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

October 23, 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 (a Pennsylvania corporation) 10 South Dearborn Street P.O. Box 805379 Chicago, Illinois 60680-5379 (312) 394-7398	23-2990190
333-85496	EXELON GENERATION COMPANY, LLC (a Pennsylvania limited liability company) 300 Exelon Way Kennett Square, Pennsylvania 19348-2473 (610) 765-5959	23-3064219
1-1839	COMMONWEALTH EDISON COMPANY (an Illinois corporation) 440 South LaSalle Street Chicago, Illinois 60605-1028 (312) 394-4321	36-0938600
000-16844	PECO ENERGY COMPANY (a Pennsylvania corporation) P.O. Box 8699 2301 Market Street Philadelphia, Pennsylvania 19101-8699 (215) 841-4000	23-0970240

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

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

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

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

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

Section 2 – Financial Information

Item 2.02. Results of Operations and Financial Condition.

Section 7 – Regulation FD

Item 7.01. Regulation FD Disclosure.

On October 23, 2009, Exelon Corporation (Exelon) announced via press release Exelon’s results for the third quarter ended September 30, 2009. A copy of the press release and related attachments is attached hereto as Exhibit 99.1. Also attached as Exhibit 99.2 to this Current Report on Form 8-K are the presentation slides to be used at the third quarter 2009 earnings conference call. This Form 8-K and the attached exhibits are provided under Items 2.02, 7.01 and 9.01 of Form 8-K and are furnished to, but not filed with, the Securities and Exchange Commission.

Section 9 – Financial Statements and Exhibits

Item 9.01. Financial Statements and Exhibits.

(d) Exhibits.

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

* * * * *

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

This Current Report includes forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995 that are subject to risks and uncertainties. The factors that could cause actual results to differ materially from these forward-looking statements include those discussed herein as well as those discussed in (1) Exelon’s 2008 Annual Report on Form 10-K in (a) ITEM 1A. Risk Factors, (b) ITEM 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations and (c) ITEM 8. Financial Statements and Supplementary Data: Note 18; (2) Exelon’s Third Quarter 2009 Quarterly Report on Form 10-Q (to be filed on October 23, 2009) in (a) Part II, Other Information, ITEM 1A. Risk Factors and (b) Part I, Financial Information, ITEM 1. Financial Statements: Note 14; and (3) other factors discussed in filings with the Securities and Exchange Commission by the Registrants. Readers are cautioned not to place undue reliance on these forward-looking statements, which apply only as of the date of this Current Report. None of the Registrants undertakes any obligation to publicly release any revision to its forward-looking statements to reflect events or circumstances after the date of this Current Report.

SIGNATURES

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

EXELON CORPORATION

EXELON GENERATION COMPANY, LLC

/s/ Matthew F. Hilzinger

Matthew F. Hilzinger

Senior Vice President and Chief Financial Officer

Exelon Corporation

COMMONWEALTH EDISON COMPANY

/s/ Joseph R. Trpik, Jr.

Joseph R. Trpik, Jr.

Senior Vice President, Chief Financial Officer and Treasurer

Commonwealth Edison Company

PECO ENERGY COMPANY

/s/ Phillip S. Barnett

Phillip S. Barnett

Senior Vice President and Chief Financial Officer

PECO Energy Company

October 23, 2009

EXHIBIT INDEX

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

EX-99.1

EXHIBIT 99.1

Contact:	Karie Anderson	FOR IMMEDIATE RELEASE
	Investor Relations
	312-394-4255
	Kathleen Cantillon
	Corporate Communications
	312-394-7417

Exelon Announces Third Quarter Results;

Narrows Full Year 2009 Earnings Guidance

CHICAGO (October 23, 2009) – Exelon Corporation (NYSE: EXC) today announced that its third quarter 2009 consolidated earnings prepared in accordance with GAAP were $757 million, or $1.14 per diluted share, compared with earnings of $700 million, or $1.06 per diluted share, in the third quarter of 2008.

Exelon’s adjusted (non-GAAP) operating earnings for the third quarter of 2009 were $633 million, or $0.96 per diluted share, compared with $706 million, or $1.07 per diluted share, for the same period in 2008.

“We are achieving our financial commitments despite difficult weather, economic and market conditions,” said John W. Rowe, Exelon’s chairman and CEO. “We continue to deliver cost savings and solid operations as shown by a 94.7 percent nuclear capacity factor for the third quarter and reliable utility performance through the critical summer months. We remain committed to achieving full year 2009 operating earnings within the guidance range we issued last fall and are narrowing that range to $4.00 to $4.10 per share.”

The decrease in third quarter 2009 adjusted (non-GAAP) operating earnings to $0.96 per share from $1.07 per share in third quarter 2008 was primarily due to:

• Lower energy gross margins at Exelon Generation Company, LLC (Generation) largely due to unfavorable portfolio and market conditions;

• Higher costs at Generation associated with a higher number of scheduled nuclear refueling outage days;

• Reversal of benefits recorded in the first quarter of 2009 related to an Illinois investment tax credit ruling;

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

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

Lower third quarter 2009 earnings were partially offset by:

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

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

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

• Unrealized gains of $87 million, or $0.13 per diluted share, related to nuclear decommissioning trust (NDT) fund investments;

• Mark-to-market gains of $77 million, or $0.12 per diluted share, primarily from Generation’s economic hedging activities;

• Costs totaling $58 million, or $0.09 per diluted share, associated with early debt retirements;

• Income of $32 million, or $0.05 per diluted share, resulting from the reduction in Generation’s decommissioning obligations;

• Costs of $11 million, or $0.02 per diluted share, associated with the 2007 Illinois electric rate settlement agreement;

• External costs of $6 million, or $0.01 per diluted share, related to Exelon’s terminated offer to acquire NRG Energy, Inc. (NRG); and

• Income of $3 million for the true-up of severance costs as a result of headcount reductions associated with Exelon’s cost management program.

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

• Mark-to-market gains of $65 million, or $0.10 per diluted share, primarily from Generation’s economic hedging activities;

• Costs of $26 million, or $0.04 per diluted share, associated with the 2007 Illinois electric rate settlement agreement;

• Unrealized losses of $60 million, or $0.09 per diluted share, related to NDT fund investments; and

• Income of $15 million, or $0.02 per diluted share, resulting from the reduction in Generation’s decommissioning obligations.

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2009 Earnings Outlook

Exelon narrowed its guidance range for 2009 adjusted (non-GAAP) operating earnings to $4.00 to $4.10 per share from $4.00 to $4.30 per share. Operating earnings guidance is based on the assumption of normal weather for the remainder of the year.

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

• Mark-to-market adjustments from economic hedging activities

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

• Significant impairments of assets, including goodwill

• Changes in decommissioning obligation estimates

• Costs associated with the 2007 Illinois electric rate settlement agreement

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

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

• Costs associated with early debt retirements

• External costs associated with the terminated offer to acquire NRG

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

• Other unusual items

• Significant future changes to GAAP

Third Quarter and Recent Highlights

• Nuclear Operations: Generation’s nuclear fleet, including its owned output from the Salem Generating Station, produced 35,684 gigawatt-hours (GWh) in the third quarter of 2009, compared with 36,451 GWh in the third quarter of 2008. The Exelon-operated nuclear plants achieved a 94.7 percent capacity factor for the third quarter of 2009 compared with 97.2 percent for the third quarter of 2008. The Exelon-operated nuclear plants began two scheduled refueling outages in the third quarter of 2009, compared with beginning one scheduled refueling outage in the third quarter of 2008. The number of refueling outage days totaled 36 and 17, respectively, in the third quarter of 2009 and 2008. Also contributing to lower total nuclear output was a higher number of non-refueling outage days at the Exelon-operated plants, which totaled 21 days in the third quarter of 2009, compared to 8 days in the third quarter of 2008.

• Fossil and Hydro Operations: Generation’s fossil fleet commercial availability was 87.0 percent in the third quarter of 2009, compared with 95.1 percent in the third quarter of 2008, primarily reflecting the impact of extended maintenance outages in 2009. The equivalent availability factor for the hydroelectric facilities was 97.1 percent in the third quarter of 2009, compared with 90.9 percent in the third quarter of 2008, primarily due to an extended planned outage in 2008 to overhaul one of the Conowingo units.

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• Three Mile Island (TMI) Unit 1 Nuclear Plant License Extension: On October 22, 2009, the Nuclear Regulatory Commission approved a 20-year operating license extension until April 19, 2034 for the TMI Unit 1 Generating Station. TMI Unit 1 began operating in 1974.

• Hedging Update: Exelon’s hedging program involves the hedging of commodity risk for Exelon’s expected generation, typically on a ratable basis over a three-year period. Expected generation represents the amount of energy estimated to be generated or purchased through owned or contracted-for capacity. The proportion of expected generation hedged as of September 30, 2009 is 98-100 percent for 2009, 88-91 percent for 2010 and 63-66 percent for 2011. The primary objective of Exelon’s hedging program is to manage market risks and protect the value of its generation and its investment grade balance sheet while preserving its ability to participate in improving long-term market fundamentals.

• ComEd Smart Meter/Smart Grid Plan: On June 1, 2009, ComEd filed a petition with the Illinois Commerce Commission (ICC) recommending a one-year Advanced Metering Infrastructure (AMI) pilot program. Current plans call for the deployment of approximately 131,000 smart meters in 10 suburban communities and in the City of Chicago, and will include tests of customers’ responses to alternative pricing plans, in-home displays and Home Area Network control systems. ComEd requested recovery of and a return on its investment through a rider beginning in 2010. On October 14, 2009, the ICC approved ComEd’s AMI pilot program and rider with minor modifications.

On August 4, 2009, ComEd announced it filed an application with the U.S. Department of Energy (DOE) for $175 million in matching funds made available under the American Recovery and Reinvestment Act of 2009. The matching funds would enable an expansion of the company’s AMI pilot, from approximately 131,000 customers to 310,000 customers, and additional investments in Smart Grid technologies. The DOE is expected to select projects for funding later this year.

On September 2, 2009, ComEd submitted a petition to the ICC requesting recovery of the remaining costs of the stimulus projects after receiving the matching funds from the DOE.

• Illinois Uncollectibles Recovery Rider: On August 9, 2009, Illinois Governor Pat Quinn signed legislation that includes assistance to low-income customers to manage their energy bills. In addition, the legislation includes a provision for utilities to recover their actual uncollectible accounts expenses through a rider adjustment mechanism. The rider would minimize regulatory lag during times when uncollectible accounts expenses are increasing beyond what is recovered through base rates and provide credits when lower than what is covered in base rates. On September 8, 2009, ComEd filed a proposed tariff with the ICC to implement this rider. An ICC decision is expected in the first quarter of 2010.

• PECO Smart Meter/Smart Grid Plan: PECO is planning to spend up to approximately $650 million on its smart meter and smart grid infrastructure. On August 14, 2009, PECO filed its $550 million Smart Meter Procurement and Installation Plan with the Pennsylvania Public Utility Commission (PAPUC) in accordance with the requirements of Pennsylvania Act 129. PECO is requesting PAPUC approval to install more than 1.6 million smart meters and deploy advanced

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communication networks over a 15-year period. The first phase of the plan includes the procurement and deployment of automated meter infrastructure and initial deployment of 100,000 smart meters over the next three years.

On August 6, 2009, PECO filed with the DOE its application seeking $200 million in American Recovery and Reinvestment Act grant funds under the Smart Grid Investment Grant Program. PECO’s “Smart Future Greater Philadelphia” project will increase the number of smart meters initially installed to 600,000, accelerate universal meter deployment by five years and increase Smart Grid investments up to approximately $100 million over the next three years.

• PECO Energy Procurement: On September 23, 2009, the PAPUC approved the results of PECO’s second competitive procurement request for proposal (RFP) for residential customers and its initial generation supply procurement for the small and medium commercial classes. The September procurements for the residential class included full requirements fixed price contracts for 17-month and 29-month periods beginning January 1, 2011, and forward purchase block contracts to procure electric generation for the 12-month period beginning January 1, 2011. The procurements for the small and medium commercial classes included full requirements fixed-price contracts for the 17-month period beginning January 1, 2011.

The June and September procurements combined accounted for approximately 49 percent of the total full requirements electricity needed for PECO’s residential customers beginning in 2011 at an average retail price of 9.41 cents per kilowatt-hour (kWh), about a 4 percent increase compared to current prices. The September procurement accounted for approximately 24 percent and 16 percent of the full requirement fixed-price product for PECO’s small and medium commercial customers, respectively, at an average blended retail price of 9.79 cents per kWh. PECO’s next supply purchases for the residential and the small and medium commercial classes will take place in May 2010.

• Pension Contribution: On September 9, 2009, Exelon announced that it was making a $350 million discretionary pension contribution allocated to the 2008 plan year, taking advantage of Federal pension funding relief provided by the Worker, Retiree and Employer Recovery Act of 2008 that allows use of average expected returns to establish asset values for determining funding requirements. The U.S. Treasury Department also has provided some funding relief through options in selecting the interest rates used for funding. The discretionary pension contribution – funded with cash from operations in excess of Exelon’s original 2009 plan – and Exelon’s pension funding elections will lower near-term mandatory pension contributions, which should increase future financial flexibility.

• Financing Activities: On September 23, 2009, Generation issued $600 million of Senior Notes maturing on October 1, 2019, with a coupon of 5.20 percent and $900 million of Senior Notes maturing on October 1, 2039, with a coupon of 6.25 percent. Generation used the net proceeds from the sale (1) to pay approximately $622 million of principal, premium and accrued interest in connection with the purchase of approximately $555 million in aggregate principal amount of its 6.95 percent Notes due June 15, 2011 pursuant to Generation’s cash tender offer announced on September 16, 2009, (2) for a $432 million distribution to Exelon Corporation to fund its purchase of approximately $387 million in aggregate principal amount of its 6.75 percent Senior

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Notes due May 1, 2011 pursuant to its cash tender offer announced on September 16, 2009, and (3) to fund Generation’s repurchase of $307 million of pollution-control bonds in early September. On September 23, 2009, Exelon Corporation and Generation called the remaining bonds that were not tendered pursuant to their tender offers, according to the terms of the respective bond issues. These bonds are obligated to be tendered today under the terms of the bonds and the call notices. Through these debt repurchase and refinancing activities, Exelon was able to capitalize on favorable market conditions, resulting in lower interest expense and an extended debt maturity profile.

• Credit Rating Actions: Following the termination of Exelon’s proposed offer for NRG on July 21, 2009, the rating agencies took the following actions.

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

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

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

On August 3, 2009, Moody’s changed its credit rating methodology, widening the notching between most senior secured debt ratings and senior unsecured debt ratings of investment grade regulated utilities. As a result, Moody’s upgraded ComEd’s senior secured debt rating to “Baa1” from “Baa2”.

OPERATING COMPANY RESULTS

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

Third quarter 2009 net income was $657 million compared with $635 million in the third quarter of 2008. Third quarter 2009 net income included (all after tax) costs of $9 million associated with the 2007 Illinois electric rate settlement, mark-to-market gains of $77 million from economic hedging activities before the elimination of intercompany transactions, unrealized gains of $87 million related to NDT fund investments, income of $32 million resulting from the reduction in decommissioning obligations primarily related to the former AmerGen nuclear plants, income of $2 million from the true-up of 2009 costs incurred for severance, and costs of $36 million associated with the early retirement of long-term debt. Third quarter 2008 net income included (all after tax) costs of $25 million associated with the

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2007 Illinois electric rate settlement, mark-to-market gains of $96 million from economic hedging activities before the elimination of intercompany transactions, unrealized losses of $60 million related to NDT fund investments primarily related to the former AmerGen nuclear plants, and income of $15 million resulting from the reduction in decommissioning obligations primarily related to the former AmerGen nuclear plants. Excluding the impact of these items, Generation’s net income in the third quarter of 2009 decreased $105 million compared with the same quarter last year primarily due to:

• Lower energy gross margins, largely due to unfavorable portfolio and market conditions, decreased nuclear output as a result of a higher number of refueling and non-refueling outage days and higher nuclear fuel costs; and

• Higher costs related to a higher number of scheduled nuclear refueling outage days and increased pension and OPEB expense.

The decrease in net income was partially offset by:

• Establishment of a reserve in 2008 related to Generation’s accounts receivable from Lehman Brothers Holdings Inc. due to its bankruptcy filing; and

• Savings achieved through the cost management initiative.

Generation’s average realized margin on all electric sales, including sales to affiliates and excluding trading activity, was $36.32 per MWh in the third quarter of 2009 compared with $36.54 per MWh in the third quarter of 2008.

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

ComEd recorded net income of $46 million in the third quarter of 2009, compared with net income of $33 million in the third quarter of 2008. Third quarter net income in 2009 and 2008 included costs of $2 million and $1 million after tax, respectively, associated with the Illinois electric rate settlement. Excluding the impact of these items, ComEd’s net income in the third quarter of 2009 increased $14 million from the same quarter last year primarily due to:

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

• Lower operating and maintenance expense, which primarily reflected savings achieved through the cost management initiative and the impact of decreased storm costs, partially offset by increased pension and OPEB expense; and

• Discrete disallowances recorded in 2008, net of allowed regulatory assets, mandated by the September 2008 rate case order.

The increase in net income was partially offset by:

• Reversal of an Illinois investment tax credit ruling – this benefit previously was recorded in the first quarter of 2009; and

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

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In the third quarter of 2009, cooling degree-days in the ComEd service territory were down 34.2 percent relative to the same period in 2008, and were 34.0 percent below normal. This reflected the Chicago area’s coolest summer weather in 17 years. ComEd’s total retail kilowatt-hour (kWh) deliveries decreased by 9.8 percent quarter over quarter, with declines in deliveries to all major customer classes. In addition, the number of residential customers being served in the ComEd region decreased 0.5 percent from the third quarter of 2008.

Weather-normalized retail kWh deliveries decreased by 3.8 percent from the third quarter of 2008. For ComEd, weather had an unfavorable after-tax impact of $18 million on third quarter 2009 earnings relative to 2008 and an unfavorable after-tax impact of $24 million relative to normal weather that was incorporated in earnings guidance.

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

PECO’s net income in the third quarter of 2009 was $92 million, up from $90 million in the third quarter of 2008. This increase was primarily due to:

• Lower uncollectible accounts expense.

The increase in net income was partially offset by:

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

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

In the third quarter of 2009, cooling degree-days in the PECO service territory were down 6.2 percent from 2008, and were 5.9 percent below normal. Total retail kWh deliveries were down 5.6 percent from last year, reflecting a decline in deliveries across all customer classes, primarily driven by the impact of current economic conditions and unfavorable weather conditions. The number of residential electric customers being served in the PECO region decreased 0.4 percent from the third quarter of 2008.

Weather-normalized retail kWh deliveries decreased by 3.9 percent from the third quarter of 2008, primarily reflecting decreased residential and large commercial and industrial deliveries. For PECO, weather had an unfavorable after-tax impact of $9 million on third quarter 2009 earnings relative to 2008 and an unfavorable after-tax impact of $19 million relative to normal weather that was incorporated in earnings guidance.

Adjusted (non-GAAP) Operating Earnings

Adjusted (non-GAAP) operating earnings, which generally exclude significant one-time charges or credits that are not normally associated with ongoing operations, mark-to-market adjustments from economic hedging activities and unrealized gains and losses from NDT fund investments, are provided as a supplement to results reported in accordance with GAAP. Management uses such adjusted (non-

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GAAP) operating earnings measures internally to evaluate the company’s performance and manage its operations. Reconciliation of GAAP to adjusted (non-GAAP) operating earnings for historical periods is attached. Additional earnings release attachments, which include the reconciliation on page 7, are posted on Exelon’s Web site: www.exeloncorp.com and have been filed with the Securities and Exchange Commission on Form 8-K on October 23, 2009.

Conference call information: Exelon has scheduled a conference call for 10:30 AM ET (9:30 AM CT) on October 23, 2009. The call-in number in the U.S. and Canada is 800-690-3108, and the international call-in number is 973-935-8753. If requested, the conference ID number is 32242270. Media representatives are invited to participate on a listen-only basis. The call will be web-cast and archived on Exelon’s Web site: www.exeloncorp.com. (Please select the Investor Relations page.)

Telephone replays will be available until November 6. The U.S. and Canada call-in number for replays is 800-642-1687, and the international call-in number is 706-645-9291. The conference ID number is 32242270.

Forward Looking Statements

This press release includes forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995, that are subject to risks and uncertainties. The factors that could cause actual results to differ materially from these forward-looking statements include those discussed herein as well as those discussed in (1) Exelon’s 2008 Annual Report on Form 10-K in (a) ITEM 1A. Risk Factors, (b) ITEM 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations and (c) ITEM 8. Financial Statements and Supplementary Data: Note 18; (2) Exelon’s Third Quarter 2009 Quarterly Report on Form 10-Q (to be filed on October 23, 2009) in (a) Part II, Other Information, ITEM 1A. Risk Factors and (b) Part I, Financial Information, ITEM 1. Financial Statements: Note 14; and (3) other factors discussed in filings with the Securities and Exchange Commission (SEC) by Exelon Corporation, Commonwealth Edison Company, PECO Energy Company and Exelon Generation Company, LLC (Companies). Readers are cautioned not to place undue reliance on these forward-looking statements, which apply only as of the date of this press release. None of the Companies undertakes any obligation to publicly release any revision to its forward-looking statements to reflect events or circumstances after the date of this press release.

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

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EXELON CORPORATION

Earnings Release Attachments

Table of Contents

Consolidating Statements of Operations - Three Months Ended September 30, 2009 and 2008	1
Consolidating Statements of Operations - Nine Months Ended September 30, 2009 and 2008	2
Business Segment Comparative Statements of Operations - Generation and ComEd - Three and Nine Months Ended September 30, 2009 and 2008	3
Business Segment Comparative Statements of Operations - PECO and Other - Three and Nine Months Ended September 30, 2009 and 2008	4
Consolidated Balance Sheets - September 30, 2009 and December 31, 2008	5
Consolidated Statements of Cash Flows - Nine Months Ended September 30, 2009 and 2008	6
Reconciliation of Adjusted (non-GAAP) Operating Earnings to GAAP Consolidated Statements of Operations - Exelon - Three Months Ended September 30, 2009 and 2008	7
Reconciliation of Adjusted (non-GAAP) Operating Earnings to GAAP Consolidated Statements of Operations - Exelon - Nine Months Ended September 30, 2009 and 2008	8
Reconciliation of Adjusted (non-GAAP) Operating Earnings to GAAP Earnings By Business Segment - Three Months Ended September 30, 2009 and 2008	9
Reconciliation of Adjusted (non-GAAP) Operating Earnings to GAAP Earnings By Business Segment - Nine Months Ended September 30, 2009 and 2008	10
Reconciliation of Adjusted (non-GAAP) Operating Earnings to GAAP Consolidated Statements of Operations - Generation - Three and Nine Months Ended September 30, 2009 and 2008	11
Reconciliation of Adjusted (non-GAAP) Operating Earnings to GAAP Consolidated Statements of Operations - ComEd - Three and Nine Months Ended September 30, 2009 and 2008	12
Reconciliation of Adjusted (non-GAAP) Operating Earnings to GAAP Consolidated Statements of Operations - PECO - Three and Nine Months Ended September 30, 2009 and 2008	13
Reconciliation of Adjusted (non-GAAP) Operating Earnings to GAAP Consolidated Statements of Operations - Other - Three and Nine Months Ended September 30, 2009 and 2008	14
Exelon Generation Statistics - Three Months Ended September 30, 2009, June 30, 2009, March 31, 2009, December 31, 2008 and September 30, 2008	15
Exelon Generation Statistics - Nine Months Ended September 30, 2009 and 2008	16
ComEd Statistics - Three and Nine Months Ended September 30, 2009 and 2008	17
PECO Statistics - Three and Nine Months Ended September 30, 2009 and 2008	18

EXELON CORPORATION

Consolidating Statements of Operations

(unaudited)

(in millions)

	Three Months Ended September 30, 2009
	Generation			ComEd			PECO			Other			Exelon Consolidated
Operating revenues	$	2,445		$	1,475		$	1,327		$	(908	)	$	4,339
Operating expenses
Purchased power		303			776			625			(908	)		796
Fuel		379			—			26			(1	)		404
Operating and maintenance		592			273			154			1			1,020
Operating and maintenance for regulatory required programs (a)		—			19			—			—			19
Depreciation and amortization		74			125			272			14			485
Taxes other than income		51			79			78			4			212
Total operating expenses		1,399			1,272			1,155			(890	)		2,936
Operating income (loss)		1,046			203			172			(18	)		1,403
Other income and deductions
Interest expense, net		(24	)		(82	)		(46	)		(36	)		(188	)
Equity in losses of unconsolidated affiliates and investments		(1	)		—			(6	)		(1	)		(8	)
Other, net		192			(19	)		2			(27	)		148
Total other income and deductions		167			(101	)		(50	)		(64	)		(48	)
Income (loss) before income taxes		1,213			102			122			(82	)		1,355
Income taxes		556			56			30			(44	)		598
Net income (loss)	$	657		$	46		$	92		$	(38	)	$	757
	Three Months Ended September 30, 2008
	Generation			ComEd			PECO			Other			Exelon Consolidated
Operating revenues	$	3,073		$	1,729		$	1,441		$	(1,015	)	$	5,228
Operating expenses
Purchased power		528			1,068			693			(962	)		1,327
Fuel		669			—			50			(1	)		718
Operating and maintenance		625			306			192			(13	)		1,110
Operating and maintenance for regulatory required programs (a)		—			11			—			—			11
Depreciation and amortization		58			119			243			11			431
Taxes other than income		53			87			73			5			218
Total operating expenses		1,933			1,591			1,251			(960	)		3,815
Operating income (loss)		1,140			138			190			(55	)		1,413
Other income and deductions
Interest expense, net		(34	)		(87	)		(55	)		(27	)		(203	)
Equity in losses of unconsolidated affiliates and investments		—			(2	)		(4	)		—			(6	)
Other, net		(164	)		3			2			1			(158	)
Total other income and deductions		(198	)		(86	)		(57	)		(26	)		(367	)
Income (loss) before income taxes		942			52			133			(81	)		1,046
Income taxes		307			19			43			(23	)		346
Net income (loss)	$	635		$	33		$	90		$	(58	)	$	700

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

1

EXELON CORPORATION

Consolidating Statements of Operations

(unaudited)

(in millions)

	Nine Months Ended September 30, 2009
	Generation			ComEd			PECO			Other			Exelon Consolidated
Operating revenues	$	7,424		$	4,417		$	4,045		$	(2,684	)	$	13,202
Operating expenses
Purchased power		962			2,373			1,742			(2,677	)		2,400
Fuel		1,295			—			346			(1	)		1,640
Operating and maintenance		2,210			796			481			5			3,492
Operating and maintenance for regulatory required programs (a)		—			44			—			—			44
Depreciation and amortization		223			371			726			40			1,360
Taxes other than income		150			215			213			14			592
Total operating expenses		4,840			3,799			3,508			(2,619	)		9,528
Operating income (loss)		2,584			618			537			(65	)		3,674
Other income and deductions
Interest expense, net		(77	)		(241	)		(145	)		(92	)		(555	)
Equity in losses of unconsolidated affiliates and investments		(2	)		—			(19	)		—			(21	)
Other, net		325			67			8			(33	)		367
Total other income and deductions		246			(174	)		(156	)		(125	)		(209	)
Income (loss) before income taxes		2,830			444			381			(190	)		3,465
Income taxes		1,133			169			106			(69	)		1,339
Net income (loss)	$	1,697		$	275		$	275		$	(121	)	$	2,126
	Nine Months Ended September 30, 2008
	Generation			ComEd			PECO			Other			Exelon Consolidated
Operating revenues	$	8,311		$	4,594		$	4,195		$	(2,734	)	$	14,366
Operating expenses
Purchased power		1,704			2,729			1,859			(2,727	)		3,565
Fuel		1,211			—			397			—			1,608
Operating and maintenance		2,023			828			557			(25	)		3,383
Operating and maintenance for regulatory required programs (a)		—			17			—			—			17
Depreciation and amortization		202			343			653			32			1,230
Taxes other than income		153			227			203			14			597
Total operating expenses		5,293			4,144			3,669			(2,706	)		10,400
Operating income (loss)		3,018			450			526			(28	)		3,966
Other income and deductions
Interest expense, net		(108	)		(279	)		(171	)		(80	)		(638	)
Equity in losses of unconsolidated affiliates and investments		(1	)		(7	)		(11	)		—			(19	)
Other, net		(292	)		12			13			11			(256	)
Total other income and deductions		(401	)		(274	)		(169	)		(69	)		(913	)
Income (loss) from continuing operations before income taxes		2,617			176			357			(97	)		3,053
Income taxes		891			66			111			(46	)		1,022
Income (loss) from continuing operations		1,726			110			246			(51	)		2,031
Loss from discontinued operations		(1	)		—			—			—			(1	)
Net income (loss)	$	1,725		$	110		$	246		$	(51	)	$	2,030

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

2

EXELON CORPORATION

Business Segment Comparative Statements of Operations

(unaudited)

(in millions)

	Generation
	Three Months Ended September 30,									Nine Months Ended September 30,
	2009			2008			Variance			2009			2008			Variance
Operating revenues	$	2,445		$	3,073		$	(628	)	$	7,424		$	8,311		$	(887	)
Operating expenses
Purchased power		303			528			(225	)		962			1,704			(742	)
Fuel		379			669			(290	)		1,295			1,211			84
Operating and maintenance		592			625			(33	)		2,210			2,023			187
Depreciation and amortization		74			58			16			223			202			21
Taxes other than income		51			53			(2	)		150			153			(3	)
Total operating expenses		1,399			1,933			(534	)		4,840			5,293			(453	)
Operating income		1,046			1,140			(94	)		2,584			3,018			(434	)
Other income and deductions
Interest expense, net		(24	)		(34	)		10			(77	)		(108	)		31
Equity in losses of investments		(1	)		—			(1	)		(2	)		(1	)		(1	)
Other, net		192			(164	)		356			325			(292	)		617
Total other income and deductions		167			(198	)		365			246			(401	)		647
Income from continuing operations before income taxes		1,213			942			271			2,830			2,617			213
Income taxes		556			307			249			1,133			891			242
Income from continuing operations		657			635			22			1,697			1,726			(29	)
Loss from discontinued operations		—			—			—			—			(1	)		1
Net income	$	657		$	635		$	22		$	1,697		$	1,725		$	(28	)
	ComEd
	Three Months Ended September 30,									Nine Months Ended September 30,
	2009			2008			Variance			2009			2008			Variance
Operating revenues	$	1,475		$	1,729		$	(254	)	$	4,417		$	4,594		$	(177	)
Operating expenses
Purchased power		776			1,068			(292	)		2,373			2,729			(356	)
Operating and maintenance		273			306			(33	)		796			828			(32	)
Operating and maintenance for regulatory required programs (a)		19			11			8			44			17			27
Depreciation and amortization		125			119			6			371			343			28
Taxes other than income		79			87			(8	)		215			227			(12	)
Total operating expenses		1,272			1,591			(319	)		3,799			4,144			(345	)
Operating income		203			138			65			618			450			168
Other income and deductions
Interest expense, net		(82	)		(87	)		5			(241	)		(279	)		38
Equity in losses of unconsolidated affiliates		—			(2	)		2			—			(7	)		7
Other, net		(19	)		3			(22	)		67			12			55
Total other income and deductions		(101	)		(86	)		(15	)		(174	)		(274	)		100
Income before income taxes		102			52			50			444			176			268
Income taxes		56			19			37			169			66			103
Net income	$	46		$	33		$	13		$	275		$	110		$	165

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

3

EXELON CORPORATION

Business Segment Comparative Statements of Operations

(unaudited)

(in millions)

		PECO
	Three Months Ended September 30,									Nine Months Ended September 30,
	2009			2008			Variance			2009			2008			Variance
Operating revenues		$1,327		$	1,441		$	(114	)	$	4,045		$	4,195		$	(150	)
Operating expenses
Purchased power		625			693			(68	)		1,742			1,859			(117	)
Fuel		26			50			(24	)		346			397			(51	)
Operating and maintenance		154			192			(38	)		481			557			(76	)
Depreciation and amortization		272			243			29			726			653			73
Taxes other than income		78			73			5			213			203			10
Total operating expenses		1,155			1,251			(96	)		3,508			3,669			(161	)
Operating income		172			190			(18	)		537			526			11
Other income and deductions
Interest expense, net		(46	)		(55	)		9			(145	)		(171	)		26
Equity in losses of unconsolidated affiliates		(6	)		(4	)		(2	)		(19	)		(11	)		(8	)
Other, net		2			2			—			8			13			(5	)
Total other income and deductions		(50	)		(57	)		7			(156	)		(169	)		13
Income before income taxes		122			133			(11	)		381			357			24
Income taxes		30			43			(13	)		106			111			(5	)
Net income	$	92		$	90		$	2		$	275		$	246		$	29
		Other (a)
	Three Months Ended September 30,									Nine Months Ended September 30,
	2009			2008			Variance			2009			2008			Variance
Operating revenues	$	(908	)	$	(1,015	)	$	107		$	(2,684	)	$	(2,734	)	$	50
Operating expenses
Purchased power		(908	)		(962	)		54			(2,677	)		(2,727	)		50
Fuel		(1	)		(1	)		—			(1	)		—			(1	)
Operating and maintenance		1			(13	)		14			5			(25	)		30
Depreciation and amortization		14			11			3			40			32			8
Taxes other than income		4			5			(1	)		14			14			—
Total operating expenses		(890	)		(960	)		70			(2,619	)		(2,706	)		87
Operating loss		(18	)		(55	)		37			(65	)		(28	)		(37	)
Other income and deductions
Interest expense, net		(36	)		(27	)		(9	)		(92	)		(80	)		(12	)
Equity in losses of unconsolidated affiliates and investments		(1	)		—			(1	)		—			—			—
Other, net		(27	)		1			(28	)		(33	)		11			(44	)
Total other income and deductions		(64	)		(26	)		(38	)		(125	)		(69	)		(56	)
Loss before income taxes		(82	)		(81	)		(1	)		(190	)		(97	)		(93	)
Income taxes		(44	)		(23	)		(21	)		(69	)		(46	)		(23	)
Net loss	$	(38	)	$	(58	)	$	20		$	(121	)	$	(51	)	$	(70	)

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

4

EXELON CORPORATION

Consolidated Balance Sheets

(unaudited)

(in millions)

	September 30, 2009			December 31, 2008
Current assets
Cash and cash equivalents	$	2,374		$	1,271
Restricted cash and investments		43			75
Accounts receivable, net
Customer		1,418			1,928
Other		442			324
Mark-to-market derivative assets		467			410
Inventories, net
Fossil fuel		216			315
Materials and supplies		568			528
Other		367			517
Total current assets		5,895			5,368
Property, plant and equipment, net		26,653			25,813
Deferred debits and other assets
Regulatory assets		5,137			5,940
Nuclear decommissioning trust (NDT) funds		6,502			5,500
Investments		732			715
Goodwill		2,625			2,625
Mark-to-market derivative assets		482			507
Other		1,476			1,349
Total deferred debits and other assets		16,954			16,636
Total assets	$	49,502		$	47,817
Liabilities and equity
Current liabilities
Short-term borrowings	$	140		$	211
Long-term debt due within one year		873			29
Long-term debt to PECO Energy Transition Trust (PETT) due within one year		591			319
Accounts payable		1,075			1,416
Mark-to-market derivative liabilities		206			214
Accrued expenses		888			1,151
Deferred income taxes		117			77
Other		554			663
Total current liabilities		4,444			4,080
Long-term debt		11,021			11,397
Long-term debt to PECO Energy Transition Trust		—			805
Long-term debt to other financing trusts		390			390
Deferred credits and other liabilities
Deferred income taxes and unamortized investment tax credits		5,858			4,939
Asset retirement obligations		3,381			3,734
Pension obligations		3,782			4,111
Non-pension postretirement benefits obligations		2,248			2,255
Spent nuclear fuel obligation		1,017			1,015
Regulatory liabilities		3,395			2,520
Mark-to-market derivative liabilities		72			24
Other		1,317			1,413
Total deferred credits and other liabilities		21,070			20,011
Total liabilities		36,925			36,683
Preferred securities of subsidiary		87			87
Shareholders’ equity
Common stock		8,896			8,816
Treasury stock, at cost		(2,338	)		(2,338	)
Retained earnings		7,905			6,820
Accumulated other comprehensive loss, net		(1,973	)		(2,251	)
Total shareholders’ equity		12,490			11,047
Total liabilities and shareholders’ equity	$	49,502		$	47,817

5

EXELON CORPORATION

Consolidated Statements of Cash Flows

(unaudited)

(in millions)

	Nine Months Ended September 30,
	2009			2008
Cash flows from operating activities
Net income	$	2,126		$	2,030
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation, amortization and accretion, including nuclear fuel amortization		1,935			1,725
Impairment of long-lived assets		223			—
Deferred income taxes and amortization of investment tax credits		740			111
Net fair value changes related to derivatives and NDT funds		(257	)		(115	)
Other non-cash operating activities		464			658
Changes in assets and liabilities:
Accounts receivable		335			226
Inventories		41			(158	)
Accounts payable, accrued expenses and other current liabilities		(463	)		(261	)
Counterparty collateral received, net		380			245
Income taxes		(176	)		457
Pension and non-pension postretirement benefit contributions		(456	)		(103	)
Other assets and liabilities		(263	)		(448	)
Net cash flows provided by operating activities		4,629			4,367
Cash flows from investing activities
Capital expenditures		(2,252	)		(2,282	)
Proceeds from NDT fund sales		18,769			14,392
Investment in NDT funds		(18,949	)		(14,621	)
Change in restricted cash		32			28
Other investing activities		16			6
Net cash flows used in investing activities		(2,384	)		(2,477	)
Cash flows from financing activities
Changes in short-term debt		(71	)		(431	)
Issuance of long-term debt		1,987			1,969
Retirement of long-term debt		(1,515	)		(1,397	)
Retirement of long-term debt to financing affiliates		(533	)		(862	)
Dividends paid on common stock		(1,038	)		(989	)
Proceeds from employee stock plans		28			122
Purchase of treasury stock		—			(436	)
Purchase of forward contract in relation to certain treasury stock		—			(64	)
Other financing activities		—			69
Net cash flows used in financing activities		(1,142	)		(2,019	)
Increase (decrease) in cash and cash equivalents		1,103			(129	)
Cash and cash equivalents at beginning of period		1,271			311
Cash and cash equivalents at end of period	$	2,374		$	182

6

EXELON CORPORATION

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

(unaudited)

(in millions, except per share data)

	Three Months Ended September 30, 2009									Three Months Ended September 30, 2008
	GAAP (a)			Adjustments			Adjusted Non-GAAP			GAAP (a)			Adjustments			Adjusted Non-GAAP
Operating revenues	$	4,339		$	16	(c)	$	4,355		$	5,228		$	43	(c)	$	5,271
Operating expenses
Purchased power		796			89	(d)		885			1,327			305	(d)		1,632
Fuel		404			37	(d)		441			718			(198	)(d)		520
Operating and maintenance		1,020			46	(c),(e),(f),(g)		1,066			1,110			26	(c),(g)		1,136
Operating and maintenance for regulatory required programs (b)		19			—			19			11			—			11
Depreciation and amortization		485			—			485			431			—			431
Taxes other than income		212			—			212			218			—			218
Total operating expenses		2,936			172			3,108			3,815			133			3,948
Operating income		1,403			(156	)		1,247			1,413			(90	)		1,323
Other income and deductions
Interest expense, net		(188	)		3	(h)		(185	)		(203	)		—			(203	)
Equity in losses of unconsolidated affiliates and investments		(8	)		—			(8	)		(6	)		—			(6	)
Other, net		148			(152	)(h),(i)		(4	)		(158	)		170	(i)		12
Total other income and deductions		(48	)		(149	)		(197	)		(367	)		170			(197	)
Income before income taxes		1,355			(305	)		1,050			1,046			80			1,126
Income taxes		598			(181	)(c),(d),(e),(f),(g),(h),(i)		417			346			74	(c),(d),(g),(i)		420
Net income	$	757		$	(124	)	$	633		$	700		$	6		$	706
Effective tax rate		44.1	%					39.7	%		33.1	%					37.3	%
Earnings per average common share
Basic:
Income from continuing operations	$	1.15		$	(0.19	)	$	0.96		$	1.06		$	0.01		$	1.07
Income from discontinued operations		—			—			—			—			—			—
Net income	$	1.15		$	(0.19	)	$	0.96		$	1.06		$	0.01		$	1.07
Diluted:
Income from continuing operations	$	1.14		$	(0.18	)	$	0.96		$	1.06		$	0.01		$	1.07
Income from discontinued operations		—			—			—			—			—			—
Net income	$	1.14		$	(0.18	)	$	0.96		$	1.06		$	0.01		$	1.07
Average common shares outstanding
Basic		660						660			658						658
Diluted		662						662			662						662
Effect of adjustments on earnings per average diluted common share recorded in accordance with GAAP:
2007 Illinois electric rate settlement (c)				$	0.02								$	0.04
Mark-to-market impact of economic hedging activities (d)					(0.12	)								(0.10	)
NRG acquisition costs (e)					0.01									—
2009 severance charges (f)					—									—
Decommissioning obligation reduction (g)					(0.05	)								(0.02	)
Costs associated with early debt retirements (h)					0.09									—
Unrealized gains and losses related to NDT fund investments (i)					(0.13	)								0.09
Total adjustments				$	(0.18	)							$	0.01

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

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

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

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

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

(f) Adjustment to exclude 2009 severance charges.

(g) Adjustment to exclude the reduction in Generation's decommissioning obligation.

(h) Adjustment to exclude 2009 costs associated with early debt retirements.

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

7

EXELON CORPORATION

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

(unaudited)

(in millions, except per share data)

	Nine Months Ended September 30, 2009									Nine Months Ended September 30, 2008
	GAAP (a)			Adjustments			Adjusted Non-GAAP			GAAP (a)			Adjustments			Adjusted Non-GAAP
Operating revenues	$	13,202		$	82	(c)	$	13,284		$	14,366		$	189	(c)	$	14,555
Operating expenses
Purchased power		2,400			129	(d)		2,529			3,565			210	(d)		3,775
Fuel		1,640			9	(d)		1,649			1,608			88	(d)		1,696
Operating and maintenance		3,492			(241	)(c),(e),(f),(g),(h)		3,251			3,383			22	(c),(h)		3,405
Operating and maintenance for regulatory required programs (b)		44			—			44			17			—			17
Depreciation and amortization		1,360			—			1,360			1,230			—			1,230
Taxes other than income		592			—			592			597			—			597
Total operating expenses		9,528			(103	)		9,425			10,400			320			10,720
Operating income		3,674			185			3,859			3,966			(131	)		3,835
Other income and deductions
Interest expense, net		(555	)		12	(i),(j)		(543	)		(638	)		—			(638	)
Equity in losses of unconsolidated affiliates and investments		(21	)		—			(21	)		(19	)		—			(19	)
Other, net		367			(308	)(i),(j),(k)		59			(256	)		335	(k)		79
Total other income and deductions		(209	)		(296	)		(505	)		(913	)		335			(578	)
Income before income taxes		3,465			(111	)		3,354			3,053			204			3,257
Income taxes		1,339			(97	)(c),(d),(e),(f),(g),(h),(i),(j),(k)		1,242			1,022			162	(c),(d),(h),(k)		1,184
Income from continuing operations		2,126			(14	)		2,112			2,031			42			2,073
Loss from discontinued operations		—			—			—			(1	)		—			(1	)
Net Income	$	2,126		$	(14	)	$	2,112		$	2,030		$	42		$	2,072
Effective tax rate		38.6	%					37.0	%		33.5	%					36.4	%
Earnings per average common share
Basic:
Income from continuing operations	$	3.22		$	(0.02	)	$	3.20		$	3.09		$	0.07		$	3.16
Income from discontinued operations		—			—			—			—			—			—
Net income	$	3.22		$	(0.02	)	$	3.20		$	3.09		$	0.07		$	3.16
Diluted:
Income from continuing operations	$	3.21		$	(0.02	)	$	3.19		$	3.06		$	0.07		$	3.13
Income from discontinued operations		—			—			—			—			—			—
Net income	$	3.21		$	(0.02	)	$	3.19		$	3.06		$	0.07		$	3.13
Average common shares outstanding
Basic		659						659			658						658
Diluted		661						661			663						663
Effect of adjustments on earnings per average diluted common share recorded in accordance with GAAP:
2007 Illinois electric rate settlement (c)				$	0.08								$	0.18
Mark-to-market impact of economic hedging activities (d)					(0.12	)								(0.27	)
NRG acquisition costs (e)					0.03									—
Impairment of certain generating assets (f)					0.20									—
2009 severance charges (g)					0.03									—
Decommissioning obligation reduction (h)					(0.05	)								(0.02	)
Non-cash income tax matters and state taxes (i)					(0.10	)								—
Costs associated with early debt retirements (j)					0.09									—
Unrealized gains and losses related to NDT fund investments (k)					(0.18	)								0.18
Total adjustments				$	(0.02	)							$	0.07

(a) Results reported in accordance with GAAP.

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

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

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

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

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

(g) Adjustment to exclude 2009 severance charges.

(h) Adjustment to exclude the reduction in Generation's decommissioning obligation.

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

(j) Adjustment to exclude 2009 costs associated with early debt retirements.

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

8

EXELON CORPORATION

Reconciliation of Adjusted (non-GAAP) Operating Earnings

to GAAP Earnings By Business Segment (in millions)

Three Months Ended September 30, 2009 and 2008

	Exelon Earnings per Diluted Share			Generation			ComEd			PECO			Other			Exelon
2008 GAAP Earnings (Loss)	$	1.06		$	635		$	33		$	90		$	(58	)	$	700
2008 Adjusted (non-GAAP) Operating Earnings (Loss) Adjustments:
2007 Illinois Electric Rate Settlement		0.04			25			1			—			—			26
Mark-to-Market Impact of Economic Hedging Activities		(0.10	)		(96	)		—			—			31			(65	)
Unrealized Losses Related to NDT Fund Investments		0.09			60			—			—			—			60
Decommissioning Obligation Reduction (1)		(0.02	)		(15	)		—			—			—			(15	)
2008 Adjusted (non-GAAP) Operating Earnings (Loss)		1.07			609			34			90			(27	)		706
Year Over Year Effects on Earnings:
Generation Energy Margins, Excluding Mark-to-Market (2)		(0.10	)		(64	)		—			—			—			(64	)
ComEd and PECO Margins:
Weather (3)		(0.04	)		—			(18	)		(9	)		—			(27	)
Other Energy Delivery (4)		0.05			—			36			(6	)		—			30
Operating and Maintenance Expense:
Bad Debt (5)		0.05			14			(7	)		29			—			36
Labor, Contracting and Materials (6)		0.02			15			5			(6	)		—			14
Other Operating and Maintenance Expense (7)		0.04			—			19			4			3			26
Pension and Non-Pension Postretirement Benefits Expense (8)		(0.04	)		(12	)		(9	)		(1	)		(5	)		(27	)
Planned Nuclear Refueling Outages (9)		(0.02	)		(15	)		—			—			—			(15	)
Discrete Items Resulting From the Distribution Rate Case (10)		0.02			—			15			—			—			15
Depreciation and Amortization (11)		(0.06	)		(10	)		(6	)		(21	)		(1	)		(38	)
Reversal of Benefit From Tax Ruling (12)		(0.06	)		(8	)		(35	)		—			1			(42	)
Income Taxes (13)		—			(25	)		1			10			17			3
Other (14)		0.03			—			13			1			2			16
2009 Adjusted (non-GAAP) Operating Earnings (Loss)		0.96			504			48			91			(10	)		633
2009 Adjusted (non-GAAP) Operating Earnings (Loss) Adjustments:
2007 Illinois Electric Rate Settlement		(0.02	)		(9	)		(2	)		—			—			(11	)
Mark-to-Market Impact of Economic Hedging Activities		0.12			77			—			—			—			77
Unrealized Gains Related to NDT Fund Investments		0.13			87			—			—			—			87
Decommissioning Obligation Reduction (1)		0.05			32			—			—			—			32
NRG Acquisition Costs (15)		(0.01	)		—			—			—			(6	)		(6	)
2009 Severance Charges (16)		—			2			—			1			—			3
Costs Associated with Early Debt Retirements (17)		(0.09	)		(36	)		—			—			(22	)		(58	)
2009 GAAP Earnings (Loss)	$	1.14		$	657		$	46		$	92		$	(38	)	$	757

(1) Reflects a decrease in Generation’s decommissioning obligation liability primarily related to the former AmerGen nuclear plants.

(2) Primarily reflects in 2009 unfavorable portfolio and market conditions, decreased nuclear output as a result of more planned and unplanned nuclear outage days and higher nuclear fuel costs.

(3) Primarily reflects the impact of unfavorable 2009 weather conditions, compared to 2008, in the ComEd and PECO service territories.

(4) For ComEd, reflects the impact of increased distribution rates effective September 2008, partially offset by reduced load. For PECO, reflects reduced load, partially offset by increased gas distribution rates effective January 2009.

(5) For Generation, reflects the impact of a reserve recorded in 2008 for counterparty exposure to Lehman Brothers Holdings, Inc. For ComEd, reflects an increase in uncollectible accounts, in part as a result of the current overall negative economic conditions, partially mitigated by ComEd’s increased collection activities in 2009. For PECO, reflects the impact of improved accounts receivable aging as a result of enhancements to its credit processes and increased termination and collection activities in late 2008 and 2009.

(6) Primarily reflects Exelon’s ongoing cost savings initiative, partially offset by inflation related to labor, contracting and materials expenses (exclusive of planned nuclear refueling outages as disclosed in number 9 below).

(7) Primarily reflects decreased storm costs in 2009 in the ComEd and PECO service territories.

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

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

(10) Reflects the 2008 impact of discrete disallowances, net of allowed regulatory assets, mandated by the September 2008 Illinois Commerce Commission (ICC) rate order.

(11) Reflects increased scheduled competitive transition charge (CTC) amortization at PECO and increased depreciation across the operating companies due to ongoing capital expenditures.

(12) Reflects the reversal of benefits associated with Investment Tax Credits as a result of the modified opinion issued by the Illinois Supreme Court in July 2009.

(13) Primarily reflects the 2008 impact at PECO of an IRS settlement related to prior tax years, partially offset by a decrease in Generation’s manufacturing deduction.

(14) Primarily reflects decreased interest expense across the operating companies and decreased taxes other than income at ComEd, partially offset by realized NDT fund losses related to market conditions in 2009.

(15) Reflects external costs incurred in 2009 associated with Exelon’s proposed acquisition of NRG, which was terminated in July 2009.

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

(17) Reflects 2009 costs associated with early debt retirements at Generation and Exelon Corporate.

9

EXELON CORPORATION

Reconciliation of Adjusted (non-GAAP) Operating Earnings to

GAAP Earnings By Business Segment (in millions)

Nine Months Ended September 30, 2009 and 2008

	Exelon Earnings per Diluted Share			Generation			ComEd			PECO			Other			Exelon
2008 GAAP Earnings (Loss)	$	3.06		$	1,725		$	110		$	246		$	(51	)	$	2,030
2008 Adjusted (non-GAAP) Operating Earnings (Loss) Adjustments:
2007 Illinois Electric Rate Settlement		0.18			115			5			—			—			120
Mark-to-Market Impact of Economic Hedging Activities		(0.27	)		(180	)		—			—			—			(180	)
Unrealized Losses Related to NDT Fund Investments		0.18			117			—			—			—			117
Decommissioning Obligation Reduction (1)		(0.02	)		(15	)		—			—			—			(15	)
2008 Adjusted (non-GAAP) Operating Earnings (Loss)		3.13			1,762			115			246			(51	)		2,072
Year Over Year Effects on Earnings:
Generation Energy Margins, Excluding Mark-to-Market (2)		(0.16	)		(108	)		—			—			—			(108	)
ComEd and PECO Margins:
Weather (3)		(0.04	)		—			(21	)		(8	)		—			(29	)
Other Energy Delivery (4)		0.21			—			115			21			—			136
Operating and Maintenance Expense:
Bad Debt (5)		0.10			15			(9	)		59			—			65
Labor, Contracting and Materials (6)		0.02			5			17			(9	)		—			13
Other Operating and Maintenance Expense (7)		0.10			15			33			12			10			70
Pension and Non-Pension Postretirement Benefits Expense (8)		(0.11	)		(38	)		(25	)		(5	)		(6	)		(74	)
Planned Nuclear Refueling Outages (9)		0.02			15			—			—			—			15
Discrete Items Resulting From the Distribution Rate Case (10)		0.02			—			15			—			—			15
Depreciation and Amortization (11)		(0.14	)		(13	)		(19	)		(53	)		(5	)		(90	)
Income Taxes (12)		(0.03	)		(26	)		10			13			(18	)		(21	)
Other (13)		0.07			24			20			—			4			48
2009 Adjusted (non-GAAP) Operating Earnings (Loss)		3.19			1,651			251			276			(66	)		2,112
2009 Adjusted (non-GAAP) Operating Earnings (Loss) Adjustments:
2007 Illinois Electric Rate Settlement		(0.08	)		(49	)		(3	)		—			—			(52	)
Mark-to-Market Impact of Economic Hedging Activities		0.12			84			—			—			—			84
Unrealized Gains Related to NDT Fund Investments		0.18			119			—			—			—			119
Decommissioning Obligation Reduction (1)		0.05			32			—			—			—			32
NRG Acquisition Costs (14)		(0.03	)		—			—			—			(20	)		(20	)
Impairment of Certain Generating Assets (15)		(0.20	)		(135	)		—			—			—			(135	)
2009 Severance Charges (16)		(0.03	)		(7	)		(13	)		(1	)		(1	)		(22	)
Non-Cash Remeasurement of Income Tax Uncertainties and Reassessment of State Deferred Income Taxes (17)		0.10			38			40			—			(12	)		66
Costs Associated with Early Debt Retirements (18)		(0.09	)		(36	)		—			—			(22	)		(58	)
2009 GAAP Earnings (Loss)	$	3.21		$	1,697		$	275		$	275		$	(121	)	$	2,126

(1) Reflects a decrease in Generation’s decommissioning obligation liability primarily related to the former AmerGen nuclear plants.

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

(3) Primarily reflects the impact of unfavorable 2009 weather conditions, compared to 2008, in the ComEd and PECO service territories.

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

(5) For Generation, reflects the impact of a reserve recorded in 2008 for counterparty exposure to Lehman Brothers Holdings, Inc. For ComEd, reflects an increase in uncollectible accounts, in part as a result of the current overall negative economic conditions, partially mitigated by ComEd’s increased collection activities in 2009. For PECO, reflects the impact of improved accounts receivable aging as a result of enhancements to its credit processes and increased termination and collection activities in late 2008 and 2009.

(6) Primarily reflects Exelon’s ongoing cost savings initiative and lower planned outage costs at Generation’s non-nuclear generating plants, partially offset by inflation related to labor, contracting and materials expenses (exclusive of planned nuclear refueling outages as disclosed in number 9 below).

(7) Primarily reflects the impact of decreased storm costs in 2009 in the ComEd and PECO service territories, decreased nuclear refueling outage costs related to Generation’s ownership interest in Salem and decreased costs associated with the possible construction of a new nuclear plant in Texas.

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

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

(10) Reflects the 2008 impact of discrete disallowances, net of allowed regulatory assets, mandated by the September 2008 ICC rate order.

(11) Primarily reflects increased scheduled CTC amortization at PECO and increased depreciation across the operating companies due to ongoing capital expenditures.

(12) Primarily reflects a decrease in Generation’s manufacturing deduction and the 2008 impact of income from state tax settlements, partially offset by a decrease in PECO’s 2009 state income tax expense due to higher deductible interest expense.

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

(14) Reflects external costs incurred in 2009 associated with Exelon’s proposed acquisition of NRG, which was terminated in July 2009.

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

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

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

(18) Reflects 2009 costs associated with early debt retirements at Generation and Exelon Corporate.

10

EXELON CORPORATION

Reconciliation of Adjusted (non-GAAP) Operating Earnings to

GAAP Consolidated Statements of Operations

(unaudited)

(in millions)

	Generation
	Three Months Ended September 30, 2009									Three Months Ended September 30, 2008
	GAAP (a)			Adjustments			Adjusted Non-GAAP			GAAP (a)			Adjustments			Adjusted Non-GAAP
Operating revenues	$	2,445		$	14	(b)	$	2,459		$	3,073		$	41	(b)	$	3,114
Operating expenses
Purchased power		303			89	(c)		392			528			356	(c)		884
Fuel		379			37	(c)		416			669			(198	)(c)		471
Operating and maintenance		592			55	(d),(e)		647			625			25	(e)		650
Depreciation and amortization		74			—			74			58			—			58
Taxes other than income		51			—			51			53			—			53
Total operating expenses		1,399			181			1,580			1,933			183			2,116
Operating income		1,046			(167	)		879			1,140			(142	)		998
Other income and deductions
Interest expense, net		(24	)		2	(f)		(22	)		(34	)		—			(34	)
Equity in losses of investments		(1	)		—			(1	)		—			—			—
Other, net		192			(188	)(f),(g)		4			(164	)		170	(g)		6
Total other income and deductions		167			(186	)		(19	)		(198	)		170			(28	)
Income before income taxes		1,213			(353	)		860			942			28			970
Income taxes		556			(200	)(b),(c),(d),(e),(f),(g)		356			307			54	(b),(c),(e),(g)		361
Net Income	$	657		$	(153	)	$	504		$	635		$	(26	)	$	609
	Nine Months Ended September 30, 2009									Nine Months Ended September 30, 2008
	GAAP (a)			Adjustments			Adjusted Non-GAAP			GAAP (a)			Adjustments			Adjusted Non-GAAP
Operating revenues	$	7,424		$	78	(b)	$	7,502		$	8,311		$	184	(b)	$	8,495
Operating expenses
Purchased power		962			129	(c)		1,091			1,704			210	(c)		1,914
Fuel		1,295			9	(c)		1,304			1,211			88	(c)		1,299
Operating and maintenance		2,210			(181	)(d),(e),(h)		2,029			2,023			25	(e)		2,048
Depreciation and amortization		223			—			223			202			—			202
Taxes other than income		150			—			150			153			—			153
Total operating expenses		4,840			(43	)		4,797			5,293			323			5,616
Operating income		2,584			121			2,705			3,018			(139	)		2,879
Other income and deductions
Interest expense, net		(77	)		2	(f)		(75	)		(108	)		—			(108	)
Equity in losses of investments		(2	)		—			(2	)		(1	)		—			(1	)
Other, net		325			(294	)(f),(g),(i)		31			(292	)		335	(g)		43
Total other income and deductions		246			(292	)		(46	)		(401	)		335			(66	)
Income from continuing operations before income taxes		2,830			(171	)		2,659			2,617			196			2,813
Income taxes		1,133			(125	)(b),(c),(d),(e),(f),(g),(h),(i)		1,008			891			159	(b),(c),(e),(g)		1,050
Income from continuing operations		1,697			(46	)		1,651			1,726			37			1,763
Loss from discontinued operations		—			—			—			(1	)		—			(1	)
Net income	$	1,697		$	(46	)	$	1,651		$	1,725		$	37		$	1,762

(a) Results reported in accordance with GAAP.

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

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

(d) Adjustment to exclude 2009 severance charges.

(e) Adjustment to exclude the reduction in Generation’s decommissioning obligation.

(f) Adjustment to exclude 2009 costs associated with early debt retirements.

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

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

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

11

EXELON CORPORATION

Reconciliation of Adjusted (non-GAAP) Operating Earnings to

GAAP Consolidated Statements of Operations

(unaudited)

(in millions)

	ComEd
	Three Months Ended September 30, 2009									Three Months Ended September 30, 2008
	GAAP (a)			Adjustments			Adjusted Non-GAAP			GAAP (a)			Adjustments			Adjusted Non-GAAP
Operating revenues	$	1,475		$	2	(c)	$	1,477		$	1,729		$	2	(c)	$	1,731
Operating expenses
Purchased power		776			—			776			1,068			—			1,068
Operating and maintenance		273			(2	)(c),(d)		271			306			—			306
Operating and maintenance for regulatory required programs (b)		19			—			19			11			—			11
Depreciation and amortization		125			—			125			119			—			119
Taxes other than income		79			—			79			87			—			87
Total operating expenses		1,272			(2	)		1,270			1,591			—			1,591
Operating income		203			4			207			138			2			140
Other income and deductions
Interest expense, net		(82	)		—			(82	)		(87	)		—			(87	)
Equity in losses of unconsolidated affiliates		—			—			—			(2	)		—			(2	)
Other, net		(19	)		—			(19	)		3			—			3
Total other income and deductions		(101	)		—			(101	)		(86	)		—			(86	)
Income before income taxes		102			4			106			52			2			54
Income taxes		56			2	(c),(d)		58			19			1	(c)		20
Net income	$	46		$	2		$	48		$	33		$	1		$	34
	Nine Months Ended September 30, 2009									Nine Months Ended September 30, 2008
	GAAP (a)			Adjustments			Adjusted Non-GAAP			GAAP (a)			Adjustments			Adjusted Non-GAAP
Operating revenues	$	4,417		$	4	(c)	$	4,421		$	4,594		$	5	(c)	$	4,599
Operating expenses
Purchased power		2,373			—			2,373			2,729			—			2,729
Operating and maintenance		796			(21	)(c),(d)		775			828			(4	)(c)		824
Operating and maintenance for regulatory required programs (b)		44			—			44			17						17
Depreciation and amortization		371			—			371			343			—			343
Taxes other than income		215			—			215			227			—			227
Total operating expenses		3,799			(21	)		3,778			4,144			(4	)		4,140
Operating income		618			25			643			450			9			459
Other income and deductions
Interest expense, net		(241	)		(6	)(e)		(247	)		(279	)		—			(279	)
Equity in losses of unconsolidated affiliates		—			—			—			(7	)		—			(7	)
Other, net		67			(60	)(e)		7			12			—			12
Total other income and deductions		(174	)		(66	)		(240	)		(274	)		—			(274	)
Income before income taxes		444			(41	)		403			176			9			185
Income taxes		169			(17	)(c),(d),(e)		152			66			4	(c)		70
Net income	$	275		$	(24	)	$	251		$	110		$	5		$	115

(a) Results reported in accordance with GAAP.

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

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

(d) Adjustment to exclude 2009 severance charges.

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

12

EXELON CORPORATION

Reconciliation of Adjusted (non-GAAP) Operating Earnings to

GAAP Consolidated Statements of Operations

(unaudited)

(in millions)

	PECO
	Three Months Ended September 30, 2009									Three Months Ended September 30, 2008
	GAAP (a)			Adjustments			Adjusted Non-GAAP			GAAP (a)			Adjustments		Adjusted Non-GAAP
Operating revenues	$	1,327		$	—		$	1,327		$	1,441		$	—	$	1,441
Operating expenses
Purchased power		625			—			625			693			—		693
Fuel		26			—			26			50			—		50
Operating and maintenance		154			2	(b)		156			192			—		192
Depreciation and amortization		272			—			272			243			—		243
Taxes other than income		78			—			78			73			—		73
Total operating expenses		1,155			2			1,157			1,251			—		1,251
Operating income		172			(2	)		170			190			—		190
Other income and deductions
Interest expense, net		(46	)		—			(46	)		(55	)		—		(55	)
Equity in losses of unconsolidated affiliates		(6	)		—			(6	)		(4	)		—		(4	)
Other, net		2			—			2			2			—		2
Total other income and deductions		(50	)		—			(50	)		(57	)		—		(57	)
Income before income taxes		122			(2	)		120			133			—		133
Income taxes		30			(1	)(b)		29			43			—		43
Net income	$	92		$	(1	)	$	91		$	90		$	—	$	90
	Nine Months Ended September 30, 2009									Nine Months Ended September 30, 2008
	GAAP (a)			Adjustments			Adjusted Non-GAAP			GAAP (a)			Adjustments		Adjusted Non-GAAP
Operating revenues	$	4,045		$	—		$	4,045		$	4,195		$	—	$	4,195
Operating expenses
Purchased power		1,742			—			1,742			1,859			—		1,859
Fuel		346			—			346			397					397
Operating and maintenance		481			(3	)(b)		478			557			—		557
Depreciation and amortization		726			—			726			653			—		653
Taxes other than income		213			—			213			203			—		203
Total operating expenses		3,508			(3	)		3,505			3,669			—		3,669
Operating income		537			3			540			526			—		526
Other income and deductions
Interest expense, net		(145	)		—			(145	)		(171	)		—		(171	)
Equity in losses of unconsolidated affiliates		(19	)		—			(19	)		(11	)		—		(11	)
Other, net		8			—			8			13			—		13
Total other income and deductions		(156	)		—			(156	)		(169	)		—		(169	)
Income before income taxes		381			3			384			357			—		357
Income taxes		106			2	(b)		108			111			—		111
Net income	$	275		$	1		$	276		$	246		$	—	$	246

(a) Results reported in accordance with GAAP.

(b) Adjustment to exclude 2009 severance charges.

13

EXELON CORPORATION

Reconciliation of Adjusted (non-GAAP) Operating Earnings to

GAAP Consolidated Statements of Operations

(unaudited)

(in millions)

		Other
	Three Months Ended September 30, 2009									Three Months Ended September 30, 2008
	GAAP (a)			Adjustments			Adjusted Non-GAAP			GAAP (a)			Adjustments			Adjusted Non-GAAP
Operating revenues	$	(908	)	$	—		$	(908	)	$	(1,015	)	$	—		$	(1,015	)
Operating expenses
Purchased power		(908	)		—			(908	)		(962	)		(51	)(d)		(1,013	)
Fuel		(1	)		—			(1	)		(1	)		—			(1	)
Operating and maintenance		1			(9	)(b)		(8	)		(13	)		—			(13	)
Depreciation and amortization		14			—			14			11			—			11
Taxes other than income		4			—			4			5			—			5
Total operating expenses		(890	)		(9	)		(899	)		(960	)		(51	)		(1,011	)
Operating loss		(18	)		9			(9	)		(55	)		51			(4	)
Other income and deductions
Interest expense, net		(36	)		1	(c)		(35	)		(27	)		—			(27	)
Equity in losses of unconsolidated affiliates and investments		(1	)		—			(1	)		—			—			—
Other, net		(27	)		36	(c)		9			1			—			1
Total other income and deductions		(64	)		37			(27	)		(26	)		—			(26	)
Loss before income taxes		(82	)		46			(36	)		(81	)		51			(30	)
Income taxes		(44	)		18	(b),(c)		(26	)		(23	)		20	(d)		(3	)
Net loss	$	(38	)	$	28		$	(10	)	$	(58	)	$	31		$	(27	)

	Nine Months Ended September 30, 2009									Nine Months Ended September 30, 2008
	GAAP (a)			Adjustments			Adjusted Non-GAAP			GAAP (a)			Adjustments		Adjusted Non-GAAP
Operating revenues	$	(2,684	)	$	—		$	(2,684	)	$	(2,734	)	$	—	$	(2,734	)
Operating expenses
Purchased power		(2,677	)		—			(2,677	)		(2,727	)		—		(2,727	)
Fuel		(1	)		—			(1	)		—			—		—
Operating and maintenance		5			(36	)(b),(e)		(31	)		(25	)		—		(25	)
Depreciation and amortization		40			—			40			32			—		32
Taxes other than income		14			—			14			14			—		14
Total operating expenses		(2,619	)		(36	)		(2,655	)		(2,706	)		—		(2,706	)
Operating loss		(65	)		36			(29	)		(28	)		—		(28	)
Other income and deductions
Interest expense, net		(92	)		16	(c),(f)		(76	)		(80	)		—		(80	)
Equity in losses of unconsolidated affiliates and investments		—			—			—			—			—		—
Other, net		(33	)		46	(c),(f)		13			11			—		11
Total other income and deductions		(125	)		62			(63	)		(69	)		—		(69	)
Loss before income taxes		(190	)		98			(92	)		(97	)		—		(97	)
Income taxes		(69	)		43	(b),(c),(d),(e),(f)		(26	)		(46	)		—		(46	)
Net loss	$	(121	)	$	55		$	(66	)	$	(51	)	$	—	$	(51	)

(a) Results reported in accordance with GAAP.

(b) Adjustment to exclude external costs associated with Exelon’s proposed acquisition of NRG, which was terminated in July 2009.

(c) Adjustment to exclude 2009 costs associated with early debt retirements.

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

(e) Adjustment to exclude 2009 severance charges.

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

14

EXELON CORPORATION

Exelon Generation Statistics

	Three Months Ended
	Sept. 30, 2009		Jun. 30, 2009		Mar. 31, 2009		Dec. 31, 2008		Sept. 30, 2008
Supply (in GWhs)
Nuclear		35,684		34,995		35,382		34,887		36,451
Purchased Power		6,669		5,276		6,077		6,100		8,761
Fossil and Hydro		2,689		2,701		2,765		2,162		2,685
Power Team Supply		45,042		42,972		44,224		43,149		47,897
	Three Months Ended
	Sept. 30, 2009		Jun. 30, 2009		Mar. 31, 2009		Dec. 31, 2008		Sept. 30, 2008
Electric Sales (in GWhs)
ComEd (a)		3,639		4,215		5,537		5,261		6,629
PECO (a)		10,809		9,277		10,223		9,760		11,333
Market and Retail (a)		30,594		29,480		28,464		28,128		29,935
Total Electric Sales (b) (c)		45,042		42,972		44,224		43,149		47,897
Average Margin ($/MWh)
Average Realized Revenue
ComEd (a)	$	64.03	$	63.58	$	63.21	$	63.30	$	64.41
PECO (a)		51.35		51.74		49.30		49.28		53.03
Market and Retail (a)		52.99		54.27		57.12		54.18		65.98
Total Electric Sales		53.48		54.64		56.08		54.18		62.70
Average Purchased Power and Fuel Cost (d)	$	17.16	$	15.68	$	16.82	$	15.90	$	26.16
Average Margin (d)	$	36.32	$	38.96	$	39.25	$	38.28	$	36.54
Around-the-clock Market Prices ($/MWh) (e)
PJM West Hub	$	33.20	$	33.70	$	49.18	$	52.62	$	77.37
NiHub		25.69		26.11		34.09		38.06		53.28

(a) $104 million, $69 million, $31 million and $20 million of pre-tax revenue, and $15 million of a pre-tax reduction in revenue, resulting from the settlement of the ComEd swap starting in June 2008, have been excluded from ComEd and included in Market and Retail sales for the quarters ended September 30, 2009, June 30, 2009, March 31, 2009, December 31, 2008 and September, 30, 2008, respectively. Additionally, $11 million (397 GWhs), $7 million (209 GWhs), $58 million (898 GWhs), and $29 million (486 GWhs) of pre-tax revenue, resulting from sales to ComEd under the RFP, which started in September 2008, have been excluded from ComEd and included in Market and Retail sales for the quarters ended September 30, 2009, June 30, 2009, March 31, 2009 and December 31, 2008, respectively. In addition, renewable energy credits sales to affiliates have been included within Market and Retail Sales.

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

(c) Total sales do not include trading volume of 1,645 GWhs, 2,003 GWhs, 2,331 GWhs, 2,153 GWhs and 3,092 GWhs for the three months ended September 30, 2009, June 30, 2009, March 31, 2009, December 31, 2008 and September 30, 2008, respectively.

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

(e) Represents the average for the quarter.

15

EXELON CORPORATION

Exelon Generation Statistics

Nine Months Ended September 30, 2009 and 2008

	September 30, 2009		September 30, 2008
Supply (in GWhs)
Nuclear		106,061		104,454
Purchased Power		18,022		20,164
Fossil and Hydro		8,155		8,407
Power Team Supply		132,238		133,025
	September 30, 2009		September 30, 2008
Electric Sales (in GWhs)
ComEd (a)		13,391		17,939
PECO (a)		30,309		31,206
Market and Retail (a)		88,538		83,880
Total Electric Sales (b) (c)		132,238		133,025
Average Margin ($/MWh)
Average Realized Revenue
ComEd (a)	$	63.55	$	63.83
PECO (a)		50.78		51.34
Market and Retail (a)		54.74		61.93
Total Electric Sales		54.70		59.70
Average Purchased Power and Fuel Cost (d)	$	16.58	$	21.16
Average Margin (d)	$	38.12	$	38.54
Around-the-clock Market Prices ($/MWh) (e)
PJM West Hub	$	38.64	$	73.86
NiHub		28.59		52.68

(a) $204 million of pre-tax revenue, and $22 million of a pre-tax reduction in revenue, resulting from the settlement of the ComEd swap starting in June 2008, have been excluded from ComEd and included in Market and Retail sales for the nine months ended September 30, 2009 and September 30, 2008, respectively. Additionally, $76 million (1,504 GWhs) of pre-tax revenue, resulting from sales to ComEd under the RFP, which started in September 2008, have been excluded from ComEd and included in Market and Retail sales for the nine months ended September 30, 2009. In addition, renewable energy credits sales to affiliates have been included within Market and Retail Sales.

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

(c) Total sales do not include trading volume of 5,979 GWhs and 6,738 GWhs for the nine months ended September 30, 2009 and 2008, respectively.

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

(e) Represents the average for the year.

16

EXELON CORPORATION

ComEd Statistics

Three Months Ended September 30, 2009 and 2008

	Electric Deliveries (in GWhs)				Revenue (in millions)
	2009	2008	% Change		2009		2008		% Change
Full Service (a)
Residential	6,983	8,114	(13.9	)%	$	797	$	950	(16.1	)%
Small Commercial & Industrial	3,494	4,047	(13.7	)%		333		428	(22.2	)%
Large Commercial & Industrial	295	319	(7.5	)%		17		31	(45.2	)%
Public Authorities & Electric Railroads	98	168	(41.7	)%		10		14	(28.6	)%
Total Full Service	10,870	12,648	(14.1	)%		1,157		1,423	(18.7	)%
Delivery Only (b)
Residential (c)	1	—	n.m.			—		—	n.m.
Small Commercial & Industrial	4,954	4,932	0.4	%		88		75	17.3	%
Large Commercial & Industrial	6,627	7,379	(10.2	)%		85		78	9.0	%
Public Authorities & Electric Railroads	189	137	38.0	%		3		2	50.0	%
Total Delivery Only	11,771	12,448	(5.4	)%		176		155	13.5	%
Total Retail	22,641	25,096	(9.8	)%		1,333		1,578	(15.5	)%
Other Revenue (d)						142		151	(6.0	)%
Total Revenues					$	1,475	$	1,729	(14.7	)%
Purchased Power					$	776	$	1,068	(27.3	)%
Heating and Cooling Degree-Days (e)	2009	2008	Normal
Heating Degree-Days	77	53	110
Cooling Degree-Days	412	626	624

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

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

(c) There were a minimal number of residential customers being served by alternative electric generation suppliers with total revenue of less than $1 million.

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

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

n.m. Not meaningful.

Nine Months Ended September 30, 2009 and 2008

	Electric Deliveries (in GWhs)				Revenue (in millions)
	2009	2008	% Change		2009		2008		% Change
Full Service (a)
Residential	20,078	21,521	(6.7	)%	$	2,374	$	2,444	(2.9	)%
Small Commercial & Industrial	10,445	11,392	(8.3	)%		1,038		1,169	(11.2	)%
Large Commercial & Industrial	924	803	15.1	%		56		73	(23.3	)%
Public Authorities & Electric Railroads	305	481	(36.6	)%		32		40	(20.0	)%
Total Full Service	31,752	34,197	(7.1	)%		3,500		3,726	(6.1	)%
Delivery Only (b)
Residential (c)	1	—	n	.m.		—		—	n.m.
Small Commercial & Industrial	13,892	14,029	(1.0	)%		244		211	15.6	%
Large Commercial & Industrial	19,240	21,133	(9.0	)%		238		215	10.7	%
Public Authorities & Electric Railroads	603	423	42.6	%		10		5	100.0	%
Total Delivery Only	33,736	35,585	(5.2	)%		492		431	14.2	%
Total Retail	65,488	69,782	(6.2	)%		3,992		4,157	(4.0	)%
Other Revenue (d)						425		437	(2.7	)%
Total Revenues					$	4,417	$	4,594	(3.9	)%
Purchased Power					$	2,373	$	2,729	(13.0	)%
Heating and Cooling Degree-Days (e)	2009	2008	Normal
Heating Degree-Days	4,165	4,225	4,084
Cooling Degree-Days	589	818	848

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

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

(c) There were a minimal number of residential customers being served by alternative electric generation suppliers with total revenue of less than $1 million.

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

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

n.m. Not meaningful.

17

EXELON CORPORATION

PECO Statistics

Three Months Ended September 30, 2009 and 2008

	Electric and Gas Deliveries				Revenue (in millions)
	2009	2008	% Change		2009		2008		% Change
Electric (in GWhs)
Full Service (a)
Residential	3,501	3,802	(7.9	)%	$	547	$	591	(7.4	)%
Small Commercial & Industrial	2,128	2,258	(5.8	)%		286		293	(2.4	)%
Large Commercial & Industrial	4,294	4,445	(3.4	)%		339		376	(9.8	)%
Public Authorities & Electric Railroads	233	221	5.4	%		22		22	0.0	%
Total Full Service	10,156	10,726	(5.3	)%		1,194		1,282	(6.9	)%
Delivery Only (b)
Residential	5	9	(44.4	)%		1		1	0.0	%
Small Commercial & Industrial	95	131	(27.5	)%		5		7	(28.6	)%
Large Commercial & Industrial	7	1	600.0	%		—		—	0.0	%
Total Delivery Only	107	141	(24.1	)%		6		8	(25.0	)%
Total Electric Retail	10,263	10,867	(5.6	)%		1,200		1,290	(7.0	)%
Other Revenue (c)						65		76	(14.5	)%
Total Electric Revenue						1,265		1,366	(7.4	)%
Gas (in mmcfs)
Retail Sales	3,694	3,794	(2.6	)%		55		70	(21.4	)%
Transportation and Other	6,145	6,455	(4.8	)%		7		5	40.0	%
Total Gas	9,839	10,249	(4.0	)%		62		75	(17.3	)%
Total Electric and Gas Revenues					$	1,327	$	1,441	(7.9	)%
Purchased Power					$	625	$	693	(9.8	)%
Fuel						26		50	(48.0	)%
Total Purchased Power and Fuel					$	651	$	743	(12.4	)%
Heating and Cooling Degree-Days	2009	2008	Normal
Heating Degree-Days	19	12	36
Cooling Degree-Days	884	942	939

Nine Months Ended September 30, 2009 and 2008

	Electric and Gas Deliveries				Revenue (in millions)
	2009	2008	% Change		2009		2008		% Change
Electric (in GWhs)
Full Service (a)
Residential	9,788	10,151	(3.6	)%	$	1,428	$	1,485	(3.8	)%
Small Commercial & Industrial	6,155	6,257	(1.6	)%		787		793	(0.8	)%
Large Commercial & Industrial	11,961	12,520	(4.5	)%		995		1,074	(7.4	)%
Public Authorities & Electric Railroads	702	681	3.1	%		68		66	3.0	%
Total Full Service	28,606	29,609	(3.4	)%		3,278		3,418	(4.1	)%
Delivery Only (b)
Residential	17	24	(29.2	)%		2		2	0.0	%
Small Commercial & Industrial	277	370	(25.1	)%		15		20	(25.0	)%
Large Commercial & Industrial	9	3	200.0	%		—		—	0.0	%
Total Delivery Only	303	397	(23.7	)%		17		22	(22.7	)%
Total Electric Retail	28,909	30,006	(3.7	)%		3,295		3,440	(4.2	)%
Other Revenue (c)						200		212	(5.7	)%
Total Electric Revenue						3,495		3,652	(4.3	)%
Gas (in mmcfs)
Retail Sales	39,444	36,979	6.7	%		530		522	1.5	%
Transportation and Other	20,128	20,806	(3.3	)%		20		21	(4.8	)%
Total Gas	59,572	57,785	3.1	%		550		543	1.3	%
Total Electric and Gas Revenues					$	4,045	$	4,195	(3.6	)%
Purchased Power					$	1,742	$	1,859	(6.3	)%
Fuel						346		397	(12.8	)%
Total Purchased Power and Fuel					$	2,088	$	2,256	(7.4	)%
Heating and Cooling Degree-Days (d)	2009	2008	Normal
Heating Degree-Days	2,967	2,744	3,004
Cooling Degree-Days	1,236	1,335	1,271

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

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

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

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

18

EX-99.2

Earnings Conference Call •

3

rd

Quarter 2009

October 23, 2009

Exhibit 99.2

2

Forward-Looking Statements

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

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

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

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

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

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

Supplementary Data: Note 18; (2) Exelon’s Third Quarter 2009 Quarterly Report on Form 10-Q (to

be filed on October 23, 2009) in (a) Part II, Other Information, ITEM 1A. Risk Factors and (b) Part I,

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

filings with the Securities and Exchange Commission (SEC) by Exelon Corporation,

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

(Companies). Readers are cautioned not to place undue reliance on these forward-looking

statements, which apply only as of the date of this presentation. None of the Companies

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

reflect events or circumstances after the date of this presentation.

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

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

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

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

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

Please refer to the footnotes of the following slides for a reconciliation non-GAAP cash flows to

GAAP cash flows.

3

Q3 Highlights

Financial:

•

Delivering consistent operating performance

•

Exceeding 2009 cost savings target

•

Narrowing 2009 EPS guidance range

Energy Markets:

•

Second PECO procurement completed

•

Illinois Power Agency procurement plan proposed

Regulatory:

•

Focus on improved results for ComEd and PECO

•

Filed plans for Smart Grid and Smart Meter investments

•

Successful relicensing of TMI nuclear unit

Climate Change:

•

Advocating for greenhouse gas-reduction legislation

•

Collaboration among industry and other key stakeholders

4

Key Financial Messages

Q3 operating results of $0.96/share driven by:

•

Cost discipline –

exceeded 2009 cost savings target with over $80 million of

savings in third quarter

•

94.7% nuclear capacity factor

•

Cooler than normal weather of $0.04/share at ComEd and $0.03/share at

PECO

Narrowing 2009 operating earnings guidance to $4.00-$4.10/share

•

Committed to an additional $100 million of one-time O&M savings in 2009

Well-positioned for continued financial strength and flexibility

•

Increased 2009 forecasted cash flow from operations

(1)

to $5.6 billion for

2009 -

$850 million higher than original plan

•

$350 million discretionary pension contribution

•

$1.5 billion tender/make whole and refinancing at Exelon and Exelon

Generation

Refer

to

Earnings

Release

Attachments

for

additional

details

and

to

the

Appendix

for

a

reconciliation

of

adjusted

(non-GAAP)

operating

EPS

to

GAAP

EPS.

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

other than capital expenditures.

Note: Data contained on this slide is rounded.

5

$0.92

$0.14

$0.76

$0.14

$0.05

$0.07

2008

2009

Operating EPS

$2.66

$0.37

$2.50

$0.42

$0.17

$0.38

2008

2009

HoldCo/Other

ExGen

PECO

ComEd

3

rd

Quarter (Q3)

(1)

Exceeding cost savings target allowed Exelon to deliver results within our range

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

$1.06

$1.14

GAAP EPS

Year-to-Date (YTD)

(1)

$3.19

$3.13

$3.06

$3.21

$0.96

$1.07

6

Exelon Generation                         

Operating EPS Contribution

2009

2008

Key Drivers –

Q3 ’09 vs. Q3 ’08

(1)

Unfavorable portfolio/market conditions:

$(0.06)

Lower nuclear volume and higher

nuclear fuel costs: $(0.04)

Higher income tax expense: $(0.04)

Higher costs due to pension and OPEB

expense and refueling outages, partially

offset by cost savings initiatives: $(0.02)

Reversal of Q1 IL tax ruling:  $(0.01)

’08 reserve associated with Lehman

bankruptcy: +$0.02

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

(2) Outage days exclude Salem. 

36

17

Refueling

21

8

Non-refueling

Q3 2009

Q3 2008

Outage Days

(2)

3Q

YTD

$0.92

$0.76

$2.50

$2.66

7

Represents an approximate range of expected gross margin, taking into account hedges in place, between the 5th and 95th percentile confidence levels.  Approximate gross margin

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

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

those years. The price distributions that generate this range are calibrated to market quotes for power, fuel, load following products and options as of September 30, 2009.

Percent of expected generation hedged represents how many equivalent MW have been hedged at forward market prices as of September 30, 2009;  all hedge products used are

converted to an equivalent average MW volume and the calculation considers whether hedges are power sales or financial products.

Hedging Update

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

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

preserving our ability to participate in improving long-term market fundamentals

•

We typically follow a 36-month ratable

hedging program

•

As we execute our hedging program, our

percent of expected generation hedged

increases and our potential range of

earnings outcomes narrows as we move

closer to the delivery year

2009

2010

2011

Percentage of Expected

Generation Hedged

(2)

98-100%

88-91%

63-66%

Midwest

98-100

88-91

67-70

Mid-Atlantic

97-99

91-94

56-59

South

98-100

90-93

52-55

•

We employ natural gas and power put

options within the portfolio to allow us to

reduce market risk while preserving

upside potential

95% case

5% case

$6,700

$6,600

$6,100

$6,500

$6,000

$8,200

$4,000

$5,000

$6,000

$7,000

$8,000

$9,000

$10,000

2009

2010

2011

(1)

(2)

8

Key Drivers –

Q3 ’09 vs. Q3 ’08

(1)

Higher electric distribution rates:

+$0.06

Net impact of 2008 write-offs

associated with final distribution rate

order: +$0.02

Lower O&M due to cost savings

initiatives and decreased storm costs

partially offset by higher pension and

OPEB expense and inflation:

+$0.01

Reversal of Q1 IL tax ruling: $(0.05)

Weather: $(0.03)

Reduced load: $(0.01)

ComEd Operating EPS Contribution

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

2009

2008

3Q

YTD

$0.05

$0.07

$0.38

$0.17

Q3

Actual

Normal

Days >90 degrees

1

11

Cooling Degree Days

412

624

9

-10.0%

-7.5%

-5.0%

-2.5%

0.0%

2.5%

5.0%

7.5%

10.0%

09Q1

09Q2

09Q3

09Q4E

10Q1E

10Q2E

10Q3E

10Q4E

-10.0%

-7.5%

-5.0%

-2.5%

0.0%

2.5%

5.0%

7.5%

10.0%

All Customer Classes

Large C&I

Residential

Gross Metro Product (right axis)

ComEd Load Trends

Weather-Normalized Load

Key Economic Indicators

Note: C&I = Commercial & Industrial

Weather-Normalized Load Year-over-Year

(4)

Chicago

U.S.

Unemployment

rate

(1)

10.5%

9.8%

2009 annualized growth in

gross

domestic/metro

product

(2)

(3.7)%

(2.6)%

7/09

Home

price

index

(3)

(14.2)%

(13.3)%

(1)  Source: Illinois Dept. of Employment Security (October 2009) and U.S.

Dept. of Labor (October 2009)

(2)

Source: Moody’s Economy.com (September 2009)

(3)

Source: S&P Case-Shiller Index

(4)

Not adjusted for leap year effect

Q309

Q409E       2009E

(4)

2010E

Customer Growth

(0.5)%

(0.6)%

(0.4)%

0.1%

Average Use-Per-Customer

0.1%

(0.7)%

(0.9)%

(0.1)%

Total Residential

(0.4)%

(1.3)%

(1.3)%

0.0%

Small C&I

(2.9)%

(0.8)%

(2.4)%

1.0%

Large C&I

(8.6)%

(4.1)%

(6.7)%

1.5%

All Customer Classes

(3.8)%

(1.9)%

(3.4)%

0.8%

10

PECO Operating EPS Contribution

Key Drivers –

Q3 ’09 vs. Q3 ’08

(1)

Lower bad debt expense: +$0.04

Higher other revenue net fuel, including

gas distribution revenues: +$0.02

Competitive Transition Charge (CTC)

amortization: $(0.03)

Reduced load: $(0.03)

Weather: $(0.01)

2009

2008

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

3Q

YTD

$0.14

$0.14

$0.42

$0.37

Q3

Actual

Normal

Days >90 degrees

6

18

Cooling Degree Days

884

939

11

PECO Load Trends

Weather-Normalized Electric Load

Key Economic Indicators

Weather-Normalized Load Year-over-Year

(3)

Philadelphia

U.S.

Unemployment

rate

(1)

8.5%                   9.8%

2009 annualized growth in

gross

domestic/metro

product

(2)

(3.4)%              (2.6)%

(1)  Source:

U.S

Dept.

of

Labor

(PHL

August

2009,

US

–

October

2009)

(2)  Source: Moody’s Economy.com (September 2009)

(3)  Not adjusted for leap year effect

-10.0%

-7.5%

-5.0%

-2.5%

0.0%

2.5%

5.0%

7.5%

10.0%

09Q1

09Q2

09Q3

09Q4E

10Q1E

10Q2E

10Q3E

10Q4E

-10.0%

-7.5%

-5.0%

-2.5%

0.0%

2.5%

5.0%

7.5%

10.0%

All Customer Classes

Large C&I

Residential

Gross Metro Product (right axis)

Note: C&I = Commercial & Industrial

Q309

Q409E      2009E

(3)

2010E

Customer Growth

(0.4)%

(0.4)%

(0.3)%

(0.0)%

Average Use-Per-Customer

(5.1)%

(0.4)%

(2.2)%

(0.5)%

Total Residential

(5.5)%

(0.8)%

(2.5)%

(0.6)%

Small C&I

(5.1)%

(3.4)%

(2.7)%

(0.8)%

Large C&I

(2.2)%

(1.7)%

(3.0)%

(2.3)%

All Customer Classes

(3.9)%

(1.8)%

(2.7)%

(1.3)%

12

Delivering on Cost Savings Commitments

•

On track to exceed promised cost savings in 2009

–

Identified $100 million

of additional one-time cost saving opportunities for 2009

Projected to exceed cost management goal in 2009 by $100 million

Note: Data contained on this slide is rounded.

$4.5B

(2)(3)

$4.5B

(2)

$4.4B

(2)(3)

(1)  Reflects operating O&M data and excludes decommissioning effect. ComEd and PECO operating O&M exclude energy efficiency costs recoverable under a rider.

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

(3)  Reflects ~$175 million increase in operating O&M expense from 2008A to 2009E due to higher pension and OPEB expense.

O&M

Expense

(1)

2008A

2009 Original Commitment

2009 Revised Forecast

13

Financial Flexibility

Increased Future Cash Flexibility

Lowered Cost of Debt

In the third quarter, Exelon capitalized on strategic opportunities to

create future financial flexibility

•

$350 million discretionary 2008

pension contribution

•

Lowered estimated 2011

contribution by $1 billion

•

Smoothing election

(1)

lowers

volatility in future contributions

•

Used cash on hand

•

Successfully executed $1.5

billion tender/make whole

and refinancing

•

Expected to lower annual

interest expense by

approximately $12 million

•

Extended average maturity of

Generation/Corporate debt

portfolio by 6.6 years

(1) 

Contributions reflect the impact of electing the option to smooth asset returns provided under the Worker, Retiree and Employer Recovery Act of 2008, which allows the use of average

assets,

including

expected

returns

(subject

to

certain

limitations)

for

a

24-month

period

prior

to

the

measurement

date,

in

the

determination

of

funding

requirements.

14

Appendix

15

2009 Operating Earnings Guidance

2009E

2008A

$0.49

$3.46

$4.20

ComEd

PECO

Exelon

Generation

2009 Earnings Drivers

ComEd

PECO

Exelon

Generation

Holdco

Holdco

Exelon

$0.33

Exelon

$4.00 -

$4.10

(1)

$0.50 -

$0.55

$0.45 -

$0.50

$3.10 -

$3.15

(1)

Adjusted

(non-GAAP)

Operating

Earnings

Guidance.

Excludes

the

earnings

effect

of

certain

items

as

disclosed

in

the

Appendix.

Note: A = Actual; E = Estimate

Narrowing

2009

operating

earnings

guidance

to

$4.00-$4.10/share

(1)

O&M and other

Pension/OPEB

Inflation

Cost reduction initiatives

Bad debt expense

ComEd

distribution revenue

PECO gas revenue

Weather

Load

Nuclear fuel costs

Depreciation and amortization

PECO CTC

16

ComEd Smart Grid/Smart Meter

•

Smart

Meter

(or

Advanced

Metering

Infrastructure

-

AMI)

Pilot

–

ICC approved on October 14, 2009

–

1-year

pilot

program

for

131,000

smart

meters

and

related

programs

(~$70

million

in

2009-2010)

–

Recovery with regulated return for capital investment expected to begin in 2010 through a rider

•

Federal Stimulus Funding

–

Request for $175 million in matching funds made on August 4, 2009

–

Investment would occur through 2011

Projected Spend

$ millions

$350

$23

$78

$107

$139

Total

$92

$6

--

$84

--

Transmission

$78

Distribution Automation

$23

Communication Support Systems

$139

AMI & Customer Applications

$258

$17

Distribution

TOTAL

Intelligent Substation

Project

Note: Totals may not add due to rounding.  ComEd includes approximately $4 million of unallocated contract expense

that will be distributed to specific projects upon finalization of scope.

ComEd’s Smart Grid project expands the AMI pilot and provides for

regulated returns on our investments

17

PECO Smart Grid/Smart Meter

•

PECO

intends

to

invest

up

to

$650

million

in

its

Smart

Grid/Smart

Meter

Infrastructure

(1)

–

$550

million

Advanced

Metering

Infrastructure

over

10

–

15

years

–

$100 million for Smart Grid over 3 years subject to stimulus funding

•

Federal Stimulus Grant application for $200 million of matching funds filed August 6, 2009

–

Amount

and

timing

of

spend

will

depend

on

approval

of

Federal

Stimulus

Grant

and

supplier

RFPs

•

Smart Meter investment required by Act 129, which provides for recovery through

surcharge including a return on capital investment

•

Smart Grid investment to be recovered through transmission and distribution rates

($ millions pre-tax)

2010

2011

2012

Total

Act 129 Smart Meter Deployment (over 10-15 years)

45

$    

125

$  

45

$    

215

$       

Smart Grid Base Case

15

20

15

50

60

$    

145

$  

60

$    

265

$       

($ millions pre-tax)

2010

2011

2012

Total

Act 129 Smart Meter Expanded Initial Deployment (600K meters by 2012)

40

$    

150

$  

100

$  

290

$       

Smart Grid Stimulus Case

50

45

15

110

Total Stimulus Case

90

195

115

400

Stimulus Grant Request

(45)

(100)

(55)

(200)

Total Expenditures net of Stimulus grant

45

$    

95

$    

60

$    

200

$       

(1) Does not include $100 million for potential replacement of gas meters and wind-down of legacy Automated Meter Reading system.

(2) Amounts included in base case assumptions for capital spend.

(3) Assumes 100% of matching funds requested by DOE.

Data contained in this slide is rounded

2010-2012

Spend

Without

Federal

Stimulus

Grant

(2)

:

2010-2012

Spend

With

Federal

Stimulus

Grant

(3)

:

18

Illinois Power Agency RFP Procurement

•

On September 30, 2009, the IPA submitted an Updated Procurement Plan for the

2010/11 planning period

•

Similar to 2009, the Procurement Plan for the 2010/11 planning period includes the

procurement of monthly peak and off-peak standard wholesale block energy products

•

The IPA’s Plan also calls for the procurement of 1,887,014 MWh of Renewable Energy

Credits

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

Next RFP to be held in Spring 2010

Delivery

Period

Peak

Off-Peak

June 2010 -

May 2011

5,390

4,538

June 2011 -

May 2012

1,858

668

Volumes to be secured in 2010

IPA Procurement Event (GWh)

2009 RFP

2009 RFP

2010 RFP

2010 RFP

2011 RFP

2011 RFP

2012 RFP

2009

2010

2011

2012

Financial

Swap

Auction

Contract

19

PECO Procurement Results

PECO has completed two of the four procurements for the power needed to serve its

residential customers beginning in 2011

•

On September 23, 2009, the PAPUC approved the bids from PECO’s second RFP

(1)

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

(2)

Wholesale prices; no Small/Medium Commercial products were procured in the June RFP.

Residential

Sept RFP average price of

$79.96/MWh

(2)

June RFP average price of

$88.61/MWh

(2)

49% of full requirements product

procured

80 MW of block energy procured

Small and Medium Commercial

Sept RFP average blended price

of $85.85/MWh

(2)

24% of Small Commercial full

requirements product procured

16% of Medium Commercial full

requirements product procured

85% full requirements

15% full requirements spot

Medium Commercial &

Industrial

(peak demand >100 kW

but <= 500 kW)

100% full requirements spot

Large Commercial &

Industrial

(peak demand >500 kW)

90% full requirements

10% full requirements spot

75% full requirements

20% block energy

5% energy only spot

Products

Small Commercial

(peak demand <100 kW)

Residential

Customer Class

PECO

Procurement

Plan

(1)

Total Procured (including

June and September RFPs)

Residential

23% of planned full requirements

contracts (17 and 29-mo terms)

140 MW of baseload (24x7)

block energy products (12, 24

and 60-mo duration)

40 MW of Jan-Feb 2011 on-peak

block energy

Small Commercial

36% of planned full requirements

contracts (17 and 29-mo term)

Medium Commercial & Industrial

42% of planned full requirements

contracts (17-mo term)

May 24, 2010 RFP

20

5.03

5.03

0.51

0.51

6.26

2.57

9.41

PECO Average Residential Electric Rates

(1)

Average of PECO’s residential rates.

(2)

Provided for illustration only.  Represents 49% of PECO’s full requirements residential procurement for 2011.

(3)

Average wholesale price for full requirements products. Full requirements product includes load following energy, capacity, ancillary transmission services and

Alternative Energy Portfolio Standard requirements.

(4)

Does not include energy efficiency or changes in distribution rates.

2011

2010

Energy / Capacity

Competitive Transition

Charge (CTC)

Transmission

Distribution

14.37¢

(1)

Unit Rates (¢/kWh)

Electric Restructuring

Settlement

~4%

(4)

14.95¢

(1)

Assumptions

Illustrative Rate Increase Based on

Average PECO Residential Full

Requirements Procurement Results

(2)

•

2011 illustrative residential rate based on

Spring and Fall 2009 RFPs full

requirements product prices

•

Actual 2011 default service residential

rate will reflect associated full

requirements costs, block energy costs,

and spot market purchases, all of which

will be acquired through multiple

procurements

•

Rates will vary by customer class

•

Retail rate components include line losses

and gross receipts taxes

Spring 2009

$88.61 / MWH

PECO Residential

Procurement Results

(3)

Effect

of

Spring

and

Fall

2009

Procurements

Fall 2009

$79.96 / MWH

Wholesale Results

21

Estimated Build-Up of PECO Average

Residential Full Requirements Price

$91.60/MWh

$28.50-

$29.50

$50.50 -

$51.50

Full Requirements Costs ($/MWh)

Average Full Requirements                          

Retail Sales Price

(1)

Load Shape &

Ancillary Services

$7.50 

Capacity

$12.00

Transmission &

Congestion

$7.00 -

$8.00

Renewable

Energy

Credits

$1.00

Migration,

Volumetric

Risk & Other

$1.00

~$6.50

~$5.50

Average

Wholesale

Energy Price

$79.96

(2)

21

(1)

As provided by Exelon Generation 

(2)

On Oct 21, 2009 the Independent Evaluator (NERA) announced a wholesale winning bid average price of $79.96/MWh for PECO’sFall 2009 RFP (reflecting 17 & 29-month

residential full requirements’ products with delivery beginning Jan 1, 2011).

22

Q3 07

Q3 08

Q3 09

ComEd and PECO Accounts Receivable

ComEd Accounts

Receivable

(1)

Through

the

third

quarter

of

2009,

both

ComEd

and

PECO

have

experienced

an

improvement in accounts receivable aging

Q3 07

Q3 08

Q3 09

PECO Accounts

Receivable

(1)

% of AR

$862M

$710M

$789M

$782M

$779M

$714M

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

>60

days

31-60 days

0-30 days

Note: Data contained on this slide is rounded.

23

23

2009 Projected Sources and Uses of Cash

(250)

n/a

(50)

(200)

Utility Growth CapEx

(4)

(925)

(925)

n/a

n/a

Nuclear Fuel

(200)

(200)

n/a

n/a

Nuclear Uprates and Solar Project

(1,400)

Dividend

(3)

$ (in millions)

Exelon

(8)

Beginning Cash Balance

(1)

$500

Cash Flow from Operations

(1)(2)

1,125

1,000

3,400

5,600

CapEx (excluding Nuclear Fuel, Nuclear Uprates

and Solar Project, Utility Growth CapEx)

(675)

(350)

(925)

(2,000)

Net Financing (excluding Dividend):

Planned Debt Issuances

(5)

0

250

1,500

1,750

Planned Debt Retirements

(6)

0

(750)

(1,000)

(2,250)

Other

(7)

50

250

50

(100)

Ending Cash Balance

(1)

$725

Note: Data contained on this slide is rounded.

(1)

Excludes counterparty collateral activity.

(2)

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

Cash Flow from Operations reflects the $350M pre-tax discretionary pension contribution. Cash Flow from Operations for PECO and Exelon includes $500M for Competitive

Transition Charges.

(3)

Assumes 2009 Dividend of $2.10 pershare.  Dividends are subject to declaration by the Board of Directors.

(4)

Represents new business and smart grid/meter investment.

(5)

Excludes ComEd  tax-exempt bonds that are backed by letters of credit (LOCs).  ComEd reissued $191M of tax exempt debt in May backed by LOCs.  Excludes PECO’s

Accounts Receivable (A/R) Agreement with Bank of Tokyo.

(6)

Planned Debt Retirements at ComEd and Exelon Corporate are $17M and $500M, respectively.  Includes securitized debt at PECO and $307M repurchase of tax exempt

debt at Exelon Generation.

(7)

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

(8)

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

24

Sufficient Liquidity

(1)  Excludes previous commitment from Lehman Brothers Bank and excludes $66 million of bank commitments from Exelon’s Community and Minority Bank Credit Facility.

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

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

(3)  Includes other corporate entities.

(35)

--

--

(35)

Outstanding Facility Draws

(409)

(154)

(10)

(241)

Outstanding Letters of Credit

$7,317

$4,834

$574

$952

Aggregate Bank Commitments

(1)

6,873

4,680

564

676

Available

Capacity

Under

Facilities

(2)

--

--

--

--

Outstanding Commercial Paper

$6,873

$4,680

$564

$676

Available Capacity Less Outstanding

Commercial Paper

Exelon

(3)

($ in Millions)

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

Available Capacity Under Bank Facilities as of October 15, 2009

25

Projected 2009 Key Credit Measures

BBB

A-

A-

BBB-

S&P Credit

Ratings

(3)

BBB+

A

BBB

BBB+

Fitch Credit

Ratings

(3)

A3

A2

Baa1

Baa1

Moody’s Credit

Ratings

(3)

4.5x

4.5x

FFO / Interest

ComEd:

23%

17%

FFO / Debt

42%

49%

Rating Agency Debt Ratio

3.4x

3.2x

FFO / Interest

PECO:

14%

12%

FFO / Debt

48%

53%

Rating Agency Debt Ratio

30%

50%

Rating Agency Debt Ratio

125%

55%

FFO / Debt

36.5x

12.5x

FFO / Interest

Exelon

Generation:

49%

43%

8.7x

Without PPA &

Pension / OPEB

(2)

60%

Rating Agency Debt Ratio

28%

FFO / Debt

6.8x

FFO / Interest

Exelon

Consolidated:

With PPA & Pension /

OPEB

(1)

Notes: Exelon

and

PECO

metrics

exclude

securitization

debt.

See

following

slide

for

FFO

(Funds

from

Operations)/Interest,

FFO/Debt

and

Adjusted

Book

Debt

Ratio

reconciliations

to

GAAP.

(1)

FFO/Debt metrics include the following standard adjustments:  imputed debt and interest related to purchased power agreements (PPA), unfunded pension and other postretirement

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

obligations by operating company.

(2)

Excludes items listed in note (1) above.

(3)

Current senior unsecured ratings for Exelon and Exelon Generation and senior secured ratings for ComEd and PECO as of October 15, 2009.  On August 3, 2009, Moody’s upgraded

ComEd’s

senior

secured

credit

rating

to

Baa1

from

Baa2

due

to

a

change

in

Moody’s

rating

methodology.

26

FFO Calculation and Ratios

FFO Calculation

= FFO

-

PECO Transition Bond Principal Paydown

+ Gain

on

Sale,

Extraordinary

Items

and

Other

Non-Cash

Items

(3)

+ Change in Deferred Taxes

+ Depreciation,

amortization

(including

nucl

fuel

amortization),

AFUDC/Cap.

Interest

Add back non-cash items:

Net Income

Adjusted Interest

FFO + Adjusted Interest

= Adjusted Interest

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

+ Interest

on

imputed

debt

related

to

PV

of

Purchased

Power

Agreements

(PPA),

unfunded

Pension

and

Other

Postretirement

Benefits

(OPEB)

obligations,

and

Capital

Adequacy

for

Energy

Trading

(2)

,

as

applicable

-

PECO Transition Bond Interest Expense

Net Interest Expense (Before AFUDC & Cap. Interest)

FFO

Interest

Coverage

+ Capital

Adequacy

for

Energy

Trading

(2)

FFO

= Adjusted Debt

+ PV of Operating Leases

+ 100%

of

PV

of

Purchased

Power

Agreements

(2)

+ Unfunded

Pension

and

OPEB

obligations

(2)

+ A/R Financing

Add off-balance sheet debt equivalents:

-

PECO Transition Bond Principal Balance

+ STD

+ LTD

Debt:

Adjusted Debt

(1)

FFO Debt Coverage

Rating Agency Capitalization

Rating Agency Debt

Total Adjusted Capitalization

Adjusted Book Debt

= Total Rating Agency Capitalization

+ Off-balance

sheet

debt

equivalents

(2)

Total Adjusted Capitalization

= Rating Agency Debt

+ Off-balance

sheet

debt

equivalents

(2)

Adjusted Book Debt

= Total Adjusted Capitalization

+ Adjusted Book Debt

+ Preferred Securities of Subsidiaries

+ Total Shareholders' Equity

Capitalization:

= Adjusted Book Debt

-

Transition Bond Principal Balance

+ STD

+ LTD

Debt:

Debt

to

Total

Cap

(1)

Uses current year-end adjusted debt balance.

(2)

Metrics are calculated in presentation unadjusted and adjusted for debt equivalents and related interest for PPAs, unfunded Pension and OPEB obligations, and Capital

Adequacy for Energy Trading.

(3)

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

27

Q3 GAAP EPS Reconciliation

(0.02)

-

-

-

(0.02)

2007 Illinois electric rate settlement

(0.09)

(0.04)

-

-

(0.05)

Costs associated with early debt retirements

0.05

-

-

-

0.05

Nuclear decommissioning obligation reduction

(0.01)

(0.01)

-

-

-

NRG acquisition costs

0.13

-

-

-

0.13

Unrealized gains related to nuclear decommissioning trust funds

0.12

-

-

-

0.12

Mark-to-market adjustments from economic hedging activities

$1.14

$(0.06)

$0.14

$0.07

$0.99

Q3 2009 GAAP Earnings (Loss) Per Share

$0.96

$(0.01)

$0.14

$0.07

$0.76

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

Exelon

Other

PECO

ComEd

ExGen

Three

Months

Ended

September

30,

2009

(0.04)

-

-

-

(0.04)

2007 Illinois electric rate settlement

0.02

-

-

-

0.02

Nuclear decommissioning obligation reduction

$1.06

$(0.09)

$0.14

$0.05

$0.96

Q3 2008 GAAP Earnings (Loss) Per Share

$1.07

$(0.04)

$0.14

$0.05

$0.92

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

0.10

(0.05)

-

-

0.15

Mark-to-market adjustments from economic hedging activities

(0.09)

-

-

-

(0.09)

Unrealized losses related to nuclear decommissioning trust funds

Exelon

Other

PECO

ComEd

ExGen

Three

Months

Ended

September

30,

2008

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

28

YTD GAAP EPS Reconciliation

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

(0.18)

-

-

(0.01)

(0.17)

2007 Illinois electric rate settlement

0.02

-

-

-

0.02

Nuclear decommissioning obligation reduction

$3.06

$(0.07)

$0.37

$0.16

$2.60

YTD 2008 GAAP Earnings (Loss) Per Share

$3.13

$(0.07)

$0.37

$0.17

$2.66

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

0.27

-

-

-

0.27

Mark-to-market adjustments from economic hedging activities

(0.18)

-

-

-

(0.18)

Unrealized losses related to nuclear decommissioning trust funds

Exelon

Other

PECO

ComEd

ExGen

Nine

Months

Ended

September

30,

2008

(0.08)

-

-

-

(0.08)

2007 Illinois electric rate settlement

(0.09)

(0.04)

-

-

(0.05)

Costs associated with early debt retirements

(0.20)

-

-

-

(0.20)

Impairment of certain generating assets

(0.03)

-

-

(0.02)

(0.01)

2009 severance charges

0.05

-

-

-

0.05

Nuclear decommissioning obligation reduction

(0.03)

(0.03)

-

-

-

NRG acquisition costs

0.18

-

-

-

0.18

Unrealized gains related to nuclear decommissioning trust funds

0.12

-

-

-

0.12

Mark-to-market adjustments from economic hedging activities

0.10

(0.02)

-

0.06

0.06

Non-cash remeasurement of income tax uncertainties and reassessment of

state deferred income taxes

$3.21

$(0.19)

$0.42

$0.42

$2.57

YTD 2009 GAAP Earnings (Loss) Per Share

$3.19

$(0.10)

$0.42

$0.38

$2.50

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

Exelon

Other

PECO

ComEd

ExGen

Nine

Months

Ended

September

30,

2009

29

2009 Earnings Outlook

•

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

excludes the earnings effects of the following:

•

Mark-to-market adjustments from economic hedging activities

•

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

Clinton,

Oyster

Creek,

and

Three

Mile

Island

nuclear

plants

(the

former

AmerGen

Energy

Company,

LLC

units)

•

Any significant impairments of assets, including goodwill

•

Any changes in decommissioning obligation estimates

•

Costs

associated

with

the

2007

Illinois

electric

rate

settlement

agreement,

including

ComEd’s

previously

announced customer rate relief programs

•

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

•

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

•

Costs associated with early debt retirements

•

External costs associated with the terminated offer to acquire NRG Energy, Inc.

•

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

•

Other unusual

items

•

Significant future changes to GAAP

•

Operating earnings guidance assumes normal weather for the

remainder of the year

30

Important Information

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

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

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

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

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

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

control.  The information on the following slides is as of September 30, 2009. Exelon plans to

update these hedging disclosures on a quarterly basis.

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

incorporates assumptions regarding future market conditions, including power and

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

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

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

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

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

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

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

future market conditions.

31

31

Portfolio Management Objective

Align Hedging Activities with Financial Commitments

•

Power Team utilizes several product

types and channels to market

•

Wholesale and retail sales

•

Block products

•

Load-following products

and load auctions

•

Put/call options

•

Exelon’s hedging program is designed to

protect the long-term value of our

generating fleet and maintain an

investment-grade balance sheet

•

Hedge enough commodity risk to meet future cash

requirements if prices drop

•

Consider:  financing policy (credit rating objectives,

capital structure, liquidity); spending (capital and

O&M); shareholder value return policy

•

Consider market, credit, operational risk

•

Approach to managing volatility

•

Increase hedging as delivery approaches

•

Have enough supply to meet peak load

•

Purchase fossil fuels as power is sold

•

Choose hedging products based on generation

portfolio –

sell what we own

•

Heat rate options

•

Fuel products

•

Capacity

•

Renewable credits

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

while positioning us to participate in long-term upside potential

32

32

32

Percentage of Expected

Generation Hedged

•

How many equivalent MW have been

hedged at forward market prices;  all hedge

products used are converted to an

equivalent average MW volume

•

Takes ALL

hedges

into

account

whether

they are power sales or financial products

Equivalent MWs Sold

Expected Generation

=

•

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

over the three years leading to the spot market

•

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

risks

•

By using

the

appropriate

product

mix,

expected

generation

hedged

approaches

the

mid-90s percentile as the delivery period approaches

•

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

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

quarter to quarter

Exelon Generation Hedging Program

33

33

33

2009

2010

2011

Estimated

Open

Gross

Margin

(millions)

(1)

$4,850

$5,850

$5,950

Open gross margin assumes all expected generation is

sold at the Reference Prices listed below

Reference Prices

Henry Hub Natural Gas ($/MMBtu)

NI-Hub ATC Energy Price ($/MWh)

PJM-W ATC Energy Price ($/MWh)    

ERCOT

North

ATC

Spark

Spread

($/MWh)

(2)

$4.04

$28.06

$38.23

$(0.01)

$6.21

$32.57

$48.40

$(1.51)

$6.87

$34.36

$51.50

$(1.94)

Exelon Generation Open Gross Margin and

Reference Prices

Based on September 30, 2009 market conditions

(1)

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

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

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

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

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

(2)

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

34

34

34

2009

2010

2011

Expected

Generation

(GWh)

(1)

168,900

166,800

164,900

Midwest

99,500

98,600

98,200

Mid-Atlantic

57,900

59,900

59,100

South

11,500

8,300

7,600

Percentage

of

Expected

Generation

Hedged

(2)

98-100%

88-91%

63-66%

Midwest

98-100

88-91

67-70

Mid-Atlantic

97-99

91-94

56-59

South

98-100

90-93

52-55

Effective

Realized

Energy

Price

($/MWh)

(3)

Midwest

$47.00

$46.50

$44.50

Mid-Atlantic

$36.00

$33.75

$60.50

ERCOT North ATC Spark Spread

$5.25

$3.00

$4.25

Generation Profile

(1)

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

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

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

Expected generation assumes capacity factors of  93.6%, 93.5% and 92.8% in 2009, 2010 and 2011 at Exelon-operated nuclear plants. These estimates of expected

generation in 2010 and 2011 do not represent guidance or a forecast of future results as Exelon has not completed its planning or optimization processes for those years.

(2)

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

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

(3)

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

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

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

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

35

35

35

Gross

Margin

Sensitivities

with

Existing

Hedges

(millions)

(1)

Henry Hub Natural Gas

+ $1/MMBtu

-

$1/MMBtu

NI-Hub ATC Energy Price

+$5/MWH

-$5/MWH

PJM-W ATC Energy Price

+$5/MWH

-$5/MWH

Nuclear Capacity Factor

+1% / -1%

2009

$3

$(2)

$3

$(1)

$4

$(2)

+/-$10

2010

$45

$(40)

$40

$(35)

$30

$(25)

+/-$50

2011

$265

$(225)

$185

$(175)

$165

$(160)

+/-$50

(1)

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

model that is updated periodically.

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

to

correlation

of

the

various

assumptions,

the

hedged

gross

margin

impact

calculated

by

aggregating

individual

sensitivities

may

not

be

equal

to

the

hedged

gross

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

Exelon Generation Gross Margin Sensitivities

(with Existing Hedges)

36

36

36

Exelon Generation Gross Margin Upside / Risk

(with Existing Hedges)

95% case

5% case

$6,700

$6,600

$6,100

$6,500

$6,000

$8,200

$5,000

$6,000

$7,000

$8,000

$9,000

$10,000

2009

2010

2011

Represents an approximate range of expected gross margin, taking into account hedges in place, between the 5th and 95th percentile confidence levels.  Approximate gross margin

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

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

those years. The price distributions that generate this range are calibrated to market quotes for power, fuel, load following products, and options as of September 30, 2009.

(1)

37

37

37

Midwest

Mid-Atlantic

ERCOT

Step 1

Start

with

fleetwide

open

gross

margin

$4.85 billion

Step 2

Determine the mark-to-market value

of energy hedges

99,550GWh * 99% *

($47.00/MWh-$28.06/MWh)

= $1.87 billion

57,900GWh * 98% *

($36.00/MWh-$38.23/MWh)

= $(0.13 billion)

11,500GWh * 99% *

($5.25/MWh-($0.01)/MWh)

= $0.06 billion

Step 3

Estimate

hedged

gross

margin

by

adding open gross margin to mark-to-

market value of energy hedges

Open

gross

margin:

$4.85

billion

MTM

value

of

energy

hedges:

$1.87

billion

+

$(0.13

billion)

+

$0.06

billion

Estimated

hedged

gross

margin:

$6.65

billion

Illustrative Example

of Modeling Exelon Generation 2009 Gross Margin

(with Existing Hedges)

38

38

38

38

45

55

65

75

85

95

105

115

10/08

11/08

12/08

1/09

2/09

3/09

4/09

5/09

6/09

7/09

8/09

9/09

10/09

20

25

30

35

40

45

50

55

60

65

10/08

11/08

12/08

1/09

2/09

3/09

4/09

5/09

6/09

7/09

8/09

9/09

10/09

35

45

55

65

75

85

95

105

10/08

11/08

12/08

1/09

2/09

3/09

4/09

5/09

6/09

7/09

8/09

9/09

10/09

5

6

7

8

9

10

11

10/08

11/08

12/08

1/09

2/09

3/09

4/09

5/09

6/09

7/09

8/09

9/09

10/09

38

Market Price Snapshot

Forward NYMEX Natural Gas

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

PJM-West and Ni-Hub Wrap Forward Prices

2010

$6.04

2011  $6.82

Rolling 12 months, as of October 15, 2009. Source: OTC quotes and electronic trading system. Quotes are daily.

Forward NYMEX Coal

2010

$53.25

2011

$65.26

2010 Ni-Hub  $43.06

2011 Ni-Hub

$45.29

2011 PJM-West  $63.88

2010 PJM-West

$59.37

2010 Ni-Hub

$24.40

2011 Ni-Hub

$26.00

2011 PJM-West

$42.28

2010 PJM-West

$39.79

39

39

39

39

4.5

5.5

6.5

7.5

8.5

9.5

10/08

11/08

12/08

1/09

2/09

3/09

4/09

5/09

6/09

7/09

8/09

9/09

10/09

8

8.2

8.4

8.6

8.8

9

9.2

9.4

9.6

9.8

10

10/08

11/08

12/08

1/09

2/09

3/09

4/09

5/09

6/09

7/09

8/09

9/09

10/09

35

40

45

50

55

60

65

70

75

80

85

10/08

11/08

12/08

1/09

2/09

3/09

4/09

5/09

6/09

7/09

8/09

9/09

10/09

5

6

7

8

9

10

11

10/08

11/08

12/08

1/09

2/09

3/09

4/09

5/09

6/09

7/09

8/09

9/09

10/09

39

Market Price Snapshot

2011

$8.66

2010

$8.65

2010

$50.68

2011

$57.42

2010

$5.86

2011

$6.63

Houston Ship Channel Natural Gas

Forward Prices

ERCOT North On-Peak Forward Prices

ERCOT North On-Peak v. Houston Ship Channel

Implied Heat Rate

2010

$5.91

2011

$7.10

ERCOT North On Peak Spark Spread

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

Rolling 12 months, as of October 15, 2009. Source: OTC quotes and electronic trading system. Quotes are daily.