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

January 26, 2011

Date of Report (Date of earliest event reported)

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

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

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

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

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

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

Section 2 – Financial Information

Item 2.02. Results of Operations and Financial Condition.

Section 7 – Regulation FD

Item 7.01. Regulation FD Disclosure.

On January 26, 2011, Exelon Corporation (Exelon) announced via press release its results for the fourth quarter ended December 31, 2010. A copy of the press release and related attachments is attached hereto as Exhibit 99.1. Also attached as Exhibit 99.2 to this Current Report on Form 8-K are the presentation slides to be used at the fourth quarter 2010 earnings conference call. This Form 8-K and the attached exhibits are provided under Items 2.02, 7.01 and 9.01 of Form 8-K and are furnished to, but not filed with, the Securities and Exchange Commission.

Exelon has scheduled the conference call for 11:00 AM ET (10:00 AM CT) on January 26, 2011. The call-in number in the U.S. and Canada is 800-690-3108, and the international call-in number is 973-935-8753. If requested, the conference ID number is 34838808. Media representatives are invited to participate on a listen-only basis. The call will be web-cast and archived on Exelon’s Web site: www.exeloncorp.com. (Please select the Investors page.)

Telephone replays will be available until February 9^th. The U.S. and Canada call-in number for replays is 800-642-1687, and the international call-in number is 706-645-9291. The conference ID number is 34838808.

Section 9 – Financial Statements and Exhibits

Item 9.01. Financial Statements and Exhibits.

(d) Exhibits.

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

* * * * *

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

This Current Report includes forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995 that are subject to risks and uncertainties. The factors that could cause actual results to differ materially from these forward-looking statements include those discussed herein as well as those discussed in (1) Exelon’s 2009 Annual Report on Form 10-K in (a) ITEM 1A. Risk Factors, (b) ITEM 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations and (c) ITEM 8. Financial Statements and Supplementary Data: Note 18; (2) Exelon’s Third Quarter 2010 Quarterly Report on Form 10-Q in (a) Part II, Other Information, ITEM 1A. Risk Factors, (b) Part 1, Financial Information, ITEM 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations and (c) Part I, Financial Information, ITEM 1. Financial Statements: Note 13; and (3) other factors discussed in filings with the Securities and Exchange Commission by the Registrants. Readers are cautioned not to place undue reliance on these forward-looking statements, which apply only as of the date of this Current Report. None of the Registrants undertakes any obligation to publicly release any revision to its forward-looking statements to reflect events or circumstances after the date of this Current Report.

SIGNATURES

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

EXELON CORPORATION

EXELON GENERATION COMPANY, LLC

/s/ Matthew F. Hilzinger

Matthew F. Hilzinger

Senior Vice President, Chief Financial Officer and Treasurer

Exelon Corporation

COMMONWEALTH EDISON COMPANY

/s/ Joseph R. Trpik, Jr.

Joseph R. Trpik, Jr.

Senior Vice President, Chief Financial Officer and Treasurer

Commonwealth Edison Company

PECO ENERGY COMPANY

/s/ Phillip S. Barnett

Phillip S. Barnett

Senior Vice President and Chief Financial Officer

PECO Energy Company

January 26, 2011

EXHIBIT INDEX

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

EX-99.1

Exhibit 99.1

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

Exelon Announces Fourth Quarter and Full Year 2010 Results;

Introduces Guidance Range for Full Year 2011 Earnings

Company projects 2011 operating earnings of $3.90 to $4.20 per share.

CHICAGO (January 26, 2011) – Exelon Corporation (NYSE: EXC) announced fourth quarter and full year 2010 consolidated earnings as follows:

Exelon Consolidated Earnings (unaudited)

	Full Year				Fourth Quarter
	2010		2009		2010		2009
Adjusted (non-GAAP) Operating Results:
Net Income ($ millions)	$	2,689	$	2,723	$	631	$	610
Diluted Earnings per Share	$	4.06	$	4.12	$	0.96	$	0.92
GAAP Results:
Net Income ($ millions)	$	2,563	$	2,707	$	524	$	581
Diluted Earnings per Share	$	3.87	$	4.09	$	0.79	$	0.88

“We delivered another exceptional year of financial and operating performance in 2010,” said John W. Rowe, chairman and chief executive officer. “We accomplished this with a keen focus on controlling operating and maintenance expenses across our businesses. At the same time, Exelon Generation attained its eighth consecutive year of nuclear fleet capacity factors that exceeded 93 percent, and ComEd and PECO demonstrated strong service reliability despite severe storms.”

Rowe added, “In 2011, Pennsylvania has fully transitioned to a competitive energy market, and along with our continued diligent focus on cost control and financial discipline, we are introducing full year operating earnings guidance of $3.90 to $4.20 per share.”

Fourth Quarter Operating Results

As shown in the table above, Exelon’s adjusted (non-GAAP) operating earnings increased to $0.96 per share in the fourth quarter of 2010 from $0.92 per share in the fourth quarter of 2009, primarily due to:

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• The impact at Exelon Generation Company, LLC (Generation) of favorable capacity pricing related to the Reliability Pricing Model (RPM) for the PJM Interconnection, LLC (PJM) market;

• Increased nuclear output at Generation primarily reflecting the effect of fewer nuclear outage days in 2010; and

• Decreased scheduled competitive transition charge (CTC) amortization expense at PECO Energy Company (PECO).

Higher fourth quarter 2010 earnings were partially offset by:

• Unfavorable market/portfolio conditions and higher nuclear fuel costs at Generation; and

• Increased depreciation expense across the operating companies largely due to ongoing capital expenditures.

Adjusted (non-GAAP) operating earnings for the fourth quarter of 2010 do not include the following items (after tax) that were included in reported GAAP earnings:

	(in millions)			(per diluted share)
Mark-to-market losses primarily from Generation’s economic hedging activities	$	(113	)	$	(0.17	)
Unrealized gains related to nuclear decommissioning trust (NDT) fund investments to the extent not offset by contractual accounting	$	26		$	0.04
Costs associated with the planned retirement of certain Generation fossil generating units	$	(17	)	$	(0.03	)
Decrease in costs related to adjustments to asset retirement obligations of Commonwealth Edison Company (ComEd) and PECO	$	7		$	0.01
External costs related to Exelon’s acquisition of John Deere Renewables, LLC (now known as Exelon Wind)	$	(6	)	$	(0.01	)
Costs associated with the 2007 Illinois electric rate settlement agreement	$	(4	)	$	(0.01	)

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

	(in millions)			(per diluted share)
Costs associated with the planned retirement of certain Generation fossil generating units	$	(34	)	$	(0.05	)
Mark-to-market gains primarily from Generation’s economic hedging activities	$	26		$	0.04
Costs associated with the 2007 Illinois electric rate settlement agreement	$	(15	)	$	(0.02	)
Costs associated with early debt retirement	$	(15	)	$	(0.02	)
Unrealized gains related to NDT fund investments	$	14		$	0.02
Charge associated with ComEd’s 2007 settlement agreement with the City of Chicago	$	(5	)	$	(0.01	)

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2011 Earnings Outlook

Exelon introduced a guidance range for 2011 adjusted (non-GAAP) operating earnings of $3.90 to $4.20 per share. Operating earnings guidance is based on the assumption of normal weather.

The outlook for 2011 adjusted (non-GAAP) operating earnings for Exelon and its subsidiaries excludes the following items:

• Mark-to-market adjustments from economic hedging activities

• Unrealized gains and losses from NDT fund investments to the extent not offset by contractual accounting as described in the notes to the consolidated financial statements

• Significant impairments of assets, including goodwill

• Changes in decommissioning obligation estimates

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

• Financial impacts associated with the planned retirement of fossil generating units

• Other unusual items

• Significant changes to GAAP

Fourth Quarter and Recent Highlights

• Oyster Creek Nuclear Station Retirement: On December 8, 2010, Exelon announced that the company will operate the Oyster Creek Generating Station in New Jersey until 2019, after which the plant will retire. The 625-megawatt (MW) nuclear plant is federally licensed to operate until 2029. Oyster Creek faces a unique set of adverse economic factors and changing environmental regulations that make ending operations in 2019 the best option. Potential additional environmental compliance costs based on evolving water cooling regulatory requirements at both the federal and state government levels created significant regulatory and economic uncertainty. Due to Exelon’s decision to retire the plant early, the New Jersey Department of Environmental Protection will not require the company to install cooling towers at Oyster Creek.

• John Deere Renewables (JDR) Acquisition: On December 9, 2010, Exelon completed its previously announced acquisition of JDR, a leading operator and developer of wind power, adding 735 MW of clean, renewable energy to Exelon’s generation portfolio. The acquisition of JDR marked Exelon’s entry into owning and operating wind projects. The 36 wind projects in eight states are now called Exelon Wind, a division of Exelon Power. The acquisition provides incremental earnings starting in 2012 and cash flows starting in 2013 and is a key part of Exelon 2020, the company’s business strategy to eliminate the equivalent of its 2001 carbon footprint by 2020. Exelon is now halfway to its goal and remains the least carbon-intensive of the large U.S. electric utilities. Approximately 75 percent of the Exelon Wind operating portfolio is already sold under long-term power purchase arrangements. In addition, Exelon has the opportunity to pursue approximately 1,400 MW of new wind projects that are in various stages of development, including 230 MW in advanced stages of development.

• Nuclear Operations: Generation’s nuclear fleet, including its owned output from the Salem Generating Station, produced 35,115 gigawatt-hours (GWh) in the fourth quarter of 2010, compared with 33,609 GWh in the fourth quarter of 2009. The Exelon-operated nuclear plants achieved a 93.1 percent capacity factor for the fourth quarter of 2010 compared with 89.8 percent for the fourth quarter of 2009. The Exelon-operated nuclear plants completed four

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scheduled refueling outages in the fourth quarter of 2010, compared with completing four and beginning a fifth scheduled refueling outage in the fourth quarter of 2009. Three Mile Island (TMI) Unit 1 was shut down from late October 2009 for an extended refueling outage which included the replacement of steam generators. The steam generator replacement increased the number of refueling outage days in the fourth quarter of 2009. As a result, the number of refueling outage days totaled 97 in the fourth quarter of 2010 versus 136 days in the fourth quarter of 2009. The number of non-refueling outage days at the Exelon-operated plants totaled 18 days in the fourth quarter of 2010 compared with 23 days in the fourth quarter of 2009.

For the full year 2010, the Exelon-operated nuclear plants achieved an average capacity factor of 93.9 percent, as compared with 93.6 percent for 2009. The average annual capacity factor for the Exelon-operated plants during the five years ended 2010 was 94.0 percent.

• Fossil and Hydro Operations: The equivalent demand forced outage rate for Generation’s fossil fleet was 4.6 percent in the fourth quarter of 2010, compared with 12.9 percent in the fourth quarter of 2009. The improvement was largely due to the impact of extended maintenance outages in 2009. The equivalent availability factor for the hydroelectric facilities was 99.8 percent in the fourth quarter of 2010, compared with 99.6 percent in the fourth quarter of 2009.

• Hedging Update: Exelon’s hedging program involves the hedging of commodity risk for Exelon’s expected generation, typically on a ratable basis over a three-year period. Expected generation represents the amount of energy estimated to be generated or purchased through owned or contracted-for capacity. The proportion of expected generation hedged as of December 31, 2010 is 90 to 93 percent for 2011, 67 to 70 percent for 2012 and 32 to 35 percent for 2013. The primary objectives of Exelon’s hedging program are to manage market risks and protect the value of its generation and its investment grade balance sheet while preserving its ability to participate in improving long-term market fundamentals.

• ComEd Electric Distribution Rate Case: On June 30, 2010, ComEd filed a rate increase request with the Illinois Commerce Commission (ICC) to allow the utility to continue modernizing its electric delivery system and recover the cost of substantial investments made since the last rate filing in 2007. In testimony submitted on January 3, 2011, ComEd revised its requested revenue increase to $326 million, reflecting certain adjustments made subsequent to its original request of $396 million. The ICC will determine any increase in rates after an 11-month proceeding with input from all stakeholders. The ICC is expected to issue its decision in late May 2011.

• PECO Electric and Gas Distribution Rate Cases: On December 16, 2010, the Pennsylvania Public Utility Commission (PAPUC) approved PECO’s settlements with all interested parties regarding the increase in electric and natural gas distribution rates for customers, which became effective on January 1, 2011. The PAPUC approved an increase of $20 million in annual natural gas distribution revenue, which is approximately 46 percent of the $44 million originally requested, and a $225 million increase in annual electric distribution revenue, which is approximately 71 percent of the $316 million originally requested. Reflecting this and the results of the company’s four competitive electric supply procurements, residential electric customer bills will increase on average about 5 percent, or about $5 a month,

beginning in

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January 2011. Overall bills for PECO residential natural gas customers will increase on average about 1 percent, or about $1 a month.

• Pension Plan Funding: As a result of accelerated cash benefits associated with recent Federal tax legislation, on January 3, 2011, Exelon announced that its board of directors had authorized contributions to the Exelon pension plans in the first quarter of 2011 totaling $2.1 billion. This amount includes contributions that Exelon was previously expected to make in 2011. Exelon expects to fund the contributions with $500 million from cash from operations, $850 million from the accelerated cash tax benefits, and $750 million from the tax benefits of making the pension contributions. Exelon expects that the pension funded status will increase from 71 percent at December 31, 2010, to 89 percent projected at December 31, 2011, subject to actual 2011 asset returns and final actuarial valuations.

• Financing Activities: On January 18, 2011, ComEd issued $600 million of 1.625 percent first mortgage bonds due 2014. The net proceeds of the bonds will be used as an interim source of liquidity for the contribution in the first quarter to the pension plans in which ComEd participates. ComEd anticipates receiving tax refunds as a result of both the pension contribution and the recent Federal tax legislation. As a result, the immediate use of the net proceeds to fund the planned contribution will allow those future cash receipts to be available to fund capital investment and for general corporate purposes.

On October 25, 2010, Exelon announced that it had entered into new credit agreements totaling $94 million with 29 minority and community banks located in the regions the company serves. The lead arranger banks for the credit agreements are Seaway Bank and Trust Company in Chicago, Riverside Community Bank in Rockford, Ill., and United Bank of Philadelphia. The new credit agreements replace a 2009 arrangement for $67 million. Exelon’s minority and community banking program – the only one of its kind in the energy industry – aims to increase the company’s business with local and diverse banks in its key markets.

OPERATING COMPANY RESULTS

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

Fourth quarter 2010 net income was $424 million compared with $425 million in the fourth quarter of 2009. Fourth quarter 2010 net income included (all after tax) mark-to-market losses of $113 million from economic hedging activities, unrealized gains of $26 million related to NDT fund investments, costs of $17 million associated with the planned retirement of certain fossil generating units, a charge of $6 million for external costs associated with the acquisition of JDR and a charge of $4 million for costs associated with the 2007 Illinois electric rate settlement. Fourth quarter 2009 net income included (all after-tax) costs of $34 million associated with the retirement of the fossil generating units, mark-to-market gains of $26 million from economic hedging activities before the elimination of intercompany transactions, unrealized gains of $14 million related to NDT fund investments, costs of $13 million associated with the 2007 Illinois electric rate settlement and costs of $9 million associated with early debt retirements. Excluding the effects of these items, Generation’s net income in the fourth quarter of 2010 increased $97 million compared with the same quarter in 2009 primarily due to:

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• The impact on energy gross margin of higher energy prices under the power purchase agreement with PECO, favorable capacity pricing related to RPM and increased nuclear output largely reflecting fewer outage days.

The increase in net income was partially offset by:

• The impact on energy gross margin of unfavorable market/portfolio conditions and higher nuclear fuel costs; and

• Increased depreciation expense.

Generation’s average realized margin on all electric sales, including sales to affiliates and excluding trading activity, was $41.45 per MWh in the fourth quarter of 2010 compared with $38.36 per MWh in the fourth quarter of 2009.

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

ComEd recorded net income of $91 million in the fourth quarter of 2010, compared with net income of $98 million in the fourth quarter of 2009. Fourth quarter net income in 2010 included an after-tax decrease in costs of $6 million associated with an adjustment to ComEd’s asset retirement obligation. Fourth quarter net income in 2009 included after-tax costs of $5 million for the City of Chicago settlement agreement and after-tax costs of $2 million associated with the 2007 Illinois electric rate settlement. Excluding the effects of these items, ComEd’s net income in the fourth quarter of 2010 was down $20 million from the same quarter in 2009 primarily reflecting:

• The effect of the September 2010 Illinois Appellate Court ruling;

• Increased operating and maintenance expense; and

• Lower load, partially offset by the effects of favorable weather conditions.

The decrease in net income was partially offset by lower uncollectible accounts expense.

In the fourth quarter of 2010, heating degree-days in the ComEd service territory were up 1.2 percent relative to the same period in 2009 and were 0.6 percent above normal. ComEd’s total retail electric deliveries increased by 0.6 percent quarter over quarter, primarily due to gains in deliveries to large commercial and industrial customers.

Weather-normalized retail electric deliveries decreased by 1.2 percent from the fourth quarter of 2009, primarily reflecting a decrease in deliveries to residential customers. For ComEd, weather had a favorable after-tax effect of $4 million on fourth quarter 2010 earnings relative to 2009 and a favorable after-tax effect of $1 million relative to normal weather that is incorporated in Exelon’s earnings guidance.

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

PECO’s net income in the fourth quarter of 2010 was $21 million, down from $78 million in the fourth quarter of 2009. Fourth quarter net income in 2010 included an after-tax decrease in costs of $1 million associated with an adjustment to PECO’s asset retirement obligation. Excluding the effect of this item,

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PECO’s net income in the fourth quarter of 2010 was down $58 million from the same quarter in 2009 primarily reflecting:

• Decreased CTC revenue, as stranded costs were substantially recovered as of the end of the third quarter 2010, resulting in higher energy prices paid to Generation under the power purchase agreement; and

• Increased operating and maintenance expense, primarily reflecting higher contracting and employee benefits expenses.

The decrease in net income was partially offset by:

• Lower CTC amortization expense as scheduled in accordance with PECO’s 1998 Restructuring Settlement with the PAPUC;

• The effects of favorable weather conditions; and

• Lower interest expense on long-term debt.

In the fourth quarter of 2010, heating degree-days in the PECO service territory were up 7.6 percent from 2009 and were 3.2 percent above normal. Total retail electric deliveries were up 1.4 percent from last year, reflecting an increase in deliveries to residential and large commercial and industrial customers. On the retail gas side, deliveries in the fourth quarter of 2010 were up 11.7 percent from the fourth quarter of 2009, primarily driven by the effects of colder weather conditions.

Weather-normalized retail electric deliveries were flat to the fourth quarter of 2009, reflecting a decline in residential and small commercial and industrial deliveries, offset by an increase in large commercial and industrial deliveries. For PECO, weather had a favorable after-tax effect of $6 million on fourth quarter 2010 earnings relative to 2009 and a favorable after-tax effect of $2 million relative to normal weather that is incorporated in Exelon’s earnings guidance.

Adjusted (non-GAAP) Operating Earnings

Adjusted (non-GAAP) operating earnings, which generally exclude significant one-time charges or credits that are not normally associated with ongoing operations, mark-to-market adjustments from economic hedging activities and unrealized gains and losses from NDT fund investments, are provided as a supplement to results reported in accordance with GAAP. Management uses such adjusted (non-GAAP) operating earnings measures internally to evaluate the company’s performance and manage its operations. Reconciliation of GAAP to adjusted (non-GAAP) operating earnings for historical periods is attached. Additional earnings release attachments, which include the reconciliations on pages 7 and 8, are posted on Exelon’s Web site: www.exeloncorp.com and have been furnished to the Securities and Exchange Commission on Form 8-K on January 26, 2011.

Conference call information: Exelon has scheduled a conference call for 11:00 AM ET (10:00 AM CT) on January 26, 2011. The call-in number in the U.S. and Canada is 800-690-3108, and the international call-in number is 973-935-8753. If requested, the conference ID number is 34838808. Media representatives are invited to participate on a listen-only basis. The call will be web-cast and archived on Exelon’s Web site: www.exeloncorp.com. (Please select the Investors page.)

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Telephone replays will be available until February 9. The U.S. and Canada call-in number for replays is 800-642-1687, and the international call-in number is 706-645-9291. The conference ID number is 34838808.

Forward Looking Statements

This press release includes forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995, that are subject to risks and uncertainties. The factors that could cause actual results to differ materially from these forward-looking statements include those discussed herein as well as those discussed in (1) Exelon’s 2009 Annual Report on Form 10-K in (a) ITEM 1A. Risk Factors, (b) ITEM 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations and (c) ITEM 8. Financial Statements and Supplementary Data: Note 18; (2) Exelon’s Third Quarter 2010 Quarterly Report on Form 10-Q in (a) Part II, Other Information, ITEM 1A. Risk Factors, (b) Part 1, Financial Information, ITEM 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations and (c) Part I, Financial Information, ITEM 1. Financial Statements: Note 13 and (3) other factors discussed in filings with the Securities and Exchange Commission (SEC) by Exelon Corporation, Commonwealth Edison Company, PECO Energy Company and Exelon Generation Company, LLC (Companies). Readers are cautioned not to place undue reliance on these forward-looking statements, which apply only as of the date of this press release. None of the Companies undertakes any obligation to publicly release any revision to its forward-looking statements to reflect events or circumstances after the date of this press release.

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Exelon Corporation is one of the nation’s largest electric utilities with more than $18 billion in annual revenues. The company has one of the industry’s largest portfolios of electricity generation capacity, with a nationwide reach and strong positions in the Midwest and Mid-Atlantic. Exelon distributes electricity to approximately 5.4 million customers in northern Illinois and southeastern Pennsylvania and natural gas to approximately 486,000 customers in the Philadelphia area. Exelon is headquartered in Chicago and trades on the NYSE under the ticker EXC.

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Earnings Release Attachments

Table of Contents

Consolidating Statements of Operations - Three Months Ended December 31, 2010 and 2009	1
Consolidating Statements of Operations - Twelve Months Ended December 31, 2010 and 2009	2
Business Segment Comparative Statements of Operations - Generation and ComEd - Three and Twelve Months Ended December 31, 2010 and 2009	3
Business Segment Comparative Statements of Operations - PECO and Other - Three and Twelve Months Ended December 31, 2010 and 2009	4
Consolidated Balance Sheets - December 31, 2010 and December 31, 2009	5
Consolidated Statements of Cash Flows - Twelve Months Ended December 31, 2010 and 2009	6
Reconciliation of Adjusted (non-GAAP) Operating Earnings to GAAP Consolidated Statements of Operations - Exelon - Three Months Ended December 31, 2010 and 2009	7
Reconciliation of Adjusted (non-GAAP) Operating Earnings to GAAP Consolidated Statements of Operations - Exelon - Twelve Months Ended December 31, 2010 and 2009	8
Reconciliation of Adjusted (non-GAAP) Operating Earnings to GAAP Earnings By Business Segment - Three Months Ended December 31, 2010 and 2009	9
Reconciliation of Adjusted (non-GAAP) Operating Earnings to GAAP Earnings By Business Segment - Twelve Months Ended December 31, 2010 and 2009	10
Reconciliation of Adjusted (non-GAAP) Operating Earnings to GAAP Consolidated Statements of Operations - Generation - Three and Twelve Months Ended December 31, 2010 and 2009	11
Reconciliation of Adjusted (non-GAAP) Operating Earnings to GAAP Consolidated Statements of Operations - ComEd - Three and Twelve Months Ended December 31, 2010 and 2009	12
Reconciliation of Adjusted (non-GAAP) Operating Earnings to GAAP Consolidated Statements of Operations - PECO - Three and Twelve Months Ended December 31, 2010 and 2009	13
Reconciliation of Adjusted (non-GAAP) Operating Earnings to GAAP Consolidated Statements of Operations - Other - Three and Twelve Months Ended December 31, 2010 and 2009	14
Exelon Generation Statistics - Three Months Ended December 31, 2010, September 30, 2010, June 30, 2010, March 31, 2010 and December 31, 2009	15
Exelon Generation Statistics - Twelve Months Ended December 31, 2010 and 2009	16
ComEd Statistics - Three and Twelve Months Ended December 31, 2010 and 2009	17
PECO Statistics - Three and Twelve Months Ended December 31, 2010 and 2009	18

EXELON CORPORATION

Consolidating Statements of Operations

(unaudited)

(in millions)

	Three Months Ended December 31, 2010
	Generation			ComEd			PECO			Other			Exelon Consolidated
Operating revenues	$	2,596		$	1,372		$	1,299		$	(773	)	$	4,494
Operating expenses
Purchased power		602			671			652			(773	)		1,152
Fuel		418			—			123			—			541
Operating and maintenance		731			247			172			10			1,160
Operating and maintenance for regulatory required programs (a)		—			27			17			—			44
Depreciation and amortization		129			130			201			5			465
Taxes other than income		56			68			64			5			193
Total operating expenses		1,936			1,143			1,229			(753	)		3,555
Operating income (loss)		660			229			70			(20	)		939
Other income and deductions
Interest expense		(44	)		(86	)		(34	)		(19	)		(183	)
Other, net		118			10			2			5			135
Total other income and deductions		74			(76	)		(32	)		(14	)		(48	)
Income (loss) before income taxes		734			153			38			(34	)		891
Income taxes		310			62			17			(22	)		367
Net income (loss)	$	424		$	91		$	21		$	(12	)	$	524
	Three Months Ended December 31, 2009
	Generation			ComEd			PECO			Other			Exelon Consolidated
Operating revenues	$	2,278		$	1,357		$	1,266		$	(785	)	$	4,116
Operating expenses
Purchased power		375			692			532			(784	)		815
Fuel		300			—			126			(1	)		425
Operating and maintenance		727			232			159			2			1,120
Operating and maintenance for regulatory required programs (a)		—			19			—			—			19
Depreciation and amortization		110			123			225			16			474
Taxes other than income		55			67			64			1			187
Total operating expenses		1,567			1,133			1,106			(766	)		3,040
Operating income (loss)		711			224			160			(19	)		1,076
Other income and deductions
Interest expense		(36	)		(78	)		(42	)		(20	)		(176	)
Loss in equity method investments		—			—			(5	)		(1	)		(6	)
Other, net		50			11			5			(6	)		60
Total other income and deductions		14			(67	)		(42	)		(27	)		(122	)
Income (loss) before income taxes		725			157			118			(46	)		954
Income taxes		300			59			40			(26	)		373
Net income (loss)	$	425		$	98		$	78		$	(20	)	$	581

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

1

EXELON CORPORATION

Consolidating Statements of Operations

(unaudited)

(in millions)

	Twelve Months Ended December 31, 2010
	Generation			ComEd			PECO			Other			Exelon Consolidated
Operating revenues	$	10,025		$	6,204		$	5,519		$	(3,104	)	$	18,644
Operating expenses
Purchased power		1,853			3,307			2,361			(3,096	)		4,425
Fuel		1,610			—			401			(1	)		2,010
Operating and maintenance		2,812			975			680			(14	)		4,453
Operating and maintenance for regulatory required programs (a)		—			94			53			—			147
Depreciation and amortization		474			516			1,060			25			2,075
Taxes other than income		230			256			303			19			808
Total operating expenses		6,979			5,148			4,858			(3,067	)		13,918
Operating income (loss)		3,046			1,056			661			(37	)		4,726
Other income and deductions
Interest expense		(153	)		(386	)		(193	)		(85	)		(817	)
Other, net		257			24			8			23			312
Total other income and deductions		104			(362	)		(185	)		(62	)		(505	)
Income (loss) before income taxes		3,150			694			476			(99	)		4,221
Income taxes		1,178			357			152			(29	)		1,658
Net income (loss)	$	1,972		$	337		$	324		$	(70	)	$	2,563
	Twelve Months Ended December 31, 2009
	Generation			ComEd			PECO			Other			Exelon Consolidated
Operating revenues	$	9,703		$	5,774		$	5,311		$	(3,470	)	$	17,318
Operating expenses
Purchased power		1,338			3,065			2,274			(3,462	)		3,215
Fuel		1,594			—			472			—			2,066
Operating and maintenance		2,938			1,028			640			6			4,612
Operating and maintenance for regulatory required programs (a)		—			63			—			—			63
Depreciation and amortization		333			494			952			55			1,834
Taxes other than income		205			281			276			16			778
Total operating expenses		6,408			4,931			4,614			(3,385	)		12,568
Operating income (loss)		3,295			843			697			(85	)		4,750
Other income and deductions
Interest expense		(113	)		(319	)		(187	)		(112	)		(731	)
Loss in equity method investments		(3	)		—			(24	)		—			(27	)
Other, net		376			79			13			(41	)		427
Total other income and deductions		260			(240	)		(198	)		(153	)		(331	)
Income (loss) before income taxes		3,555			603			499			(238	)		4,419
Income taxes		1,433			229			146			(96	)		1,712
Net income (loss)	$	2,122		$	374		$	353		$	(142	)	$	2,707

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

2

EXELON CORPORATION

Business Segment Comparative Statements of Operations

(unaudited)

(in millions)

	Generation
	Three Months Ended December 31,									Twelve Months Ended December 31,
	2010			2009			Variance			2010			2009			Variance
Operating revenues	$	2,596		$	2,278		$	318		$	10,025		$	9,703		$	322
Operating expenses
Purchased power		602			375			227			1,853			1,338			515
Fuel		418			300			118			1,610			1,594			16
Operating and maintenance		731			727			4			2,812			2,938			(126	)
Depreciation and amortization		129			110			19			474			333			141
Taxes other than income		56			55			1			230			205			25
Total operating expenses		1,936			1,567			369			6,979			6,408			571
Operating income		660			711			(51	)		3,046			3,295			(249	)
Other income and deductions
Interest expense		(44	)		(36	)		(8	)		(153	)		(113	)		(40	)
Loss in equity method investments		—			—			—			—			(3	)		3
Other, net		118			50			68			257			376			(119	)
Total other income and deductions		74			14			60			104			260			(156	)
Income before income taxes		734			725			9			3,150			3,555			(405	)
Income taxes		310			300			10			1,178			1,433			(255	)
Net income	$	424		$	425		$	(1	)	$	1,972		$	2,122		$	(150	)
	ComEd
	Three Months Ended December 31,									Twelve Months Ended December 31,
	2010			2009			Variance			2010			2009			Variance
Operating revenues	$	1,372		$	1,357		$	15		$	6,204		$	5,774		$	430
Operating expenses
Purchased power		671			692			(21	)		3,307			3,065			242
Operating and maintenance		247			232			15			975			1,028			(53	)
Operating and maintenance for regulatory required programs (a)		27			19			8			94			63			31
Depreciation and amortization		130			123			7			516			494			22
Taxes other than income		68			67			1			256			281			(25	)
Total operating expenses		1,143			1,133			10			5,148			4,931			217
Operating income		229			224			5			1,056			843			213
Other income and deductions
Interest expense		(86	)		(78	)		(8	)		(386	)		(319	)		(67	)
Other, net		10			11			(1	)		24			79			(55	)
Total other income and deductions		(76	)		(67	)		(9	)		(362	)		(240	)		(122	)
Income before income taxes		153			157			(4	)		694			603			91
Income taxes		62			59			3			357			229			128
Net income	$	91		$	98		$	(7	)	$	337		$	374		$	(37	)

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

3

EXELON CORPORATION

Business Segment Comparative Statements of Operations

(unaudited)

(in millions)

	PECO
	Three Months Ended December 31,									Twelve Months Ended December 31,
	2010			2009			Variance			2010			2009			Variance
Operating revenues	$	1,299		$	1,266		$	33		$	5,519		$	5,311		$	208
Operating expenses
Purchased power		652			532			120			2,361			2,274			87
Fuel		123			126			(3	)		401			472			(71	)
Operating and maintenance		172			159			13			680			640			40
Operating and maintenance for regulatory required programs (a)		17			—			17			53			—			53
Depreciation and amortization		201			225			(24	)		1,060			952			108
Taxes other than income		64			64			—			303			276			27
Total operating expenses		1,229			1,106			123			4,858			4,614			244
Operating income		70			160			(90	)		661			697			(36	)
Other income and deductions
Interest expense		(34	)		(42	)		8			(193	)		(187	)		(6	)
Loss in equity method investments		—			(5	)		5			—			(24	)		24
Other, net		2			5			(3	)		8			13			(5	)
Total other income and deductions		(32	)		(42	)		10			(185	)		(198	)		13
Income before income taxes		38			118			(80	)		476			499			(23	)
Income taxes		17			40			(23	)		152			146			6
Net income	$	21		$	78		$	(57	)	$	324		$	353		$	(29	)
	Other (b)
	Three Months Ended December 31,									Twelve Months Ended December 31,
	2010			2009			Variance			2010			2009			Variance
Operating revenues	$	(773	)	$	(785	)	$	12		$	(3,104	)	$	(3,470	)	$	366
Operating expenses
Purchased power		(773	)		(784	)		11			(3,096	)		(3,462	)		366
Fuel		—			(1	)		1			(1	)		—			(1	)
Operating and maintenance		10			2			8			(14	)		6			(20	)
Depreciation and amortization		5			16			(11	)		25			55			(30	)
Taxes other than income		5			1			4			19			16			3
Total operating expenses		(753	)		(766	)		13			(3,067	)		(3,385	)		318
Operating loss		(20	)		(19	)		(1	)		(37	)		(85	)		48
Other income and deductions
Interest expense		(19	)		(20	)		1			(85	)		(112	)		27
Loss in equity method investments		—			(1	)		1			—			—			—
Other, net		5			(6	)		11			23			(41	)		64
Total other income and deductions		(14	)		(27	)		13			(62	)		(153	)		91
Loss before income taxes		(34	)		(46	)		12			(99	)		(238	)		139
Income taxes		(22	)		(26	)		4			(29	)		(96	)		67
Net loss	$	(12	)	$	(20	)	$	8		$	(70	)	$	(142	)	$	72

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

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

4

EXELON CORPORATION

Consolidated Balance Sheets

(unaudited)

(in millions)

	December 31, 2010			December 31, 2009
ASSETS
Current assets
Cash and cash equivalents	$	1,612		$	2,010
Restricted cash and investments		30			40
Accounts receivable, net
Customer		1,932			1,563
Other		1,196			486
Mark-to-market derivative assets		487			376
Inventories, net
Fossil fuel		216			198
Materials and supplies		590			559
Other		335			209
Total current assets		6,398			5,441
Property, plant and equipment, net		29,941			27,341
Deferred debits and other assets
Regulatory assets		4,140			4,872
Nuclear decommissioning trust (NDT) funds		6,408			6,669
Investments		732			724
Goodwill		2,625			2,625
Mark-to-market derivative assets		409			649
Pledged assets for Zion Station decommissioning		824			—
Other		763			859
Total deferred debits and other assets		15,901			16,398
Total assets	$	52,240		$	49,180
Liabilities and shareholders’ equity
Current liabilities
Short-term borrowings	$	—		$	155
Short-term notes payable — accounts receivable agreement		225			—
Long-term debt due within one year		599			639
Long-term debt to PECO Energy Transition Trust due within one year		—			415
Accounts payable		1,373			1,345
Mark-to-market derivative liabilities		38			198
Accrued expenses		1,040			923
Deferred income taxes		85			152
Other		880			411
Total current liabilities		4,240			4,238
Long-term debt		11,614			10,995
Long-term debt to financing trusts		390			390
Deferred credits and other liabilities
Deferred income taxes and unamortized investment tax credits		6,621			5,750
Asset retirement obligations		3,494			3,434
Pension obligations		3,658			3,625
Non-pension postretirement benefit obligations		2,218			2,180
Spent nuclear fuel obligation		1,018			1,017
Regulatory liabilities		3,555			3,492
Mark-to-market derivative liabilities		21			23
Payable for Zion Station decommissioning		659			—
Other		1,102			1,309
Total deferred credits and other liabilities		22,346			20,830
Total liabilities		38,590			36,453
Preferred securities of subsidiary		87			87
Shareholders’ equity
Common stock		9,006			8,923
Treasury stock, at cost		(2,327	)		(2,328	)
Retained earnings		9,304			8,134
Accumulated other comprehensive loss, net		(2,423	)		(2,089	)
Total shareholders’ equity		13,560			12,640
Noncontrolling interest		3			—
Total equity		13,563			12,640
Total liabilities and shareholders’ equity	$	52,240		$	49,180

5

EXELON CORPORATION

Consolidated Statements of Cash Flows

(unaudited)

(in millions)

	Twelve Months Ended
	December 31,
	2010			2009
Cash flows from operating activities
Net income	$	2,563		$	2,707
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation, amortization and accretion, including nuclear fuel amortization		2,943			2,601
Impairment of long-lived assets		—			223
Deferred income taxes and amortization of investment tax credits		981			756
Net fair value changes related to derivatives		(88	)		(95	)
Net realized and unrealized gains on NDT fund investments		(105	)		(207	)
Other non-cash operating activities		609			652
Changes in assets and liabilities:
Accounts receivable		(232	)		234
Inventories		(62	)		51
Accounts payable, accrued expenses and other current liabilities		472			(254	)
Options premiums paid, net		(124	)		(40	)
Counterparty collateral received (posted), net		(155	)		196
Income taxes		(543	)		(29	)
Pension and non-pension postretirement benefit contributions		(959	)		(588	)
Other assets and liabilities		(56	)		(113	)
Net cash flows provided by operating activities		5,244			6,094
Cash flows from investing activities
Capital expenditures		(3,326	)		(3,273	)
Proceeds from nuclear decommissioning trust fund sales		3,764			4,292
Investment in nuclear decommissioning trust funds		(3,907	)		(4,531	)
Acquisition of Exelon Wind		(893	)		—
Proceeds from sales of investments		28			41
Purchases of investments		(22	)		(28	)
Change in restricted cash		423			35
Other investing activities		39			6
Net cash flows used in investing activities		(3,894	)		(3,458	)
Cash flows from financing activities
Changes in short-term debt		(155	)		(56	)
Issuance of long-term debt		1,398			1,987
Retirement of long-term debt		(828	)		(1,773	)
Retirement of long-term debt of variable interest entity		(806	)		—
Retirement of long-term debt to financing affiliates		—			(709	)
Dividends paid on common stock		(1,389	)		(1,385	)
Proceeds from employee stock plans		48			42
Other financing activities		(16	)		(3	)
Net cash flows used in financing activities		(1,748	)		(1,897	)
Increase (decrease) in cash and cash equivalents		(398	)		739
Cash and cash equivalents at beginning of period		2,010			1,271
Cash and cash equivalents at end of period	$	1,612		$	2,010

6

EXELON CORPORATION

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

(unaudited)

(in millions, except per share data)

	Three Months Ended December 31, 2010									Three Months Ended December 31, 2009
	GAAP (a)			Adjustments			Adjusted Non-GAAP			GAAP (a)			Adjustments			Adjusted Non-GAAP
Operating revenues	$	4,494		$	6	(c)	$	4,500		$	4,116		$	32	(c),(i)	$	4,148
Operating expenses
Purchased power		1,152			(145	)(d)		1,007			815			(36	)(d)		779
Fuel		541			(41	)(d)		500			425			78	(d)		503
Operating and maintenance		1,160			(2	)(e),(f),(g)		1,158			1,120			(24	)(e)		1,096
Operating and maintenance for regulatory required programs (b)		44			—			44			19			—			19
Depreciation and amortization		465			(23	)(e)		442			474			(32	)(e)		442
Taxes other than income		193			—			193			187			—			187
Total operating expenses		3,555			(211	)		3,344			3,040			(14	)		3,026
Operating income		939			217			1,156			1,076			46			1,122
Other income and deductions
Interest expense		(183	)		—			(183	)		(176	)		—			(176	)
Loss in equity method investments		—			—			—			(6	)		—			(6	)
Other, net		135			(83	)(h)		52			60			(18	)(h),(j)		42
Total other income and deductions		(48	)		(83	)		(131	)		(122	)		(18	)		(140	)
Income before income taxes		891			134			1,025			954			28			982
Income taxes		367			27	(c),(d),(e),  (f),(g),(h)		394			373			(1)	(c),(d),(e),  (h),(i),(j)		372
Net income	$	524		$	107		$	631		$	581		$	29		$	610
Effective tax rate		41.2	%					38.4	%		39.1	%					37.9	%
Earnings per average common share
Basic	$	0.79		$	0.17		$	0.96		$	0.88		$	0.04		$	0.92
Diluted	$	0.79		$	0.17		$	0.96		$	0.88		$	0.04		$	0.92
Average common shares outstanding
Basic		662						662			660						660
Diluted		663						663			662						662
Effect of adjustments on earnings per average diluted common share recorded in accordance with GAAP:
2007 Illinois electric rate settlement (c)				$	0.01								$	0.02
Mark-to-market impact of economic hedging activities (d)					0.17									(0.04	)
Retirement of fossil generating units (e)					0.03									0.05
Acquisition costs (f)					0.01									—
Asset retirement obligation reduction (g)					(0.01	)								—
Unrealized gains related to NDT fund investments (h)					(0.04	)								(0.02	)
City of Chicago Settlement with ComEd (i)					—									0.01
Costs associated with early debt retirements (j)					—									0.02
Total adjustments				$	0.17								$	0.04

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

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

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

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

(e) Adjustment to exclude costs associated with the planned retirement of fossil generating units.

(f) Adjustment to exclude external costs associated with Exelon’s acquisition of John Deere Renewables, LLC (JDR) (now known as Exelon Wind).

(g) Adjustment to exclude a decrease in 2010 in ComEd and PECO’s asset retirement obligations.

(h) Adjustment to exclude unrealized gains in 2010 and 2009 associated with Generation’s NDT fund investments and the associated contractual accounting relating to income taxes.

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

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

7

EXELON CORPORATION

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

(unaudited)

(in millions, except per share data)

	Twelve Months Ended December 31, 2010									Twelve Months Ended December 31, 2009
	GAAP (a)			Adjustments			Adjusted Non-GAAP			GAAP (a)			Adjustments			Adjusted Non-GAAP
Operating revenues	$	18,644		$	25	(c),(d)	$	18,669		$	17,318		$	114	(c),(d)	$	17,432
Operating expenses
Purchased power		4,425			(3	)(e)		4,422			3,215			94	(e)		3,309
Fuel		2,010			32	(e),(f)		2,042			2,066			87	(e)		2,153
Operating and maintenance		4,453			(4)	(g),(h),(i),  (j)		4,449			4,612			(265)	(c),(h),(i),(j),  (m),(n)		4,347
Operating and maintenance for regulatory required programs (b)		147			—			147			63			—			63
Depreciation and amortization		2,075			(80	)(h)		1,995			1,834			(32	)(h)		1,802
Taxes other than income		808			—			808			778			—			778
Total operating expenses		13,918			(55	)		13,863			12,568			(116	)		12,452
Operating income		4,726			80			4,806			4,750			230			4,980
Other income and deductions
Interest expense		(817	)		103	(k)		(714	)		(731	)		12	(k),(o)		(719	)
Loss in equity method investments		—			—			—			(27	)		—			(27	)
Other, net		312			(153	)(k),(l)		159			427			(324	)(k),(l),(o)		103
Total other income and deductions		(505	)		(50	)		(555	)		(331	)		(312	)		(643	)
Income before income taxes		4,221			30			4,251			4,419			(82	)		4,337
Income taxes		1,658			(96)	(c),(d),(e),  (f),(g),(h),  (i),(j),(k),(l)		1,562			1,712			(98)	(c),(d),(e),(h),  (i),(j),(k),(l),  (m),(n),(o)		1,614
Net income	$	2,563		$	126		$	2,689		$	2,707		$	16		$	2,723
Effective tax rate		39.3	%					36.7	%		38.7	%					37.2	%
Earnings per average common share
Basic	$	3.88		$	0.19		$	4.07		$	4.10		$	0.03		$	4.13
Diluted	$	3.87		$	0.19		$	4.06		$	4.09		$	0.03		$	4.12
Average common shares outstanding
Basic		661						661			659						659
Diluted		663						663			662						662
Effect of adjustments on earnings per average diluted common share recorded in accordance with GAAP:
2007 Illinois electric rate settlement (c)				$	0.02								$	0.10
City of Chicago settlement (d)					—									0.01
Mark-to-market impact of economic hedging activities (e)					(0.08	)								(0.16	)
Impairment of certain emissions allowances (f)					0.05									—
Charge resulting from health care legislation (g)					0.10									—
Retirement of fossil generating units (h)					0.08									0.05
Acquisition costs (i)					0.01									0.03
Asset retirement obligation reduction (j)					(0.01	)								(0.05	)
Remeasurement of income tax uncertainties (k)					0.10									(0.10	)
Unrealized gains related to NDT fund investments (l)					(0.08	)								(0.19	)
2009 restructuring charges (m)					—									0.03
Impairment of certain generating assets (n)					—									0.20
Costs associated with early debt retirements (o)					—									0.11
Total adjustments				$	0.19								$	0.03

(a) Results reported in accordance with GAAP.

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

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

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

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

(f) Adjustment to exclude a non-cash charge for the impairment of certain SO2 emission allowances as a result of declining market prices since the release of the EPA’s proposed Transport Rule in the third quarter of 2010.

(g) Adjustment to exclude a non-cash charge related to the passage of Federal health care legislation that reduces the deductibility of retiree prescription drug benefits for Federal income tax purposes to the extent they are reimbursed under Medicare Part D.

(h) Adjustment to exclude costs associated with the planned retirement of fossil generating units.

(i) Adjustment to exclude external costs associated with Exelon’s acquisition of JDR (now known as Exelon Wind) and the proposed acquisition of NRG, which was terminated in July 2009.

(j) Adjustment to exclude a decrease in 2010 in ComEd and PECO’s asset retirement obligations and a decrease in 2009 in Generation’s decomissioning obligation.

(k) Adjustment to exclude 2010 and 2009 remeasurements of income tax uncertainties and a 2009 change in state deferred income taxes.

(l) Adjustment to exclude unrealized gains in 2010 and 2009 associated with Generation’s NDT fund investments and the associated contractual accounting relating to income taxes.

(m) Adjustment to exclude 2009 charges associated with the elimination of management and staff positions.

(n) Adjustment to exclude a non-cash charge for the impairment of certain of Generation’s Texas plants.

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

8

EXELON CORPORATION

Reconciliation of Adjusted (non-GAAP) Operating

Earnings to GAAP Earnings (in millions)

Three Months Ended December 31, 2010 and 2009

	Exelon Earnings per Diluted Share			Generation			ComEd			PECO			Other			Exelon
2009 GAAP Earnings (Loss)	$	0.88		$	425		$	98		$	78		$	(20	)	$	581
2009 Adjusted (non-GAAP) Operating Earnings (Loss) Adjustments:
2007 Illinois Electric Rate Settlement		0.02			13			2			—			—			15
Mark-to-Market Impact of Economic Hedging Activities		(0.04	)		(26	)		—			—			—			(26	)
Unrealized Gains Related to NDT Fund Investments (1)		(0.02	)		(14	)		—			—			—			(14	)
City of Chicago Settlement with ComEd		0.01			—			5			—			—			5
Costs Associated with Early Debt Retirements		0.02			9			—			—			6			15
Retirement of Fossil Generating Units (2)		0.05			34			—			—			—			34
2009 Adjusted (non-GAAP) Operating Earnings (Loss)		0.92			441			105			78			(14	)		610
Year Over Year Effects on Earnings:
Generation Energy Margins, Excluding Mark-to-Market:
Nuclear Output (3)		0.04			27			—			—			—			27
Nuclear Fuel Costs (4)		(0.02	)		(15	)		—			—			—			(15	)
Reliability Pricing Model (RPM) Capacity Pricing		0.07			48			—			—			—			48
Market and Portfolio Conditions (5)		(0.03	)		(22	)		—			—			—			(22	)
ComEd and PECO Margins:
Weather		0.02			—			4			6			—			10
Load		(0.01	)		—			(5	)		—			—			(5	)
Other Energy Delivery		0.01			—			—			5			—			5
Competitive Transition Charge (CTC) Recoveries (6)		—			75			—			(68	)		(7	)		—
Operating and Maintenance Expense:
Bad Debt (7)		0.01			(2	)		7			(1	)		—			4
Labor, Contracting and Materials (8)		(0.04	)		(14	)		(7	)		(7	)		—			(28	)
Planned Nuclear Refueling Outages		—			1			—			—			—			1
Other Operating and Maintenance (9)		—			7			(2	)		—			(3	)		2
Pension and Non-Pension Postretirement Benefits (10)		(0.01	)		(2	)		(2	)		—			(1	)		(5	)
Depreciation and Amortization Expense (11)		(0.03	)		(17	)		(4	)		(2	)		5			(18	)
Scheduled CTC Amortization Expense (12)		0.02			—			—			15			—			15
Income Taxes		—			8			(5	)		(13	)		8			(2	)
Interest Expense		—			(5	)		(4	)		7			1			(1	)
Other (13)		0.01			8			(2	)		—			(1	)		5
2010 Adjusted (non-GAAP) Operating Earnings (Loss)		0.96			538			85			20			(12	)		631
2010 Adjusted (non-GAAP) Operating Earnings (Loss) Adjustments:
2007 Illinois Electric Rate Settlement		(0.01	)		(4	)		—			—			—			(4	)
Mark-to-Market Impact of Economic Hedging Activities		(0.17	)		(113	)		—			—			—			(113	)
Unrealized Gains Related to NDT Fund Investments (1)		0.04			26			—			—			—			26
Retirement of Fossil Generating Units (2)		(0.03	)		(17	)		—			—			—			(17	)
JDR Acquisition Costs (14)		(0.01	)		(6	)		—			—			—			(6	)
Asset Retirement Obligation Reduction (15)		0.01			—			6			1			—			7
2010 GAAP Earnings (Loss)	$	0.79		$	424		$	91		$	21		$	(12	)	$	524

(1) Reflects the impact of unrealized gains in 2009 and 2010 on NDT fund investments to the extent not offset by contractual accounting as described in the notes to the consolidated financial statements.

(2) Reflects incremental accelerated depreciation, inventory write-downs and severance costs associated with the planned retirement of four fossil generating units.

(3) Primarily reflects the impact of decreased planned and unplanned nuclear outage days in 2010, including Salem.

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

(5) Primarily reflects the impact of a decrease in realized market prices for the sale of energy.

(6) Reflects decreased CTC revenues at PECO as scheduled in connection with the end of the transition period, which resulted in higher energy prices paid to Generation under the PPA. Generation and PECO’s marginal tax rate differences are reflected at Exelon Corporate.

(7) Primarily reflects increased collection activities at ComEd.

(8) Primarily reflects the impact of increased wages and incentive compensation benefits, as well as the impact of inflation related to contracting and materials expense.

(9) Primarily reflects the 2010 impact of a nuclear insurance credit at Generation.

(10) Primarily reflects the impact of a lower assumed discount rate used in 2010 as compared to 2009 to calculate the pension and other postretirement benefit obligations and costs.

(11) Primarily reflects increased depreciation expense across the operating companies due to ongoing capital expenditures and the impact of a first quarter 2010 depreciation study at Generation.

(12) Reflects decreased amortization expense of CTCs at PECO as scheduled in connection with the end of the transition period.

(13) Primarily reflects realized gains associated with NDT funds at Generation as a result of favorable market conditions in 2010.

(14) Reflects external costs incurred associated with Exelon’s acquisition of JDR (now known as Exelon Wind).

(15) Reflects a decrease in ComEd and PECO’s asset retirement obligations primarily related to transmission and distribution substation assets.

9

EXELON CORPORATION

Reconciliation of Adjusted (non-GAAP) Operating

Earnings to GAAP Earnings (in millions)

Twelve Months Ended December 31, 2010 and 2009

	Exelon Earnings per Diluted Share			Generation			ComEd			PECO			Other			Exelon
2009 GAAP Earnings (Loss)	$	4.09		$	2,122		$	374		$	353		$	(142	)	$	2,707
2009 Adjusted (non-GAAP) Operating Earnings (Loss) Adjustments:
2007 Illinois Electric Rate Settlement		0.10			62			4			—			—			66
Mark-to-Market Impact of Economic Hedging Activities		(0.16	)		(110	)		—			—			—			(110	)
Unrealized Gains Related to NDT Fund Investments (1)		(0.19	)		(132	)		—			—			—			(132	)
Asset Retirement Obligation Reduction (2)		(0.05	)		(32	)		—			—			—			(32	)
City of Chicago Settlement with ComEd		0.01			—			5			—			—			5
NRG Acquisition Costs (3)		0.03			—			—			—			20			20
Impairment of Certain Generating Assets (4)		0.20			135			—			—			—			135
2009 Restructuring Charges (5)		0.03			7			13			1			1			22
Non-Cash Remeasurement of Income Tax Uncertainties and Reassessment of State Deferred Income Taxes (6)		(0.10	)		(38	)		(40	)		—			12			(66	)
Costs Associated with Early Debt Retirements		0.11			44			—			—			30			74
Retirement of Fossil Generating Units (7)		0.05			34			—			—			—			34
2009 Adjusted (non-GAAP) Operating Earnings (Loss)		4.12			2,092			356			354			(79	)		2,723
Year Over Year Effects on Earnings:
Generation Energy Margins, Excluding Mark-to-Market:
Nuclear Output (8)		(0.02	)		(11	)		—			—			—			(11	)
Nuclear Fuel Costs (9)		(0.11	)		(70	)		—			—			—			(70	)
RPM Capacity Pricing		0.19			125			—			—			—			125
Market and Portfolio Conditions (10)		(0.13	)		(86	)		—			—			—			(86	)
ComEd and PECO Margins:
Weather		0.16			—			54			54			—			108
Load		—			—			(2	)		1			—			(1	)
Other Energy Delivery		(0.02	)		—			(4	)		(10	)		—			(14	)
CTC Recoveries (11)		—			(41	)		—			45			(4	)		—
Operating and Maintenance Expense:
Bad Debt (12)		0.04			—			24			2			—			26
Recovery of Prior Year Bad Debt Expense at ComEd (13)		0.06			—			36			—			—			36
Labor, Contracting and Materials (14)		(0.07	)		(33	)		5			(19	)		—			(47	)
Planned Nuclear Refueling Outages		(0.02	)		(11	)		—			—			—			(11	)
Other Operating and Maintenance (15)		(0.03	)		15			(9	)		(11	)		(17	)		(22	)
Pension and Non-Pension Postretirement Benefits (16)		(0.03	)		(14	)		(4	)		—			2			(16	)
Depreciation and Amortization Expense (17)		(0.09	)		(58	)		(12	)		(7	)		18			(59	)
Scheduled CTC Amortization Expense (18)		(0.10	)		—			—			(67	)		—			(67	)
Income Taxes (19)		0.05			34			(11	)		(8	)		18			33
Interest Expense (20)		0.03			(30	)		(1	)		36			15			20
Other (21)		0.03			16			20			(15	)		1			22
2010 Adjusted (non-GAAP) Operating Earnings (Loss)		4.06			1,928			452			355			(46	)		2,689
2010 Adjusted (non-GAAP) Operating Earnings (Loss) Adjustments:
2007 Illinois Electric Rate Settlement		(0.02	)		(12	)		(1	)		—			—			(13	)
Mark-to-Market Impact of Economic Hedging Activities		0.08			52			—			—			—			52
Unrealized Gains Related to NDT Fund Investments (1)		0.08			52			—			—			—			52
City of Chicago Settlement with ComEd		—			—			(2	)		—			—			(2	)
Asset Retirement Obligation Reduction (2)		0.01			—			6			1			—			7
Retirement of Fossil Generating Units (7)		(0.08	)		(50	)		—			—			—			(50	)
Non-Cash Charge Resulting From Health Care Legislation (22)		(0.10	)		(26	)		(12	)		(10	)		(17	)		(65	)
Non-Cash Remeasurement of Income Tax Uncertainties (6)		(0.10	)		70			(106	)		(22	)		(7	)		(65	)
Impairment of Certain Emissions Allowances (23)		(0.05	)		(35	)		—			—			—			(35	)
JDR Acquisition Costs (24)		(0.01	)		(7	)		—			—			—			(7	)
2010 GAAP Earnings (Loss)	$	3.87		$	1,972		$	337		$	324		$	(70	)	$	2,563

(1) Reflects the impact of unrealized gains in 2009 and 2010 on NDT fund investments to the extent not offset by contractual accounting as described in the notes to the consolidated financial statements.

(2) Reflects a decrease in 2009 of Generation’s decommissioning obligation liability primarily related to the former AmerGen nuclear plants and a decrease in 2010 of ComEd and PECO’s asset retirement obligations primarily related to transmission and distribution substation assets.

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

(4) Reflects the impact of the impairment of certain of Generation’s Texas plants.

(5) Reflects severance expense associated with the elimination of management and staff positions in 2009.

(6) For 2009, reflects the impacts of a remeasurement of income tax uncertainties related to ComEd’s 1999 sale of fossil generating units and a reassessment of anticipated apportionment of Exelon’s income. For 2010, reflects the impact of a remeasurement of income tax uncertainties related to ComEd’s 1999 sale of fossil generating assets and related to CTCs received by PECO.

(7) Reflects incremental accelerated depreciation, inventory write-downs and severance costs associated with the planned retirement of four fossil generating units.

(8) Primarily reflects the impact of increased unplanned nuclear outage days in the Mid-Atlantic region in 2010, including Salem.

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

(10) Primarily reflects the impact of a decrease in realized market prices for the sale of energy.

(11) Reflects increased CTC revenues at PECO resulting in lower energy prices paid to Generation under the PPA. Generation and PECO’s marginal tax rate differences are reflected at Exelon Corporate.

(12) Primarily reflects increased collection activities at ComEd.

(13) Reflects a credit for the recovery of 2008 and 2009 bad debt expense pursuant to the ICC’s February 2010 approval of a bad debt rider, partially offset by a contribution mandated by Illinois legislation.

(14) Primarily reflects the impact of increased wages and incentive compensation, as well as the impact of inflation related to contracting and materials expense (exclusive of incremental storm costs as disclosed in number 15 below).

(15) Primarily reflects increased storm costs in the ComEd and PECO service territories and increased costs associated with Exelon Transmission Company at Corporate, partially offset by reduced stock-based compensation costs across the operating companies and the 2010 impact of a nuclear insurance credit at Generation.

(16) Primarily reflects the impact of a lower assumed discount rate used in 2010 as compared to 2009 to calculate the pension and other postretirement benefit obligations and costs.

(17) Primarily reflects increased depreciation expense across the operating companies due to ongoing capital expenditures and the impact of a first quarter 2010 depreciation study at Generation.

(18) Reflects increased scheduled amortization expense of CTCs at PECO, which became fully amortized at the end of the transition period on December 31, 2010.

(19) Primarily reflects an increase in Generation’s tax benefits associated with an increase in the manufacturing deduction rate, partially offset by the incremental impact on the 2010 manufacturing tax deduction associated with the pension contribution to be made in the first quarter of 2011.

(20) Primarily reflects lower interest expense at PECO and Exelon Corporate due to lower outstanding debt, partially offset by higher interest expense at Generation due to higher outstanding debt.

(21) Primarily reflects realized gains associated with NDT funds at Generation as a result of favorable market conditions in 2010 and projected refunds related to Illinois electric distribution taxes at ComEd, partially offset by increased gross receipts tax at PECO.

(22) Reflects a non-cash charge related to the passage of Federal health care legislation that reduces the deductibility of retiree prescription drug benefits for Federal income tax purposes to the extent they are reimbursed under Medicare Part D.

(23) Reflects the impairment of certain SO2 emission allowances as a result of declining market prices since the release of the EPA’s proposed Transport Rule during the third quarter of 2010.

(24) Reflects external costs incurred associated with Exelon’s acquisition of JDR (now known as Exelon Wind).

10

EXELON CORPORATION

Reconciliation of Adjusted (non-GAAP) Operating Earnings to

GAAP Consolidated Statements of Operations

(unaudited)

(in millions)

	Generation
	Three Months Ended December 31, 2010									Three Months Ended December 31, 2009
	GAAP (a)			Adjustments			Adjusted Non- GAAP			GAAP (a)			Adjustments			Adjusted Non- GAAP
Operating revenues	$	2,596		$	6	(b)	$	2,602		$	2,278		$	20	(b)	$	2,298
Operating expenses
Purchased power		602			(145	)(c)		457			375			(36	)(c)		339
Fuel		418			(41	)(c)		377			300			78	(c)		378
Operating and maintenance		731			(13	)(d),(e)		718			727			(24	)(e)		703
Depreciation and amortization		129			(23	)(e)		106			110			(32	)(e)		78
Taxes other than income		56			—			56			55			—			55
Total operating expenses		1,936			(222	)		1,714			1,567			(14	)		1,553
Operating income		660			228			888			711			34			745
Other income and deductions
Interest expense		(44	)		—			(44	)		(36	)		—			(36	)
Other, net		118			(83	)(f)		35			50			(28	)(f),(g)		22
Total other income and deductions		74			(83	)		(9	)		14			(28	)		(14	)
Income before income taxes		734			145			879			725			6			731
Income taxes		310			31	(b),(c),(d),  (e),(f)		341			300			(10)	(b),(c),(e),(f),  (g)		290
Net income	$	424		$	114		$	538		$	425		$	16		$	441
	Twelve Months Ended December 31, 2010									Twelve Months Ended December 31, 2009
	GAAP (a)			Adjustments			Adjusted Non- GAAP			GAAP (a)			Adjustments			Adjusted Non- GAAP
Operating revenues	$	10,025		$	21	(b)	$	10,046		$	9,703		$	98	(b)	$	9,801
Operating expenses
Purchased power		1,853			(3	)(c)		1,850			1,338			94	(c)		1,432
Fuel		1,610			32	(c),(h)		1,642			1,594			87	(c)		1,681
Operating and maintenance		2,812			(18	)(d),(e),(i)		2,794			2,938			(207	)(e),(k),(l),(m)		2,731
Depreciation and amortization		474			(80	)(e)		394			333			(32	)(e)		301
Taxes other than income		230			—			230			205			—			205
Total operating expenses		6,979			(69	)		6,910			6,408			(58	)		6,350
Operating income		3,046			90			3,136			3,295			156			3,451
Other income and deductions
Interest expense		(153	)		—			(153	)		(113	)		2	(g)		(111	)
Loss in equity method investments		—			—			—			(3	)		—			(3	)
Other, net		257			(155	)(f)		102			376			(320	)(f),(g),(n)		56
Total other income and deductions		104			(155	)		(51	)		260			(318	)		(58	)
Income before income taxes		3,150			(65	)		3,085			3,555			(162	)		3,393
Income taxes		1,178			(21)	(b),(c),(d),(e),  (f),(h),(i),(j)		1,157			1,433			(132)	(b),(c),(e),  (f),(g),(k),(l),  (m),(n)		1,301
Net income	$	1,972		$	(44	)	$	1,928		$	2,122		$	(30	)	$	2,092

(a) Results reported in accordance with GAAP.

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

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

(d) Adjustment to exclude costs associated with Exelon’s acquisition of JDR (now known as Exelon Wind).

(e) Adjustment to exclude costs associated with the planned retirement of fossil generating units.

(f) Adjustment to exclude unrealized gains in 2010 and 2009 associated with Generation’s NDT fund investments to the extent not offset by contractual accounting as described in the notes to the consolidated financial statements.

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

(h) Adjustment to exclude a non-cash charge for the impairment of certain SO2 emission allowances as a result of declining market prices since the release of the EPA’s proposed Transport Rule in the third quarter of 2010.

(i) Adjustment to exclude a non-cash charge related to the passage of Federal health care legislation that reduces the deductibility of retiree prescription drug benefits for Federal income tax purposes to the extent they are reimbursed under Medicare Part D.

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

(k) Adjustment to exclude a decrease in 2009 in Generation’s decommissioning obligation.

(l) Adjustment to exclude 2009 charges associated with the elimination of management and staff positions.

(m) Adjustment to exclude a non-cash charge for the impairment of certain of Generation’s Texas plants.

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

11

EXELON CORPORATION

Reconciliation of Adjusted (non-GAAP) Operating Earnings to

GAAP Consolidated Statements of Operations

(unaudited)

(in millions)

	ComEd
	Three Months Ended December 31, 2010									Three Months Ended December 31, 2009
	GAAP (a)			Adjustments			Adjusted  Non- GAAP			GAAP (a)			Adjustments			Adjusted  Non- GAAP
Operating revenues	$	1,372		$	—		$	1,372		$	1,357		$	12	(d),(e)	$	1,369
Operating expenses
Purchased power		671			—			671			692			—			692
Operating and maintenance		247			10	(c)		257			232			—			232
Operating and maintenance for regulatory required programs (b)		27			—			27			19			—			19
Depreciation and amortization		130			—			130			123			—			123
Taxes other than income		68			—			68			67			—			67
Total operating expenses		1,143			10			1,153			1,133			—			1,133
Operating income		229			(10	)		219			224			12			236
Other income and deductions
Interest expense		(86	)		—			(86	)		(78	)		—			(78	)
Other, net		10			—			10			11			—			11
Total other income and deductions		(76	)		—			(76	)		(67	)		—			(67	)
Income before income taxes		153			(10	)		143			157			12			169
Income taxes		62			(4	)(c)		58			59			5	(d),(e)		64
Net income	$	91		$	(6	)	$	85		$	98		$	7		$	105
	Twelve Months Ended December 31, 2010									Twelve Months Ended December 31, 2009
	GAAP (a)			Adjustments			Adjusted  Non- GAAP			GAAP (a)			Adjustments			Adjusted  Non- GAAP
Operating revenues	$	6,204		$	4	(d),(e)	$	6,208		$	5,774		$	16	(d),(e)	$	5,790
Operating expenses
Purchased power		3,307			—			3,307			3,065			—			3,065
Operating and maintenance		975			7	(c),(f)		982			1,028			(20	)(d),(h)		1,008
Operating and maintenance for regulatory required programs (b)		94						94			63			—			63
Depreciation and amortization		516			—			516			494			—			494
Taxes other than income		256			—			256			281			—			281
Total operating expenses		5,148			7			5,155			4,931			(20	)		4,911
Operating income		1,056			(3	)		1,053			843			36			879
Other income and deductions
Interest expense		(386	)		59	(g)		(327	)		(319	)		(6	)(g)		(325	)
Other, net		24			—			24			79			(60	)(g)		19
Total other income and deductions		(362	)		59			(303	)		(240	)		(66	)		(306	)
Income before income taxes		694			56			750			603			(30	)		573
Income taxes		357			(59	(c),(d),  )(e),(f),(g)		298			229			(12	(d),(e),  )(g),(h)		217
Net income	$	337		$	115		$	452		$	374		$	(18	)	$	356

(a) Results reported in accordance with GAAP.

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

(c) Adjustment to exclude a decrease in 2010 in ComEd’s asset retirement obligation.

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

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

(f) Adjustment to exclude a non-cash charge related to the passage of Federal health care legislation that reduces the deductibility of retiree prescription drug benefits for Federal income tax purposes to the extent they are reimbursed under Medicare Part D.

(g) Adjustment to exclude 2010 and 2009 remeasurements of income tax uncertainties.

(h) Adjustment to exclude 2009 charges associated with the elimination of management and staff positions.

12

EXELON CORPORATION

Reconciliation of Adjusted (non-GAAP) Operating Earnings to

GAAP Consolidated Statements of Operations

(unaudited)

(in millions)

	PECO
	Three Months Ended December 31, 2010									Three Months Ended December 31, 2009
	GAAP (a)			Adjustments			Adjusted Non- GAAP			GAAP (a)			Adjustments			Adjusted Non- GAAP
Operating revenues	$	1,299		$	—		$	1,299		$	1,266		$	—		$	1,266
Operating expenses
Purchased power		652			—			652			532			—			532
Fuel		123			—			123			126			—			126
Operating and maintenance		172			1	(c)		173			159			—			159
Operating and maintenance for regulatory required programs (b)		17			—			17			—			—			—
Depreciation and amortization		201			—			201			225			—			225
Taxes other than income		64			—			64			64			—			64
Total operating expenses		1,229			1			1,230			1,106			—			1,106
Operating income		70			(1	)		69			160			—			160
Other income and deductions
Interest expense		(34	)		—			(34	)		(42	)		—			(42	)
Loss in equity method investments		—			—			—			(5	)		—			(5	)
Other, net		2			—			2			5			—			5
Total other income and deductions		(32	)		—			(32	)		(42	)		—			(42	)
Income before income taxes		38			(1	)		37			118			—			118
Income taxes		17			—	(c)		17			40			—			40
Net income	$	21		$	(1	)	$	20		$	78		$	—		$	78
	Twelve Months Ended December 31, 2010									Twelve Months Ended December 31, 2009
	GAAP (a)			Adjustments			Adjusted Non- GAAP			GAAP (a)			Adjustments			Adjusted Non- GAAP
Operating revenues	$	5,519		$	—		$	5,519		$	5,311		$	—		$	5,311
Operating expenses
Purchased power		2,361			—			2,361			2,274			—			2,274
Fuel		401			—			401			472			—			472
Operating and maintenance		680			(1	)(c),(d)		679			640			(3	)(f)		637
Operating and maintenance for regulatory required programs (b)		53			—			53			—			—			—
Depreciation and amortization		1,060			—			1,060			952			—			952
Taxes other than income		303			—			303			276			—			276
Total operating expenses		4,858			(1	)		4,857			4,614			(3	)		4,611
Operating income		661			1			662			697			3			700
Other income and deductions
Interest expense		(193	)		36	(e)		(157	)		(187	)		—			(187	)
Loss in equity method investments		—			—			—			(24	)		—			(24	)
Other, net		8			2	(e)		10			13			—			13
Total other income and deductions		(185	)		38			(147	)		(198	)		—			(198	)
Income before income taxes		476			39			515			499			3			502
Income taxes		152			8	(c),(d),(e)		160			146			2	(f)		148
Net income	$	324		$	31		$	355		$	353		$	1		$	354

(a) Results reported in accordance with GAAP.

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

(c) Adjustment to exclude a decrease in 2010 PECO’s asset retirement obligation.

(d) Adjustment to exclude a non-cash charge related to the passage of Federal health care legislation that reduces the deductibility of retiree prescription drug benefits for Federal income tax purposes to the extent they are reimbursed under Medicare Part D.

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

(f) Adjustment to exclude 2009 charges associated with the elimination of management and staff positions.

13

EXELON CORPORATION

Reconciliation of Adjusted (non-GAAP) Operating Earnings to

GAAP Consolidated Statements of Operations

(unaudited)

(in millions)

	Other
	Three Months Ended December 31, 2010									Three Months Ended December 31, 2009
	GAAP (a)			Adjustments			Adjusted Non- GAAP			GAAP (a)			Adjustments			Adjusted  Non- GAAP
Operating revenues	$	(773	)	$	—		$	(773	)	$	(785	)	$	—		$	(785	)
Operating expenses
Purchased power		(773	)		—			(773	)		(784	)		—			(784	)
Fuel		—			—			—			(1	)		—			(1	)
Operating and maintenance		10			—			10			2			—			2
Depreciation and amortization		5			—			5			16			—			16
Taxes other than income		5			—			5			1			—			1
Total operating expenses		(753	)		—			(753	)		(766	)		—			(766	)
Operating loss		(20	)		—			(20	)		(19	)		—			(19	)
Other income and deductions
Interest expense		(19	)		—			(19	)		(20	)		—			(20	)
Loss in equity method investments		—			—			—			(1	)		—			(1	)
Other, net		5			—			5			(6	)		10	(b)		4
Total other income and deductions		(14	)		—			(14	)		(27	)		10			(17	)
Loss before income taxes		(34	)		—			(34	)		(46	)		10			(36	)
Income taxes		(22	)		—			(22	)		(26	)		4	(b)		(22	)
Net loss	$	(12	)	$	—		$	(12	)	$	(20	)	$	6		$	(14	)
	Twelve Months Ended December 31, 2010									Twelve Months Ended December 31, 2009
	GAAP (a)			Adjustments			Adjusted Non- GAAP			GAAP (a)			Adjustments			Adjusted Non- GAAP
Operating revenues	$	(3,104	)	$	—		$	(3,104	)	$	(3,469	)	$	—		$	(3,469	)
Operating expenses
Purchased power		(3,096	)		—			(3,096	)		(3,462	)		—			(3,462	)
Fuel		(1	)		—			(1	)		—			—			—
Operating and maintenance		(14	)		8	(c)		(6	)		6			(35	)(e),(f)		(29	)
Depreciation and amortization		25			—			25			55			—			55
Taxes other than income		19			—			19			16			—			16
Total operating expenses		(3,067	)		8			(3,059	)		(3,385	)		(35	)		(3,420	)
Operating loss		(37	)		(8	)		(45	)		(84	)		35			(49	)
Other income and deductions
Interest expense		(85	)		8	(d)		(77	)		(112	)		16	(b),(d)		(96	)
Other, net		23			—			23			(42	)		56	(b),(d)		14
Total other income and deductions		(62	)		8			(54	)		(154	)		72			(82	)
Loss before income taxes		(99	)		—			(99	)		(238	)		107			(131	)
Income taxes		(29	)		(24	)(c),(d)		(53	)		(96	)		44	(b),(d),(e),(f)		(52	)
Net loss	$	(70	)	$	24		$	(46	)	$	(142	)	$	63		$	(79	)

(a) Results reported in accordance with GAAP.

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

(c) Adjustment to exclude a non-cash charge related to the passage of Federal health care legislation that reduces the deductibility of retiree prescription drug benefits for Federal income tax purposes to the extent they are reimbursed under Medicare Part D.

(d) Adjustment to exclude 2010 and 2009 remeasurements of income tax uncertainties.

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

(f) Adjustment to exclude 2009 charges associated with the elimination of management and staff positions.

14

EXELON CORPORATION

Exelon Generation Statistics

	Three Months Ended
	Dec. 31, 2010			Sept. 30, 2010			Jun. 30, 2010			Mar. 31, 2010			Dec. 31, 2009
Supply (in GWhs)
Nuclear Generation
Mid-Atlantic (a)		11,974			12,076			11,691			11,776			11,137
Midwest		23,141			23,675			23,344			22,333			22,472
Total Nuclear Generation		35,115			35,751			35,035			34,109			33,609
Fossil and Renewables
Mid-Atlantic (b)		2,115			2,582			2,175			2,564			1,986
Midwest		45			16			7			—			—
South and West		93			691			310			119			48
Total Fossil and Renewables		2,253			3,289			2,492			2,683			2,034
Purchased Power
Mid-Atlantic		442			599			414			463			342
Midwest		1,776			1,774			1,568			1,914			1,991
South and West		2,632			4,084			2,695			2,701			2,851
Total Purchased Power		4,850			6,457			4,677			5,078			5,184
Total Supply by Region
Mid-Atlantic		14,531			15,257			14,280			14,803			13,465
Midwest		24,962			25,465			24,919			24,247			24,463
South and West		2,725			4,775			3,005			2,820			2,899
		42,218			45,497			42,204			41,870			40,827
	Three Months Ended
	Dec. 31, 2010			Sept. 30, 2010			Jun. 30, 2010			Mar. 31, 2010			Dec. 31, 2009
Electric Sales (in GWhs)
ComEd (c)		—			—			1,895			3,428			3,439
PECO		9,756			11,976			10,044			10,228			9,588
Market and Retail (c)		32,462			33,521			30,265			28,214			27,800
Total Electric Sales (d)(e)		42,218			45,497			42,204			41,870			40,827
Average Margin ($/MWh) (f)(g)
Mid-Atlantic	$	51.75		$	36.97		$	40.83		$	41.41		$	43.15
Midwest		41.14			41.00			40.78			41.00			41.98
South and West		(10.64	)		(2.30	)		(14.31	)		(16.67	)		(14.49	)
Average Margin - Overall Portfolio	$	41.45		$	35.11		$	36.87		$	37.26		$	38.36
Around-the-clock Market Prices ($/MWh) (h)
PJM West Hub	$	43.65		$	52.25		$	43.21		$	44.54		$	37.31
NiHub		27.26			38.32			32.35			34.47			29.61
ERCOT North Spark Spread		(0.69	)		8.25			1.52			(0.02	)		(1.34	)

(a) Includes Generation’s proportionate share of the output of its nuclear generating plants, including Salem.

(b) Includes New England generation.

(c) ComEd line item represents sales under the 2006 ComEd Auction. Settlements of the ComEd swap and sales under the Request for Proposal (RFP) are included within Market and Retail sales. In addition, renewable energy credit sales to affiliates have been included within Market and Retail sales.

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

(e) Total sales do not include trading volume of 740 GWhs, 1,077 GWhs, 889 GWhs, 920 GWhs and 1,599 GWhs for the three months ended December 31, 2010, September 30, 2010, June 30, 2010, March 31, 2010 and December 31, 2009, respectively.

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

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

(h) Represents the average for the quarter.

15

EXELON CORPORATION

Exelon Generation Statistics

Twelve Months Ended December 31, 2010 and 2009

	December 31, 2010			December 31, 2009
Supply (in GWhs)
Nuclear Generation
Mid-Atlantic (a)		47,517			47,866
Midwest		92,493			91,804
Total Nuclear Generation		140,010			139,670
Fossil and Renewables
Mid-Atlantic (b)		9,436			8,938
Midwest		68			4
South and West		1,213			1,247
Total Fossil and Renewables		10,717			10,189
Purchased Power
Mid-Atlantic		1,918			1,747
Midwest		7,032			7,738
South and West		12,112			13,721
Total Purchased Power		21,062			23,206
Total Supply by Region
Mid-Atlantic		58,871			58,551
Midwest		99,593			99,546
South and West		13,325			14,968
		171,789			173,065
	December 31, 2010			December 31, 2009
Electric Sales (in GWhs)
ComEd (c)		5,323			16,830
PECO		42,003			39,897
Market and Retail (c)		124,463			116,338
Total Electric Sales (d)(e)		171,789			173,065
Average Margin ($/MWh) (f)(g)
Mid-Atlantic	$	42.67		$	44.03
Midwest		40.98			41.67
South and West		(9.83	)		(7.82	)
Average Margin - Overall Portfolio	$	37.62		$	38.20
Around-the-clock Market Prices ($/MWh) (h)
PJM West Hub	$	45.93		$	38.30
NiHub		33.09			28.85
ERCOT North Spark Spread		2.31			0.35

(a) Includes Generation’s proportionate share of the output of its nuclear generating plants, including Salem.

(b) Includes New England generation.

(c) ComEd line item represents sales under the 2006 ComEd Auction. Settlements of the ComEd swap and sales under the RFP are included within Market and Retail sales. In addition, renewable energy credit sales to affiliates have been included within Market and Retail sales.

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

(e) Total sales do not include trading volume of 3,625 GWhs and 7,578 GWhs for the years ended December 31, 2010 and 2009, respectively.

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

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

(h) Represents the average for the years ended December 31, 2010 and 2009, respectively.

16

EXELON CORPORATION

ComEd Statistics

Three Months Ended December 31, 2010 and 2009

	Electric Deliveries (in GWhs)										Revenue (in millions)
	2010		2009		% Change			Weather- Normal % Change			2010		2009		% Change
Retail Deliveries and Sales (a)
Residential		6,393		6,541		(2.3	)%		(4.1	)%	$	761	$	741		2.7	%
Small Commercial & Industrial		7,929		7,897		0.4	%		(1.5	)%		366		378		(3.2	)%
Large Commercial & Industrial		6,725		6,505		3.4	%		1.9	%		91		93		(2.2	)%
Public Authorities & Electric Railroads		346		329		5.2	%		2.9	%		14		15		(6.7	)%
Total Retail		21,393		21,272		0.6	%		(1.2	)%		1,232		1,227		0.4	%
Other Revenue (b)												140		130		7.7	%
Total Electric Revenue											$	1,372	$	1,357		1.1	%
Purchased Power											$	671	$	692		(3.0	)%

							% Change
Heating and Cooling Degree-Days	2010		2009		Normal		From 2009			From Normal
Heating Degree-Days		2,292		2,264		2,278		1.2	%		0.6	%
Cooling Degree-Days		15		—		7		n/a			114.3	%

Twelve Months Ended December 31, 2010 and 2009

	Electric Deliveries (in GWhs)										Revenue (in millions)
	2010		2009		% Change			Weather- Normal %  Change			2010		2009		% Change
Retail Deliveries and Sales (a)
Residential		29,171		26,621		9.6	%		(1.2	)%	$	3,549	$	3,115		13.9	%
Small Commercial & Industrial		32,904		32,234		2.1	%		(0.6	)%		1,639		1,660		(1.3	)%
Large Commercial & Industrial		27,717		26,668		3.9	%		2.6	%		397		387		2.6	%
Public Authorities & Electric Railroads		1,273		1,237		2.9	%		2.4	%		62		57		8.8	%
Total Retail		91,065		86,760		5.0	%		0.2	%		5,647		5,219		8.2	%
Other Revenue (b)												557		555		0.4	%
Total Electric Revenue											$	6,204	$	5,774		7.4	%
Purchased Power											$	3,307	$	3,065		7.9	%

							% Change
Heating and Cooling Degree-Days	2010		2009		Normal		From 2009			From Normal
Heating Degree-Days		5,991		6,429		6,362		(6.8	)%		(5.8	)%
Cooling Degree-Days		1,181		589		855		100.5	%		38.1	%
Number of Electric Customers	2010		2009
Residential		3,438,677		3,425,570
Small Commercial & Industrial		363,393		360,779
Large Commercial & Industrial		2,005		1,985
Public Authorities & Electric Railroads		5,078		5,008
Total		3,809,153		3,793,342

(a) Reflects delivery revenues and volumes from customers purchasing electricity directly from ComEd and customers purchasing electricity from a competitive electric generation supplier as all customers are assessed delivery charges. For customers purchasing electricity from ComEd, revenue also reflects the cost of energy.

(b) Other revenue primarily includes transmission revenue from PJM Interconnection, LLC (PJM).

17

EXELON CORPORATION

PECO Statistics

Three Months Ended December 31, 2010 and 2009

	Electric and Gas Deliveries										Revenue (in millions)
	2010		2009		% Change			Weather- Normal %  Change			2010		2009		% Change
Electric (in GWhs)
Retail Deliveries and Sales (a)
Residential		3,124		3,088		1.2	%		(0.7	)%	$	444	$	429		3.5	%
Small Commercial & Industrial		1,958		1,965		(0.4	)%		(2.0	)%		233		232		0.4	%
Large Commercial & Industrial		3,975		3,878		2.5	%		1.5	%		327		312		4.8	%
Public Authorities & Electric Railroads		226		228		(0.9	)%		(0.3	)%		22		22		0.0	%
Total Retail		9,283		9,159		1.4	%		(0.0	)%		1,026		995		3.1	%
Other Revenue (b)												61		59		3.4	%
Total Electric Revenue												1,087		1,054		3.1	%
Gas (in mmcfs)
Retail Sales		19,730		17,659		11.7	%		0.7	%		205		202		1.5	%
Transportation and Other		7,253		7,078		2.5	%		2.2	%		7		10		(30.0	)%
Total Gas		26,983		24,737		9.1	%		1.1	%		212		212		0.0	%
Total Electric and Gas Revenues											$	1,299	$	1,266		2.6	%
Purchased Power											$	652	$	532		22.6	%
Fuel												123		126		(2.4	)%
Total Purchased Power and Fuel											$	775	$	658		17.8	%

							% Change
Heating and Cooling Degree-Days	2010		2009		Normal		From 2009			From Normal
Heating Degree-Days		1,686		1,567		1,634		7.6	%		3.2	%
Cooling Degree-Days		19		10		21		90.0	%		(9.5	%)

Twelve Months Ended December 31, 2010 and 2009

	Electric and Gas Deliveries										Revenue (in millions)
	2010		2009		% Change			Weather- Normal %  Change			2010		2009		% Change
Electric (in GWhs)
Retail Deliveries and Sales (a)
Residential		13,913		12,893		7.9	%		0.5	%	$	2,069	$	1,859		11.3	%
Small Commercial & Industrial		8,503		8,397		1.3	%		(1.9	)%		1,060		1,034		2.5	%
Large Commercial & Industrial		16,372		15,848		3.3	%		0.8	%		1,362		1,307		4.2	%
Public Authorities & Electric Railroads		925		930		(0.5	)%		(0.3	)%		89		90		(1.1	)%
Total Retail		39,713		38,068		4.3	%		0.1	%		4,580		4,290		6.8	%
Other Revenue (b)												255		259		(1.5	)%
Total Electric Revenue												4,835		4,549		6.3	%
Gas (in mmcfs)
Retail Sales		56,833		57,103		(0.5	)%		0.9	%		656		732		(10.4	)%
Transportation and Other		30,911		27,206		13.6	%		10.8	%		28		30		(6.7	)%
Total Gas		87,744		84,309		4.1	%		4.1	%		684		762		(10.2	)%
Total Electric and Gas Revenues											$	5,519	$	5,311		3.9	%
Purchased Power											$	2,361	$	2,274		3.8	%
Fuel												401		472		(15.0	)%
Total Purchased Power and Fuel											$	2,762	$	2,746		0.6	%

							% Change
Heating and Cooling Degree-Days	2010		2009		Normal		From 2009			From Normal
Heating Degree-Days		4,396		4,534		4,638		(3.0	)%		(5.2	)%
Cooling Degree-Days		1,817		1,246		1,292		45.8	%		40.6	%

Number of Electric Customers	2010		2009		Number of Gas Customers	2010		2009
Residential		1,411,643		1,404,416	Residential		448,391		444,923
Small Commercial & Industrial		156,865		156,305	Commercial & Industrial		41,303		40,991
Large Commercial & Industrial		3,071		3,094	Total Retail		489,694		485,914
Public Authorities & Electric Railroads		1,102		1,085	Transportation		838		778
Total		1,572,681		1,564,900	Total		490,532		486,692

(a) Reflects delivery revenues and volumes from customers purchasing electricity directly from PECO and customers purchasing electricity from a competitive electric generation supplier as all customers are assessed delivery charges and a CTC. For customers purchasing electricity from PECO, revenue should also reflects the cost of energy.

(b) Other revenue includes transmission revenue from PJM and wholesale revenues.

18

EX-99.2

Earnings Conference Call

4

th

Quarter 2010

January 26, 2011

Exhibit 99.2

2

Forward-Looking Statements

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

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

actual results to differ materially from these forward-looking statements include those discussed

herein as well as those discussed in (1) Exelon’s 2009 Annual Report on Form 10-K in (a) ITEM 1A.

Risk Factors, (b) ITEM 7. Management’s Discussion and Analysis of Financial Condition and Results

of Operations and (c) ITEM 8. Financial Statements and Supplementary Data: Note 18; (2) Exelon’s

Third Quarter 2010 Quarterly Report on Form 10-Q in (a) Part II, Other Information, ITEM 1A.  Risk

Factors, (b) Part 1, Financial Information, ITEM 2. Management’s Discussion and Analysis of

Financial Condition and Results of Operations and (c) Part I , Financial Information, ITEM 1. Financial

Statements: Note 13 and (3) other factors discussed in filings with the Securities and Exchange

Commission (SEC) by Exelon Corporation, Commonwealth Edison Company, PECO Energy

Company and Exelon Generation Company, LLC (Companies). Readers are cautioned not to place

undue reliance on these forward-looking statements, which apply only as of the date of this

presentation.

None

of

the

Companies

undertakes

any

obligation

to

publicly

release

any

revision

to

its

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

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

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

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

Please refer to the appendix to this presentation for a reconciliation of adjusted (non-GAAP) operating

earnings

to

GAAP

earnings.

Please

refer

to

the

footnotes

of

the

following

slides

for

a

reconciliation

of

non-GAAP cash flows to GAAP cash flows.

3

2010: Another Strong Year for Exelon

Exemplary year of financial

and operational performance

•

Operating earnings of

$4.06/share

(1)

•

2010 Cash from operations

of $5.3 billion

(2)

•

Returned $1.4 billion in cash

to shareholders through

dividends

Continuing to position Exelon

for cleaner energy future

Strong reliability scores despite significant storm

activity

Highest customer satisfaction scores in > 5 yrs

Completed electric and gas distribution rate cases

Best

customer

satisfaction

scores

in

PECO

history

Eighth consecutive year with nuclear capacity

factor above 93%

59 MW added through nuclear uprate program

Acquired John Deere Renewables

Announced early retirement of Oyster Creek

RITE line project announced

(1)

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

(2)

2010 Cash from operations excludes counterparty collateral and includes net cash from investing activities other than capital expenditures, acquisition of Exelon Wind and change in

restricted cash.

4

2011 Operating Earnings Guidance

2011E

(2)

2010A

$0.54

$2.91

$4.06

(1)

ComEd

PECO

Exelon

Generation

ComEd

PECO

Exelon

Generation

Holdco

Holdco

Exelon

$0.68

Exelon

$3.90 -

$4.20

(1)

$0.55 -

$0.65

$0.50 -

$0.55

$2.85 -

$3.05

Key Drivers of FY Guidance

+

Generation margins driven by PECO

PPA roll-off, partially offset by lower

capacity revenues

+

Higher PECO gross margin driven by

new distribution rates effective 1/1/11

-

Higher O&M expense

-

Higher depreciation & amortization

expense

Introducing

2011

operating

earnings

guidance

of

$3.90

–

$4.20/share

and

1Q

2011

guidance

of

$1.00

–

$1.10/share

(1)

(1)

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

(2)

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

5

2017/

2018

2016/

2017

2015/

2016

2014/

2015

PJM RPM Auctions

Delivery Year

2010

2011

2012

2013

2014

2015

2016

2017

2018

EPA Regulations Will Move Forward in 2011

Notes: RPM auctions take place annually in May.

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

6

Key Financial Messages

2010

operating

earnings

of

$4.06/share

(1)

in

line

with

expectations

•

Higher capacity and energy (PECO PPA) revenues at ExGen

•

Higher earnings (vs. 2009) at ComEd

2011

earnings

guidance

of

$3.90

-

$4.20/share

(1)

•

Expiration

of

PECO

PPA

allows

ExGen

to

sell

additional

energy

at

market

prices,

offset by lower RPM capacity prices and higher costs

•

New distribution rates effective 1/1/11 at PECO

Strong cash flows in 2011

•

Expect to generate $4.3 billion cash from operations in 2011

•

Increasing investment in growth projects at ExGen and Utilities

Efficient use of cash benefits from bonus depreciation

•

$2.1 billion pension contribution proactively reduces pension costs and future

contributions while improving pension funding status

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

7

Exelon Generation

Operating EPS Contribution

2010

2009

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

(2) Outage days exclude Salem. 

97

136

Refueling

18

23

Non-refueling

4Q10

4Q09

Outage Days

(2)

4Q

YTD

$0.66

$3.16

$0.81

$2.91

Note: PPA = Power Purchase Agreement

Key Drivers –

4Q10 vs. 4Q09

(1)

Higher energy prices under the PECO

PPA, offset at PECO: $0.10

Favorable RPM capacity pricing: $0.07

Higher nuclear volume: $0.04

Higher nuclear fuel costs: $(0.02)

Higher depreciation expense: $(0.03)

8

0%

10%

20%

30%

40%

50%

60%

70%

80%

Q1 2010

Q2 2010

Q3 2010

Q4 2010

Underlying

Options

Ratable

Power Fundamentals & Hedging Update

Using our perspective on the markets to time

sales, thereby adding value

•

PJMW energy prices increased in 4Q 2010, driven by

higher eastern coal prices

•

NiHub energy prices and Henry Hub natural gas prices

remained relatively stable in 4Q 2010

•

Slowed down pace of hedging in Q3 & Q4 to recognize

future upside from environmental regulations and

economic recovery

Normal practice is to hedge commodity risk

on a ratable basis over three years

•

Maintain flexibility from quarter to quarter

•

Use gas and power put options to capture potential

upside while providing downside price protection

Exelon’s ratable hedging program provides flexibility to time sales based

on fundamental view of the market

2012 Historical Energy & Gas Prices

31.00

33.00

35.00

37.00

39.00

41.00

43.00

45.00

47.00

49.00

51.00

1/4/10

2/3/10

3/5/10

4/4/10

5/4/10

6/3/10

7/3/10

8/2/10

9/1/10

10/1/10

10/31/10

11/30/10

12/30/10

4.80

5.00

5.20

5.40

5.60

5.80

6.00

6.20

6.40

6.60

6.80

PJMWHub

NiHub

Henry Hub Nat Gas

2012 Quarterly Hedge Level vs. Ratable Plan

Note: % values represent amount

above ratable plan

10%

8%

11%

5%

9

Key Drivers –

4Q10 vs. 4Q09

(1)

Appellate Court ruling: $(0.02)

Higher O&M expense: $(0.01)

ComEd Operating EPS Contribution

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

2010

2009

4Q

YTD

$0.16

$0.54

4Q10

Actual

Normal

% Change

Heating Degree-Days   2,292           2,278         0.6%

Cooling Degree-Days      15

7            114%

$0.13

$0.68

10

10

ComEd Load Trends

Chicago

U.S.

Unemployment rate

(1)

9.3%

9.4%

2010 annualized growth in

gross

domestic/metro

product

(2)

1.6%                   2.8%

Note: C&I = Commercial & Industrial

Weather-Normalized Load Year-over-Year 

Key Economic Indicators

Weather-Normalized Load

4Q10 

2010      2011E

Average Customer Growth

0.4%  

0.2%    

0.5%

Average Use-Per-Customer

(4.5)%

(1.4)%

0.0%

Total Residential

(4.1)%   

(1.2)%      0.5%

Small C&I

(1.5)%

(0.6)%     (0.3)%

Large C&I

1.9%  

2.6%      (0.2)%

All Customer Classes

(1.2)%   

0.2%       0.0%

(1)

Source:  U.S. Dept. of Labor (December 2010) and Illinois

Department of Security (December 2010)

(2)  Source: Global Insight December 2010

-6.0%

-3.0%

0.0%

3.0%

6.0%

1Q10

2Q10

3Q10

4Q10

1Q11

2Q11

3Q11

4Q11

-6.0%

-3.0%

0.0%

3.0%

6.0%

All Customer Classes

Large C&I

Residential

Gross Metro Product

11

PECO Operating EPS Contribution

Key Drivers –

4Q10 vs. 4Q09

(1)

Decreased CTC revenue resulting

in higher energy prices paid to

Generation under the PPA, offset

at Generation: $(0.10)

Weather: $0.01

CTC amortization $0.02

2010

2009

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

4Q

YTD

$0.12

$0.54

4Q10

$0.03

$0.54

Actual

Normal

% Change

Heating Degree-Days   1,686        1,634            3.2%

Cooling Degree-Days      19             21             (9.5)%

Note: CTC = Competitive Transition Charge

12

(1)

Source: U.S Dept. of Labor (PHL – November 2010 preliminary data, US – 

December 2010)

(2)

Source: Global Insight December 2010

PECO Load Trends

Philadelphia

U.S.

Unemployment rate

(1)

8.4%                  9.4%

2010 annualized growth in

gross

domestic/metro

product

(2)

2.8%                  2.8%

Note: C&I = Commercial & Industrial

Weather-Normalized Load Year-over-Year 

Key Economic Indicators

Weather-Normalized Load

4Q10    

2010        2011E

Average Customer Growth

0.5%  

0.3%    

0.4%

Average Use-Per-Customer

(1.2)%

0.3%

(0.3)%

Total Residential

(0.7)%   

0.5%        0.1%

Small C&I

(2.0)%

(1.9)%      (0.5)%

Large C&I

1.5%  

0.8%        0.1%

All Customer Classes

0.0%   

0.1%        0.0%

-5.0%

-2.5%

0.0%

2.5%

5.0%

1Q10

2Q10

3Q10

4Q10

1Q11E

2Q11E

3Q11E

4Q11E

-5.0%

-2.5%

0.0%

2.5%

5.0%

All Customer Classes

Large C&I

Residential

Gross Metro Product

$0.98

$0.68

$2.74

$2.91

$1.07

$0.71

2010A

2011E

PECO

ComEd

ExGen

Operating O&M Outlook

2010 to 2011 Drivers (per share)

Inflation $(0.08)

Full year of Exelon Wind $(0.05)

Two additional nuclear refueling

outages $(0.05)

ComEd uncollectibles

$(0.04)

Estimated

2011

O&M

represents

a

new

“base”

level

for

operating

O&M

$4.39B

$4.68B

2010 Operating O&M below 2008 levels for second consecutive year

One-time savings in 2010 included executive salary freezes and reduced

compensation benefits

Anticipate annual O&M growth rate of ~2% for 2011-2013

(1)

(1)

13

(1) Amounts may not add due to rounding. Refer to slide 44 for a reconciliation of GAAP O&M to Operating O&M.

14

Pension and OPEB Expense and

Contributions –

As of 12/31/10

(1) 

Pension expense amounts exclude settlement charges.

(2)

Note: Slide provided for illustrative purposes and not intended to represent a forecast of future outcomes. Assumes an ~25% capitalization of pension and OPEB costs.

$190

$240

Pre-tax

expense

$205

$1,655

$3,875

$2,220

$765

$8,860

$12,525

$3,665

Actual

contribution

$210

$2,140

$225

$185

$2,180

$210

5.83% in 2010

5.30% in 2011

5.52% in 2012

11.6% in 2010

7.08% in 2011

7.08% in 2012

OPEB

Assets

Obligations

Unfunded balance –

end of year

$110

$1,015

$240

$2,100

$1,305

$200

5.83% in 2010

5.26% in 2011

5.48% in 2012

11.9% in 2010

8.0% in 2011

7.5% in 2012

Pension

Assets

Obligations

Unfunded balance –

end of year

Expected

contribution

Pre-tax

expense

Expected

contribution

Pre-tax

expense

Discount Rate

(used for

expense)

Asset Returns

(actual for 2010 and

expected for

2011 and 2012)

($ in millions)

Assumptions

2011

2012

2010

The decrease in pension expense in 2011 is primarily due to the $2.1 billion pension

contribution, partially offset by the impacts of lower discount rates and a decrease in EROA

Management considers various factors when making pension funding decisions, including actuarially determined minimum contribution requirements under ERISA, contributions

required to avoid benefit restrictions and at-risk status as defined by the Pension Protection Act of 2006 (the Act), management of the pension obligation and regulatory implications.

The Act requires the attainment of certain funding levels to avoid benefit restrictions (such as an inability to pay lump sums or to accrue benefits prospectively), and at-risk status

(which triggers higher minimum contribution requirements and participant notification).

15

2011 Pension Contribution

$2.1 billion contribution to pension in 2011

•

Timing:

~$850

million

funded

by

the

accelerated cash benefits generated as a

result of bonus depreciation

•

Tax

efficient:

Income

tax

deduction

of

pension contribution creates $750 million

of cash benefit

•

Economic:

Reduces

estimated

future

pension expense, lowers future minimum

funding requirements and reduces volatility

Improves financial flexibility

•

Creates debt capacity for future growth

•

Improves ability to weather commodity

cycle in 2012 and 2013 and maintain the

dividend

Contributes to improved pension funded

status of 71% at 12/31/10, projected to be

89% at 12/31/11

Pension Contributions

615

2,100

765

110

175

160

195

780

790

170

485

2010

2011

2012

2013

2014

2015

With $2.1B

Original Plan*

Pre-Tax Pension Expense

(1)

240

300

265

200

240

2010

2011

2012

(1) Assumes an ~25% capitalization rate.

$ millions

$ millions

*

Original Plan reflects preliminary  2010 underlying assumptions (including

discount rate and asset returns)

16

2011 Projected Sources and Uses of Cash

(1)

Excludes counterparty collateral activity.

(2)

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

(3)

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

(4)

Includes $475 million in Nuclear Uprates and $225 million for Exelon Wind spend.

(5)

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

(6)

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

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

(7)

“Other”

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

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

($ millions)

Exelon

(8)

Beginning Cash Balance

(1)

$800

Cash Flow from Operations

(2)

425

775

3,150

4,325

CapEx (excluding Nuclear Fuel, Nuclear

Uprates, Exelon Wind, Utility Growth CapEx)

(700)

(325)

(850)

(1,875)

Nuclear Fuel

n/a

n/a

(1,025)

(1,025)

Dividend

(3)

(1,400)

Nuclear Uprates and Exelon Wind

(4)

n/a

n/a

(700)

(700)

Utility Growth CapEx

(5)

(325)

(125)

n/a

(450)

Net Financing (excluding Dividend):

Planned Debt Issuances

(6)

1,000

--

--

1,000

Planned Debt Retirements

(350)

(250)

--

(600)

Other

(7)

250

--

--

300

Ending Cash Balance

(1)

$375

17

2011 Events of Interest

Q1

Q2

Q3

Q4

RPM Auction results

(5/13)

Illinois Power Agency

RFP (April)

ALJ Proposed Order

–

DST Rate Case

(3/31)

Procurement RFP

(bids due 5/23;

results by 6/23)

DST Rate Case Final

Order  (by 5/31)

EPA Final HAP

Rule (November)

Retirement of Cromby

1 & Eddystone 1 units

(5/31)

Proposed HAP EPA

Regulation (by 3/16)

Procurement RFP

(bids due 9/19;

results by 10/19)

Retirement of

Cromby 2 unit

(12/31)

Proposed 316(b) EPA

Regulation (by 3/14)

EPA Final Transport

Rule (June)

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

18

Exelon Generation Hedging Disclosures

(as of December 31, 2010)

***********

19

19

Important Information

The

following

slides

are

intended

to

provide

additional

information

regarding

the

hedging

program

at

Exelon

Generation

and

to

serve

as

an

aid

for

the

purposes

of

modeling

Exelon

Generation’s

gross

margin

(operating

revenues

less

purchased

power

and

fuel

expense).

The

information

on

the

following

slides

is

not

intended

to

represent

earnings

guidance

or

a

forecast

of

future

events.

In

fact,

many

of

the

factors

that

ultimately

will

determine

Exelon

Generation’s

actual

gross

margin

are

based

upon

highly

variable

market

factors

outside

of

our

control.

The

information

on

the

following

slides

is

as

of

December

31,

2010.

We

update

this

information

on

a quarterly basis.

Certain

information

on

the

following

slides

is

based

upon

an

internal

simulation

model

that

incorporates

assumptions

regarding

future

market

conditions,

including

power

and

commodity

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

characteristics

of

our

generating

fleet.

Our

simulation

model

and

the

assumptions

therein

are

subject

to

change.

For

example,

actual

market

conditions

and

the

dispatch

profile

of

our

generation

fleet

in

future

periods

will

likely

differ

–

and

may

differ

significantly

–

from

the

assumptions

underlying

the

simulation

results

included

in

the

slides.

In

addition,

the

forward-

looking

information

included

in

the

following

slides

will

likely

change

over

time

due

to

continued

refinement

of

our

simulation

model

and

changes

in

our

views

on

future

market

conditions.

20

20

Portfolio Management Objective

Align Hedging Activities with Financial Commitments

Power Team utilizes several product types

and channels to market

•

Wholesale and retail sales

•

Block products

•

Load-following products

and load auctions

•

Put/call options

Exelon’s hedging program is designed to

protect the long-term value of our

generating fleet and maintain an

investment-grade balance sheet

•

Hedge enough commodity risk to meet future cash

requirements if prices drop

•

Consider:  financing policy (credit rating objectives,

capital structure, liquidity); spending (capital and

O&M); shareholder value return policy

Consider market, credit, operational risk

Approach to managing volatility

•

Increase hedging as delivery approaches

•

Have enough supply to meet peak load

•

Purchase fossil fuels as power is sold

•

Choose hedging products based on generation

portfolio –

sell what we own

•

Heat rate options

•

Fuel products

•

Capacity

•

Renewable credits

% Hedged

High End of Profit

Low End of Profit

Open Generation

with LT Contracts

Portfolio

Optimization

Portfolio

Management

Portfolio Management Over Time

21

21

Percentage of Expected

Generation Hedged

•

How many equivalent MW have been

hedged at forward market prices; all hedge

products used are converted to an

equivalent average MW volume

•

Takes ALL

hedges into account whether

they are power sales or financial products

Equivalent MWs Sold

Expected Generation

=

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

over the three years leading to the spot market

•

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

risks

•

By

using

the

appropriate

product

mix,

expected

generation

hedged

approaches

the

mid-90s percentile as the delivery period approaches

•

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

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

quarter to quarter

Exelon Generation Hedging Program

22

22

2011

2012

2013

Estimated Open Gross Margin ($ millions)

(1)(2)(3)

$5,200

$5,050

$5,700

Open gross margin assumes all expected generation is sold

at the Reference Prices listed below

Reference Prices

(1)

Henry Hub Natural Gas ($/MMBtu)

NI-Hub ATC Energy Price ($/MWh)

PJM-W ATC Energy Price ($/MWh)    

ERCOT North ATC Spark Spread ($/MWh)

(4)

$4.56

$30.69

$45.45

$1.12

$5.08

$32.38

$46.41

$0.82

$5.33

$35.09

$48.25

$1.84

Exelon Generation Open Gross Margin and

Reference Prices

(1)

Based on December 31, 2010 market conditions. 

(2)

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

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

assumes

there

is

no

hedging

in

place

other

than

fixed

assumptions

for

capacity

cleared

in

the

RPM

auctions

and

uranium

costs

for

nuclear

power

plants.

Open

gross

margin

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

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

(3)

As of December 31, 2010 disclosure, Exelon Wind included.   Assets in IL, MI and MN are in Midwest region and assets in ID, KS, MO, OR and TX are in South and West region.

(4)

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

23

23

2011

2012

2013

Expected Generation

(GWh)

(1)

165,900

165,800

163,300

Midwest

99,600

98,500

96,200

Mid-Atlantic

56,800

57,200

56,500

South & West

9,500

10,100

10,600

Percentage

of

Expected

Generation

Hedged

(2)

90-93%

67-70%

32-35%

Midwest

91-94

69-72

31-34

Mid-Atlantic

93-96

67-70

36-39

South & West

70-73

51-54

39-42

Effective Realized Energy Price

($/MWh)

(3)

Midwest

$43.00

$41.50

$43.50

Mid-Atlantic

$57.00

$50.50

$51.50

South & West

$2.50

$(1.00)

$(3.50)

Generation Profile

(1)

Expected

generation

represents

the

amount

of

energy

estimated

to

be

generated

or

purchased

through

owned

or

contracted

for

capacity.

Expected

generation

is

based

upon

a

simulated

dispatch

model

that

makes

assumptions

regarding

future

market

conditions,which

are

calibrated

to

market

quotes

for

power,

fuel,

load

following

products,

and

options.

Expected

generation

assumes

12

refueling

outages

in

2011

and

10

refueling

outages

in

2012

and

2013

at

Exelon-operated

nuclear

plants

and

Salem.

Expected

generation

assumes

capacity

factors

of

93.0%,

93.6%

and

93.1%

in

2011,

2012

and

2013

at

Exelon-operated

nuclear

plants.

These

estimates

of

expected

generation

in

2012

and

2013

do

not

represent guidance or a

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

(2)

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

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

(3)

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

revenues

and

costs

associated

with

our

hedges

and

by

considering

the

fossil

fuel

that

has

been

purchased

to

lock

in

margin.

It

excludes

uranium

costs

and

RPM

capacity

revenue,

but

includes

the

mark-to-market

value

of

capacity

contracted

at

prices

other

than

RPM

clearing

prices

including

our

load

obligations.

It

can

be

compared

with

the

reference

prices

used

to

calculate open gross margin in order to determine the mark-to-market value of Exelon Generation's energy hedges.

24

24

Gross Margin Sensitivities with Existing Hedges ($ millions)

(1)

Henry Hub Natural Gas

+ $1/MMBtu

-

$1/MMBtu

NI-Hub ATC Energy Price

+$5/MWH

-$5/MWH

PJM-W ATC Energy Price

+$5/MWH

-$5/MWH

Nuclear Capacity Factor

+1% / -1%

2011

$5

$(5)

$30

$(20)

$15

$(10)

+/-

$40

2012

$175

$(95)

$185

$(165)

$115

$(110)

+/-

$45

2013

$495

$(445)

$340

$(335)

$200

$(195)

+/-

$50

Exelon Generation Gross Margin Sensitivities

(with Existing Hedges)

(1)

Based on December 31, 2010 market conditions and hedged position. Gas price sensitivities are based on an assumed gas-power relationship derived from an

internal model that is updated periodically.

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

constant. Due to correlation of the various assumptions, the hedged gross margin impact calculated by aggregating individual sensitivities may not be equal to the

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

25

25

95% case

5% case

$5,400

$7,100

$6,800

$6,300

Exelon Generation Gross Margin Upside / Risk

(with Existing Hedges)

$3,000

$4,000

$5,000

$6,000

$7,000

$8,000

$9,000

2011

2012

(1)

Represents

an

approximate

range

of

expected

gross

margin,

taking

into

account

hedges

in

place,

between

the

5th

and

95th

percent

confidence

levels

assuming

all

unhedged

supply

is

sold

into

the

spot

market.

Approximate

gross

margin

ranges

are

based

upon

an

internal

simulation

model

and

are

subject

to

change

based

upon

market

inputs,

future

transactions

and

potential

modeling

changes.

These

ranges

of

approximate

gross

margin

in

2012

and

2013

do

not

represent

earnings

guidance

or

a

forecast

of

future

results

as

Exelon

has

not

completed

its

planning

or

optimization

processes

for

those

years.

The

price

distributions

that

generate

this

range

are

calibrated

to

market

quotes

for

power,

fuel,

load

following

products,

and

options

as

of

December

31,

2010.

$7,200

$5,000

2013

26

26

Midwest

Mid-Atlantic

South & West

Step 1

Start

with

fleetwide

open

gross

margin 

$5.20 billion

Step 2

Determine the mark-to-market value

of

energy hedges

99,600GWh * 92% *

($43.00/MWh-$30.69MWh)

= $1.13 billion

56,800GWh * 94% *

($57.00/MWh-$45.45MWh)

= $0.62 billion

9,500GWh * 71% *

($2.50/MWh-$1.12/MWh)

= $0.01 billion

Step 3

Estimate

hedged

gross

margin

by

adding open gross margin to mark-to-

market value of energy hedges

Open gross margin:                              $5.20 billion

MTM value of energy hedges:              $1.13billion + $0.62billion + $0.01 billion

Estimated hedged gross margin:          $6.96 billion

Illustrative Example

of Modeling Exelon Generation 2011 Gross Margin

(with Existing Hedges)

27

35

40

45

50

55

60

65

70

75

1/10

2/10

3/10

4/10

5/10

6/10

7/10

8/10

9/10

10/10

11/10

12/10

1/11

4.0

4.5

5.0

5.5

6.0

6.5

7.0

7.5

8.0

1/10

2/10

3/10

4/10

5/10

6/10

7/10

8/10

9/10

10/10

11/10

12/10

1/11

27

27

20

25

30

35

40

45

1/10

2/10

3/10

4/10

5/10

6/10

7/10

8/10

9/10

10/10

11/10

12/10

1/11

50

55

60

65

70

75

80

85

90

1/10

2/10

3/10

4/10

5/10

6/10

7/10

8/10

9/10

10/10

11/10

12/10

1/11

Market Price Snapshot

Forward NYMEX Natural Gas

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

PJM-West and Ni-Hub Wrap Forward Prices

2012

$5.54

2013  $5.79

Rolling

12

months,

as

of

January

20

,

2011.

Source:

OTC

quotes

and

electronic

trading

system.

Quotes

are

daily.

Forward NYMEX Coal

2012

$75.61

2013

$79.57

2012 Ni-Hub  $41.35

2013 Ni-Hub

$43.48

2013 PJM-West  $55.12

2012 PJM-West

$53.08

2012 Ni-Hub

$25.78

2013 Ni-Hub

$28.06

2013 PJM-West

$40.79

2012 PJM-West

$38.84

th

28

28

28

4.5

5.5

6.5

7.5

8.5

9.5

10.5

11.5

12.5

13.5

1/10

2/10

3/10

4/10

5/10

6/10

7/10

8/10

9/10

10/10

11/10

12/10

1/11

8.0

8.2

8.4

8.6

8.8

9.0

9.2

9.4

9.6

9.8

10.0

1/10

2/10

3/10

4/10

5/10

6/10

7/10

8/10

9/10

10/10

11/10

12/10

1/11

35

40

45

50

55

60

65

70

1/10

2/10

3/10

4/10

5/10

6/10

7/10

8/10

9/10

10/10

11/10

12/10

1/11

3.5

4.0

4.5

5.0

5.5

6.0

6.5

7.0

7.5

8.0

1/10

2/10

3/10

4/10

5/10

6/10

7/10

8/10

9/10

10/10

11/10

12/10

1/11

Market Price Snapshot

2013

9.29

2012

9.10

2012

$49.40

2013

$52.75

2012

$5.43

2013

$5.67

Houston Ship Channel Natural Gas

Forward Prices

ERCOT North On-Peak Forward Prices

ERCOT North On-Peak v. Houston Ship Channel

Implied Heat Rate

2012

$7.72

2013

$9.30

ERCOT North On Peak Spark Spread

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

Rolling

12

months,

as

of

January

20

,

2011.

Source:

OTC

quotes

and

electronic

trading

system.

Quotes

are

daily.

th

29

Appendix

*************************

30

Exelon Generation 2011 EPS Contribution

(1)

Estimated contribution to Exelon’s operating earnings guidance.

$ / Share

$0.35

$(0.03)

RNF

O&M

Other

Depreciation &

Amortization

$(0.08)

Key Items:

Inflation                               

Exelon Wind                       

Nuclear Outages                

2010A

2011E

(1)

$2.85 -

$3.05

$2.91

Key Items:

PECO CTC                              $0.62

Exelon Wind

$0.08

Capacity Market Prices          $(0.29)

Nuclear Fuel

$(0.09)

Market/portfolio conditions

and Exelon Energy                  $0.07

$(0.17)

$(0.03)

Interest

Expense

Note: Drivers add up to mid-point of 2011 EPS range.

$(0.05)

$(0.05)

$(0.05)

31

ComEd 2011 EPS Contribution

2010A

Depreciation &

Amortization

Interest

Expense

$0.55 -

$0.65

$0.03

$(0.08)

$(0.03)

2011E

(3)

$ / Share

$(0.02)

$0.02

Other

RNF

(1)

O&M

(1)

Key Items:

Weather

Uncollectibles

Appellate Court ruling

Distribution revenue

(2)

Key Items:

Uncollectibles

$(0.04)

Inflation                $(0.02)

Note: Drivers add up to mid-point of 2011 EPS range.

$0.68

1

$(0.04)

$(0.02)

$(0.01)

$0.08

(1)

Excludes estimated impact of Rider EDA (Energy Efficiency and Demand Response Adjustment) of +/-$0.05/share. 2010 net income includes a one-time benefit for

collections of under-recovered 2008 and 2009 bad debt costs, as provided by the uncollectible expense rider approved by the ICC in February 2010.  Going forward, the

rider provides for full recovery of all bad debt costs.

(2)

Distribution rate case currently pending, new rates will be effective in June 2011.  Earnings guidance assumes mid-point of ComEd’s requested revenue increase.

(3)

Estimated contribution to Exelon’s operating earnings guidance.

32

PECO 2011 EPS Contribution

$ / Share

RNF

(2)

$(0.03)

$0.54

(1)

CTC,net

2011E

(3)

Key Items:

Electric & Gas

Distribution Rate

$0.19

Weather                    $(0.05)

Key Items:

Inflation                   $(0.01)

Bad Debt               $(0.01)

$0.14

O&M

(2)

$0.50 -

$0.55

(1)

$(0.04)

2010A

(1)

Excludes preferred dividends.

(2)

Excludes items that are income statement neutral and estimated impact of energy efficiency and smart meter costs recoverable under a rider of $0.10/share.

(3)

Estimated contribution to Exelon’s operating earnings guidance.

Note: Drivers add up to mid-point of 2011 EPS range.

$(0.03)

Depreciation

$(0.05)

Income Taxes

Key Items:

Revenue net         $(0.06)

of amortization

Interest on PECO

transition bonds     $0.02

33

Key Assumptions

38.0

31.1

29.5

PECO

40.8

39.7

37.9

ComEd

37.1

37.5

38.3

Exelon Generation

38.1

36.7

37.2

Effective Tax Rate -

Operating (%)

136.59

144.40

106.13

RTO Capacity Price ($/MW-day)

2009 Actual

2010 Actual

2011 Est.

(3)

Nuclear Capacity Factor (%)

(1)

93.6

93.9

93.0

Total Generation Sales Excluding Trading (GWh)

173,065

171,789

168,700

Henry Hub Gas Price ($/mmBtu)

3.92

4.37

4.56

PJM West Hub ATC Price ($/MWh)

38.30

45.93

45.45

Tetco M3 Gas Price ($/mmBtu)

4.64

5.10

5.32

PJM West Hub Implied ATC Heat Rate (mmbtu/MWh)

8.25

9.01

8.54

NI Hub ATC Price ($/MWh)

28.85

33.09

30.69

Chicago City Gate Gas Price ($/mmBtu)

3.92

4.46

4.61

NI Hub Implied ATC Heat Rate (mmbtu/MWh)

7.36

7.42

6.66

MAAC Capacity Price ($/MW-day)

158.48

181.34

136.59

EMAAC Capacity Price ($/MW-day)

173.73

181.34

136.59

Electric Delivery Growth (%)

(2)

PECO

0.6

0.1

0.0

ComEd

(0.1)

0.2

0.0

(1)

Excludes Salem.

.

(2)

Weather-normalized retail load growth.

(3)

Reflects forward market prices as of December 31, 2010.

Note:

The

estimates

of

planned

generation

do

not

represent

guidance

or

a

forecast

of

future

results

as

Exelon

has

not

completed

its

planning

or

optimization

processes.

34

34

Total Portfolio Characteristics

110,594

142,400

42,003

5,295

13,897

26,300

0

50,000

100,000

150,000

200,000

2010

2011E

ComEd Swap

IL Auction

PECO Load

Actual Forward Hedges & Open Position

Expected Total Supply (GWh)

Expected Total Sales

(GWh)

92,493

91,300

47,517

48,100

27,090

26,500

4,689

2,800

0

50,000

100,000

150,000

200,000

2010

2011E

Forward / Spot Purchases

Fossil and Renewables

Mid-Atlantic Nuclear

Midwest Nuclear

171,789

171,789

168,700

168,700

Note:

The

estimates

of

planned

generation

do

not

represent

guidance

or

a

forecast

of

future

results

as

Exelon

has

not

completed

its

planning

or

optimization

processes.

35

Refueling Outage Schedule

Note:

Data

includes

Salem.

Net

nuclear

generation

data

based

on

ownership

interest.

The

estimates

of

planned

generation

do

not

represent

guidance

or

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

All Exelon owned units on a 24 month

cycle except for Braidwood U1/U2,

Byron U1/U2 and Salem U1/U2,

which are on 18 month cycles

Average Outage Duration (2009-10):

~29 days

(1)

Nuclear Refueling Cycle

12 planned refueling outages,

including 2 at Salem; Clinton outage

was moved from spring 2012 to fall

2011

6 refueling outages planned for the

Spring and 6 refueling outages

planned for the Fall

2011 Refueling Outage Impact

(1)

Excludes Salem.

125

127

129

131

133

135

137

139

141

143

145

2004

2005

2006

2007

2008

2009

2010

2011

2012

2013

2014

2015

7

8

9

10

11

12

13

Nuclear Output

Actual

Plan

# of Outages

36

ComEd 2010 Rate Case Update

ComEd Surrebuttal (1/3/11)

$326M increase requested

11.50% ROE / 47.28% equity ratio

Rate base $7,349M

2009 test year with pro forma plant

additions through 6/30/11

ICC Staff Position

$116M increase proposed in Dec 2010

rebuttal testimony

10.00% ROE / 47.11% equity ratio

Rate base $6,602M

Pro forma plant additions and

depreciation reserve through 12/31/10

(ICC Docket No. 10-0467)

$ millions

ComEd Original Request (6/30/10)

396

$       

Adjustments:

Bonus Depreciation

(14)

Pro forma plant adds/O&M update

(4)

Errata in Initial Filing

(12)

Reduction to Reg Asset Amortization

(8)

Other Items

(4)

ComEd Rebuttal (11/22/10)

354

$       

Adjustments:

New Bonus Depreciation

(22)

Pro forma plant adds/O&M update

(4)

Reduction to AMI/Other

(2)

ComEd Surrebuttal (1/3/2011)

326

$       

Reconciliation of ComEd Request to ComEd Surrebuttal

Note: See slide 17 for ComEd rate case key dates

* ComEd request does not reflect Appellate Court decision relating to

depreciation reserve, which we estimate would have a $85M reduction

to revenue requirement

*

37

ComEd Customer Usage Breakdown

Other

2%

Residential

31%

Small C&I

36%

380 Large

C&I

18%

Other Large

C&I

13%

3%

Leisure & Hospitality

9%

Trade, Transportation & Utilities

11%

Finance, Professional &

Business Services

12%

Health & Educational Services

13%

Government

52%

Manufacturing

Customer Usage by Revenue Class

Top 380 Customer Usage by Segment

Limited survey of select Large C&I customers has indicated an increase in

production via longer production runs and additional shifts due to improved

economic conditions for manufacturing-based customers, especially in the

steel and transportation sectors, along with data center expansions.

38

PECO Customer Usage Breakdown

Other

3%

Other Large

C&I

24%

150 Large

C&I

17%

Small C&I

22%

Residential

34%

7%

Other

13%

Transportation, Communication &

Utilities

18%

Health & Educational Services

18%

Manufacturing

22%

Petroleum

2%

Retail Trade

9%

Finance, Insurance & Real Estate

12%

Pharmaceuticals

Customer Usage by Revenue Class

Top 150 Customer Usage by Segment

PECO’s load is relatively diversified by customer class and industry

39

Sufficient Liquidity

--

--

--

--

Outstanding Facility Draws

(338)

(134)

(1)

(196)

Outstanding Letters of Credit

$7,365

$4,834

$574

$1,000

Aggregate Bank Commitments

(1)

7,027

4,700

573

804

Available Capacity Under Facilities

(2)

--

--

--

--

Outstanding Commercial Paper

$7,027

$4,700

$573

$804

Available Capacity Less Outstanding

Commercial Paper

Exelon

(3)

($ millions)

Available Capacity Under Bank Facilities as of January 14, 2011

(1)  Excludes previous commitment from Lehman Brothers Bank and commitments from Exelon’s Community and Minority Bank Credit Facility.

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

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

(3)  Includes other corporate entities.

Plan

to

extend/refinance

Exelon

Generation,

PECO

and

Exelon

Corp

credit

facilities in first half of 2011

40

Key Credit Metrics

0.0x

2.0x

4.0x

6.0x

8.0x

10.0x

12.0x

2009A

2010A

2011E

ExGen/Corp

ComEd

PECO

0%

5%

10%

15%

20%

25%

30%

35%

40%

45%

50%

2009A

2010A

2011E

ExGen/Corp

ComEd

PECO

FFO / Debt

(1)

(1)

Reflects FFO / Debt, Interest Coverage and Debt / Cap ratios as calculated by S&P.

(2)

Reflects S&P Target Range.  See slide 41 for reconciliations to GAAP.

(3)

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

(4)

Current senior unsecured ratings for Exelon and Exelon Generation and senior secured ratings for ComEd and PECO as of January 21, 2011.

30-35%

(3)

15-18%

15-18%

FFO / Debt

Target

Range

(2)

BBB+

A

BBB+

BBB+

Fitch

Credit

Ratings

(4)

BBB

A-

A-

BBB-

S&P

Credit

Ratings

(4)

A3

A1

Baa1

Baa1

Moody’s

Credit

Ratings

(4)

ComEd:

PECO:

Generation:

Exelon:

Interest Coverage

(1)

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%

2009A

2010A

2011E

ExGen/Corp

ComEd

PECO

Debt / Cap

(1)

41

Metric Calculations and Ratios

+

Other

Non-Cash

items

(1)

-

AFUDC/Cap. Interest

-

Decommissioning activity

+/-

Change in Working Capital

FFO Calculation:

= FFO

-

PECO Transition Bond Principal Paydown

Net Cash Flows provided by Operating Activities

Adjusted Interest:

Net Interest Expense

Adjusted Interest

FFO + Adjusted Interest

= Adjusted Interest

+ AFUDC & Capitalized interest

+ Interest on Present Value (PV) of Operating Leases

+ Interest on Imputed Debt Related to PV of Power Purchase Agreements (PPA)

-

PECO Transition Bond Interest Expense

Interest Coverage:

FFO

= Adjusted Debt

+ Off-balance sheet debt equivalents

(3)

-

PECO Transition Bond Principal Balance

+ STD

LTD

Adjusted Debt:

Adjusted Debt

(2)

FFO / Debt:

(1)

Reflects depreciation adjustment for PPAs and operating leases and pension/OPEB contribution normalization.

(2)

Uses current year-end adjusted debt balance.

(3)

Metrics

are

calculated

in

presentation

adjusted

for

debt

equivalents

for

PV

of

Operating

Leases,

PPAs,

unfunded

Pension

and

OPEB

obligations

(after-tax)

and

other

minor

debt equivalents.

+  Adjusted Debt

(3)

Debt / Cap:

= Adjusted Capitalization

Adjusted Debt

(2)

Adjusted Capitalization

Adjusted Capitalization:

Total shareholder’s equity

+   Preferred Securities of Subsidiaries

42

4Q GAAP EPS Reconciliation

(0.01)

-

-

-

(0.01)

2007 Illinois electric rate settlement

(0.01)

-

-

-

(0.01)

John Deere Renewables acquisition costs

0.01

-

-

0.01

-

Asset Retirement Obligation reduction

(0.03)

-

-

-

(0.03)

Retirements of fossil generation units / plant retirements

(0.17)

-

-

-

(0.17)

Mark-to-market adjustments from economic hedging activities

$0.79

$(0.01)

$0.03

$0.14

$0.63

4Q 2010 GAAP Earnings (Loss) Per Share

$0.96

$(0.01)

$0.03

$0.13

$0.81

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

0.04

-

-

-

0.04

Unrealized gains related to nuclear decommissioning trust funds

Exelon

Other

PECO

ComEd

ExGen

Three Months Ended December 31, 2010

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

0.04

-

-

-

0.04

Mark-to-market adjustments from economic hedging activities

(0.01)

-

-

(0.01)

-

City of Chicago settlement with ComEd

(0.02)

(0.01)

-

-

(0.01)

Costs associated with early debt retirements

(0.02)

-

-

-

(0.02)

2007 Illinois electric rate settlement

(0.05)

-

-

-

(0.05)

Retirement of fossil generating units

0.02

-

-

-

0.02

Unrealized gains related to nuclear decommissioning trust funds

$0.88

$(0.03)

$0.12

$0.15

$0.64

4Q 2009 GAAP Earnings (Loss) Per Share

$0.92

$(0.02)

$0.12

$0.16

$0.66

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

Exelon

Other

PECO

ComEd

ExGen

Three Months Ended December 31, 2009

43

YTD GAAP EPS Reconciliation

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

(0.01)

-

-

-

(0.01)

John Deere Renewables acquisition costs

0.01

-

-

0.01

-

Asset Retirement Obligation reduction

(0.10)

(0.01)

(0.03)

(0.16)

0.10

Non-cash remeasurement of income tax uncertainties

(0.10)

(0.02)

(0.02)

(0.02)

(0.04)

Non-cash charge resulting from health care legislation

(0.05)

-

-

-

(0.05)

Impact of certain emission allowances

0.08

-

-

-

0.08

Mark-to-market adjustments from economic hedging activities

(0.08)

-

-

-

(0.08)

Retirement of fossil generating units

$3.87

$(0.10)

$0.49

$0.51

$2.97

FY 2010 GAAP Earnings (Loss) Per Share

$4.06

$(0.07)

$0.54

$0.68

$2.91

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

(0.02)

-

-

-

(0.02)

2007 Illinois electric rate settlement

0.08

-

-

-

0.08

Unrealized gains related to nuclear decommissioning trust funds

Exelon

Other

PECO

ComEd

ExGen

Twelve Months Ended December 31, 2010

0.16

-

-

-

0.16

Mark-to-market adjustments from economic hedging activities

(0.05)

-

-

-

(0.05)

Retirement of fossil generating units

(0.01)

-

-

(0.01)

-

City of Chicago settlement with ComEd

(0.10)

-

-

(0.01)

(0.09)

2007 Illinois electric rate settlement

(0.11)

(0.04)

-

-

(0.07)

Costs associated with early debt retirements

(0.20)

-

-

-

(0.20)

Impairment of certain generating assets

(0.03)

-

(0.00)

(0.02)

(0.01)

2009 severance charges

0.05

-

-

-

0.05

Nuclear decommissioning obligation reduction

(0.03)

(0.03)

-

-

-

NRG acquisition costs

0.19

-

-

-

0.19

Unrealized gains related to nuclear decommissioning trust funds

0.10

(0.02)

-

0.06

0.06

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

deferred income taxes

$4.09

$(0.21)

$0.53

$0.56

$3.21

FY 2009 GAAP Earnings (Loss) Per Share

$4.12

$(0.12)

$0.54

$0.54

$3.16

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

Exelon

Other

PECO

ComEd

ExGen

Twelve Months Ended December 31, 2009

GAAP to Operating Adjustments

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

earnings effects of the following:

•

Mark-to-market adjustments from economic hedging activities

•

Unrealized gains and losses from nuclear decommissioning trust fund investments to the extent not offset by

contractual accounting as described in the notes to the consolidated financial statements

•

Significant impairments of assets, including goodwill

•

Any changes in decommissioning obligation estimates

•

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

•

Financial impacts associated with the planned retirement of fossil generating units

•

Other unusual items

•

Significant changes to GAAP

Operating earnings guidance assumes normal weather for full year

O&M reconciliation:

2010

2011

ExGen

ComEd

PECO

Other

Exelon

ExGen

ComEd

PECO

Other

Exelon

Operating and maintenance (GAAP)

2,812

1,069

733

(14)

4,600

3,010

1,220

820

(10)

5,040

JDR acquisition costs

(11)

-

-

-

(11)

-

-

-

-

-

Retirement of Fossil Generating Units

(3)

-

-

-

(3)

(30)

-

-

-

(30)

Non-cash charge resulting from health care legislation

(4)

(3)

(2)

8

(1)

-

-

-

-

-

Asset Retirement Obligation reduction

-

10

1

-

11

-

-

-

-

-

Adjusted Non-GAAP O&M

2,794

1,076

732

(6)

4,596

2,980

1,220

820

(10)

5,010

Decommissioning accretion

(57)

-

-

-

(57)

(70)

-

-

-

(70)

Regulatory required programs

-

(94)

(53)

-

(147)

-

(150)

(110)

-

(260)

Operating O&M (as shown on slide 13)

2,737

982

679

(6)

4,392

2,910

1,070

710

(10)

4,680

($ millions)

44