT Contracts

Portfolio

Optimization

Portfolio

Management

Portfolio Management Over Time

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

•

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

2009

2010

2011

Estimated

Open

Gross

Margin

(millions)

(1,2)

$5,100

$6,000

$6,150

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)

$4.26

$29.42

$40.30

($0.09)

$6.06

$33.38

$48.64

($2.17)

$6.89

$35.12

$52.21

($0.77)

(1)

Based on June 30, 2009 market conditions.

(2)

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

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

assumes

there

hedging

place

other

than

fixed

assumptions

for

capacity

cleared

the

RPM

auctions

and

uranium

costs

for

nuclear

power

plants.

Open

gross

margin

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

incorporates

management

discretion

and

modeling

assumptions

that

are

subject

change.

(3)

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

Exelon Generation Open Gross Margin and

Reference Prices

(1)

Expected

generation

represents

the

amount

energy

estimated

generated

purchased

through

owned

contracted

for

capacity.

Expected

generation

based

upon

simulated

dispatch

model

that

makes

assumptions

regarding

future

market

conditions,

which

are

calibrated

market

quotes

for

power,

fuel,

load

following

products,

and

options.

Expected generation assumes 10 refueling outages in 2009 and 2010 and 11 refueling outages in 2011 at Exelon-operated nuclear plants and Salem. Expected generation assumes

capacity factors of 93.6%, 92.8% and 92.8% in 2009, 2010 and 2011 at Exelon-operated nuclear plants. These estimates of expected generation in 2010 and 2011 do not represent

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

(2)

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

power, options, and swaps. Uses expected value on options.

(3)

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

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

revenue,

but

includes

the

mark-to-market

value

capacity

contracted

prices

other

than

RPM

clearing

prices

including

our

load

obligations.

can

compared

with

the

reference

prices

used

calculate

open

gross

margin

order

determine

the

mark-to-market

value

Exelon

Generation's

energy

hedges.

2009

2010

2011

Expected Generation

(GWh)

(1)

169,800

165,500

164,700

Midwest

99,600

97,700

Mid-Atlantic

57,500

58,500

58,100

South

12,700

9,300

8,900

Percentage of Expected Generation Hedged

(2)

95-98%

87-90%

59-62%

Midwest

96-99

87-90

63-66

Mid-Atlantic

95-98

91-94

56-59

South

90-93

68-71

34-37

Effective Realized Energy Price

($/MWh)

(3)

Midwest

$47.00

$46.75

$45.00

Mid-Atlantic

$36.25

$34.50

$62.00

ERCOT North ATC Spark Spread

$5.25

$3.50

$4.75

Generation Profile

Gross

Margin

Sensitivities

with

Existing

Hedges

(millions)

(1)

Henry Hub Natural Gas

+ $1/MMBtu

$1/MMBtu

NI-Hub ATC Energy Price

+$5/MWH

-$5/MWH

PJM-W ATC Energy Price

+$5/MWH

-$5/MWH

Nuclear Capacity Factor

+1% / -1%

2009

($3)

($2)

+/-$20

2010

$40

($30)

$55

($50)

$25

($20)

+/-$50

2011

$280

($240)

$205

($195)

$170

($165)

+/-$55

(1)

Based on June 30, 2009 market conditions and hedged position. Gas price sensitivities are based on an assumed gas-power relationship derived from an internal

model

that

updated

periodically.

Power

prices

sensitivities

are

derived

adjusting

the

power

price

assumption

while

keeping

all

other

prices

inputs

constant.

Due

correlation

the

various

assumptions,

the

hedged

gross

margin

impact

calculated

aggregating

individual

sensitivities

may

not

equal

the

hedged

gross

margin

impact

calculated

when

correlations

between

the

various

assumptions

are

also

considered.

Exelon Generation Gross Margin Sensitivities

(with Existing Hedges)

Exelon Generation Gross Margin Upside / Risk

(with Existing Hedges)

(1)

Represents

approximate

range

expected

gross

margin,

taking

into

account

hedges

place,

between

the

5th

and

95th

percent

confidence

levels.

Approximate

gross

margin

ranges are based upon an internal simulation model and are subject to change based upon market inputs, future transactions and potential modeling changes. These ranges of

approximate gross margin in 2010 and 2011 do not represent earnings guidance or a forecast of future results as Exelon has not completed its planning or optimization processes

for

those

years.

The

price

distributions

that

generate

this

range

are

calibrated

market

quotes

for

power,

fuel,

load

following

products,

and

options

June

30,

2009.

95% case

5% case

$6,700

$6,500

$6,100

$6,700

$6,100

$8,400

$5,000

$6,000

$7,000

$8,000

$9,000

$10,000

2009

2010

2011

Midwest

Mid-Atlantic

ERCOT

Step 1

Start

with

fleetwide

open

gross

margin

$5.10 billion

Step 2

Determine the mark-to-market value

of energy hedges

99,600GWh * 97% *

($47.00/MWh-$29.42/MWh)

= $1.70 billion

57,500GWh * 96% *

($36.25/MWh-$40.30/MWh)

= ($0.22 billion)

12,700GWh * 91% *

($5.25/MWh-($0.09)/MWh)

= $0.06 billion

Step 3

Estimate

hedged

gross

margin

adding open gross margin to mark-to-

market value of energy hedges

Open gross margin: $5.10 billion

MTM value of energy hedges: $1.70

billion

($0.22

billion)

$0.06

billion

Estimated hedged gross margin: $6.64 billion

Illustrative Example

of Modeling Exelon Generation 2009 Gross Margin

(with Existing Hedges)

100

110

120

130

140

150

7/08

8/08

9/08

10/08

11/08

12/08

1/09

2/09

3/09

4/09

5/09

6/09

7/09

7/08

8/08

9/08

10/08

11/08

12/08

1/09

2/09

3/09

4/09

5/09

6/09

7/09

105

7/08

8/08

9/08

10/08

11/08

12/08

1/09

2/09

3/09

4/09

5/09

6/09

7/09

5.5

6.5

7.5

8.5

9.5

10.5

11.5

7/08

8/08

9/08

10/08

11/08

12/08

1/09

2/09

3/09

4/09

5/09

6/09

7/09

Market Price Snapshot

Forward NYMEX Natural Gas

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

PJM-West and Ni-Hub Wrap Forward Prices

2010

2011

Rolling 12 months, as of July 17, 2009. Source: OTC quotes and electronic trading system. Quotes are daily.

Forward NYMEX Coal

$5.81

$6.59

2010

2011

$54.96

$65.90

2010 Ni-Hub

2011 Ni-Hub

2011 PJM-West

2010 PJM-West

2010 Ni-Hub

2011 Ni-Hub

2011 PJM-West

2010 PJM-West

$53.90

$59.30

$40.45

$24.48

$39.48

$22.81

$42.75

$37.43

4.5

5.5

6.5

7.5

8.5

9.5

10.5

11.5

12.5

13.5

14.5

7/08

8/08

9/08

10/08

11/08

12/08

1/09

2/09

3/09

4/09

5/09

6/09

7/09

8.2

8.4

8.6

8.8

9.2

9.4

9.6

9.8

7/08

8/08

9/08

10/08

11/08

12/08

1/09

2/09

3/09

4/09

5/09

6/09

7/09

6/08

7/08

8/08

9/08

10/08

11/08

12/08

1/09

2/09

3/09

4/09

5/09

6/09

7/09

7/08

8/08

9/08

10/08

11/08

12/08

1/09

2/09

3/09

4/09

5/09

6/09

7/09

Market Price Snapshot

2011

2010

2011

2010

2011

Houston Ship Channel Natural Gas

Forward Prices

ERCOT North On-Peak Forward Prices

ERCOT North On-Peak v. Houston Ship Channel

Implied Heat Rate

2010

2011

ERCOT North On Peak Spark Spread

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

$5.54

$6.34

$55.31

$47.77

$8.62

$8.73

$5.28

$7.10

Rolling 12 months, as of July 17, 2009. Source: OTC quotes and electronic trading system. Quotes are daily.