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 22, 2010

Date of Report (Date of earliest event reported)

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

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

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

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

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

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

Section 2 – Financial Information

Item 2.02. Results of Operations and Financial Condition.

Section 7 – Regulation FD

Item 7.01. Regulation FD Disclosure.

On January 22, 2010, Exelon Corporation (Exelon) announced via press release its results for the fourth quarter ended December 31, 2009. A copy of the press release and related attachments is attached hereto as Exhibit 99.1. Also attached as Exhibit 99.2 to this Current Report on Form 8-K are the presentation slides to be used at the fourth quarter 2009 earnings conference call. This Form 8-K and the attached exhibits are provided under Items 2.02, 7.01 and 9.01 of Form 8-K and are furnished to, but not filed with, the Securities and Exchange Commission.

Exelon has scheduled the conference call for 11:00 AM ET (10:00 AM CT) on January 22, 2010. 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 49405882. Media representatives are invited to participate on a listen-only basis. The call will be web-cast and archived on Exelon’s Web site: www.exeloncorp.com. (Please select the Investor Relations page.)

Telephone replays will be available until February 5. 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 49405882.

Section 9 – Financial Statements and Exhibits

Item 9.01. Financial Statements and Exhibits.

(d) Exhibits.

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

* * * * *

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

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

SIGNATURES

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

EXELON CORPORATION

EXELON GENERATION COMPANY, LLC

/s/ Matthew F. Hilzinger

Matthew F. Hilzinger

Senior Vice President and Chief Financial Officer

Exelon Corporation

COMMONWEALTH EDISON COMPANY

/s/ Joseph R. Trpik, Jr.

Joseph R. Trpik, Jr.

Senior Vice President, Chief Financial Officer and Treasurer

Commonwealth Edison Company

PECO ENERGY COMPANY

/s/ Phillip S. Barnett

Phillip S. Barnett

Senior Vice President and Chief Financial Officer

PECO Energy Company

January 22, 2010

EXHIBIT INDEX

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

EX-99.1

EXHIBIT 99.1

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

Exelon Announces Fourth Quarter and Full Year 2009 Results;

Reaffirms 2010 Earnings Guidance

CHICAGO (January 22, 2010) – Exelon Corporation (Exelon) announced fourth quarter and full year 2009 consolidated earnings as follows:

Exelon Consolidated Earnings (unaudited)

	Full Year				Fourth Quarter
	2009		2008		2009		2008
GAAP Results:
Net Income ($ millions)	$	2,707	$	2,737	$	581	$	707
Diluted Earnings per Share	$	4.09	$	4.13	$	0.88	$	1.07
Adjusted (non-GAAP) Operating Results:
Net income ($ millions)	$	2,723	$	2,781	$	610	$	709
Diluted Earnings per Share	$	4.12	$	4.20	$	0.92	$	1.07

“Our full year 2009 operating earnings results were well within our original guidance range of $4.00 to $4.30 per share and topped the narrowed $4.00 to $4.10 per share range that we announced in late October,” said John W. Rowe, Exelon’s chairman and CEO. “Despite the impact of adverse economic, market and weather conditions, we achieved our financial and operating commitments, and for 2010, we are reaffirming our operating earnings guidance range of $3.60 to $4.00 per share. At the same time, we continue to improve our industry-leading environmental position and evaluate and pursue appropriate growth opportunities for the long term.”

Fourth Quarter Operating Results

The decrease in fourth quarter 2009 adjusted (non-GAAP) operating earnings to $0.92 per share from $1.07 per share in fourth quarter 2008 was primarily due to:

• Lower energy gross margins at Exelon Generation Company, LLC (Generation) largely reflecting lower nuclear volume due to a higher number of scheduled refueling outage days and unfavorable portfolio and market conditions;

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

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

Lower fourth quarter 2009 earnings were partially offset by:

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

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

	(in millions)			(per diluted share)
Costs associated with the 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 retirements	$	(15	)	$	(0.02	)
Unrealized gains related to nuclear decommissioning trust (NDT) fund investments	$	14		$	0.02
Charge associated with ComEd’s 2007 settlement agreement with the City of Chicago	$	(5	)	$	(0.01	)

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

	(in millions)			(per diluted share)
Mark-to-market gains primarily from Generation’s economic hedging activities	$	93		$	0.15
Unrealized losses related to NDT fund investments	$	(68	)	$	(0.10	)
Costs associated with the 2007 Illinois electric rate settlement agreement	$	(26	)	$	(0.04	)
Gain for the resolution of tax matters related to a previous investment in Sithe Energies, Inc. (Sithe) at Generation	$	21		$	0.03
Charge associated with ComEd’s 2007 settlement agreement with the City of Chicago	$	(11	)	$	(0.02	)
External costs related to Exelon’s proposed acquisition of NRG Energy, Inc.	$	(11	)	$	(0.02	)

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2010 Earnings Outlook

Exelon reaffirms its guidance range for 2010 adjusted (non-GAAP) operating earnings of $3.60 to $4.00 per share. Operating earnings guidance is based on the assumption of normal weather.

The outlook for 2010 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

• Significant impairments of assets, including goodwill

• Changes in decommissioning obligation estimates

• Costs associated with the 2007 Illinois electric rate settlement agreement

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

• Costs associated with the retirement of fossil generating units

• Other unusual items

• Significant future changes to GAAP

Fourth Quarter and Recent Highlights

• Retirement of the Cromby Station and Eddystone Units 1 and 2: On December 2, 2009, Exelon Power announced that it had notified PJM Interconnection, LLC (PJM) of its intention to permanently retire Units 1 and 2 at Cromby Generating Station, totaling 345 megawatts (MW), and Units 1 and 2 at Eddystone Generating Station, totaling 588 MW, effective May 31, 2011. Following these retirements, Eddystone Station will remain in service, operating six gas and peaking units capable of generating 820 MW. Cromby Station will close when its units permanently retire. In the notification to PJM, Exelon Power stated that the four units, all in suburban Philadelphia, are no longer economic to operate and are not required to meet demand for electricity in the region. Exelon continues to work with PJM to ensure system reliability will be maintained when the four units are retired.

• Nuclear Operations: Generation’s nuclear fleet, including its owned output from the Salem Generating Station, produced 33,609 gigawatt-hours (GWh) in the fourth quarter of 2009, compared with 34,887 GWh in the fourth quarter of 2008. The Exelon-operated nuclear plants achieved an 89.8 percent capacity factor for the fourth quarter of 2009 compared with 93.7 percent for the fourth quarter of 2008. The Exelon-operated nuclear plants completed four and began a fifth scheduled refueling outage in the fourth quarter of 2009, compared with completing four scheduled refueling outages in the fourth quarter of 2008. Three Mile Island (TMI) Unit 1 has been shut down since late October 2009 for an extended refueling outage which includes the replacement of steam generators. The steam generator replacement increased the number of refueling outage days in the fourth quarter of 2009, which totaled 136 days versus 80 days in the fourth quarter of 2008. The number of non-refueling outage days at the Exelon-operated plants totaled 23 days in the fourth quarter of 2009 compared with 22 days in the fourth quarter of 2008.

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For the full year 2009, the Exelon-operated nuclear plants achieved an average capacity factor of 93.6 percent, as compared with 93.9 percent for 2008. The average annual capacity factor for the Exelon-operated plants during the five years ended 2009 was 93.9 percent.

• Fossil and Hydro Operations: Generation’s fossil fleet commercial availability was 90.2 percent in the fourth quarter of 2009, down slightly from 91.5 percent in the fourth quarter of 2008, driven by an outage at Handley Unit 5 from late July to early December. The equivalent availability factor for the hydroelectric facilities was 99.6 percent in the fourth quarter of 2009, compared with 98.9 percent in the fourth quarter of 2008.

For the full year 2009, Generation’s fossil fleet availability was 93.7 percent, compared with 89.1 percent for 2008. The equivalent availability factor for the hydroelectric facilities was 97.5 percent for the full year 2009, compared with 95.8 percent for 2008.

• Hedging Update: Exelon’s hedging program involves the hedging of commodity risk for Exelon’s expected generation, typically on a ratable basis over a three-year period. Expected generation represents the amount of energy estimated to be generated or purchased through owned or contracted-for capacity. The proportion of expected generation hedged as of December 31, 2009 is 91 to 94 percent for 2010, 69 to 72 percent for 2011 and 37 to 40 percent for 2012. The primary objective of Exelon’s hedging program is to manage market risks and protect the value of its generation and its investment grade balance sheet while preserving its ability to participate in improving long-term market fundamentals.

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

OPERATING COMPANY RESULTS

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

Fourth quarter 2009 net income was $425 million compared with $553 million in the fourth quarter of 2008. 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. Fourth quarter 2008 net income included (all after-tax) mark-to-market gains of $93 million from economic hedging activities before the elimination of intercompany transactions, costs of $23 million associated with the 2007 Illinois electric rate settlement, income of $21 million associated with the resolution of tax matters related to a previous investment in Sithe and unrealized losses of $68 million related to NDT fund investments. Excluding the impact of these items, Generation’s net income in the fourth quarter of 2009 decreased $89 million compared with the same quarter last year primarily due to:

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

• Higher operating and maintenance costs primarily related to increased pension and OPEB expense, partially offset by savings achieved through the cost management initiative.

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Generation’s average realized margin on all electric sales, including sales to affiliates and excluding trading activity, was $38.36 per MWh in the fourth quarter of 2009 compared with $38.28 per MWh in the fourth quarter of 2008.

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

ComEd recorded net income of $98 million in the fourth quarter of 2009, compared with net income of $91 million in the fourth quarter of 2008. 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. Fourth quarter 2008 net income included after-tax costs of $11 million for the City of Chicago settlement agreement and after-tax costs of $3 million associated with the 2007 Illinois electric rate settlement. Excluding the impact of these items, ComEd’s net income in the fourth quarter of 2009 was approximately level with the same quarter last year and reflected:

• Lower operating and maintenance expense, primarily due to savings achieved through the cost management initiative, partially offset by increased pension and OPEB expense;

• Impact of income tax benefit recorded in 2008 associated with the tax method of capitalizing overhead costs; and

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

In the fourth quarter of 2009, heating degree-days in the ComEd service territory were down 7.8 percent relative to the same period in 2008 and were 0.6 percent below normal. ComEd’s total retail kilowatt-hour (kWh) deliveries decreased by 3.8 percent quarter over quarter, with declines in deliveries across all major customer classes, primarily driven by the impact of current economic and unfavorable weather conditions. In addition, the number of residential customers being served in the ComEd region decreased 0.5 percent from the fourth quarter of 2008.

Weather-normalized retail kWh deliveries decreased by 1.6 percent from the fourth quarter of 2008. For ComEd, weather had an unfavorable after-tax impact of $8 million on fourth quarter 2009 earnings relative to 2008 and an unfavorable after-tax impact of $3 million relative to normal weather that was incorporated in earnings guidance.

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

PECO’s net income in the fourth quarter of 2009 was $78 million, down from $80 million in the fourth quarter of 2008. This decrease was primarily due to:

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

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

The decrease in net income was partially offset by:

• Higher gas distribution revenue, reflecting new rates effective January 1, 2009, resulting from the 2008 gas distribution rate case; and

• Lower uncollectible accounts expense.

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In the fourth quarter of 2009, heating degree-days in the PECO service territory were down 5.5 percent from 2008 and were 4.1 percent below normal. Total retail kWh deliveries were down 2.3 percent from last year, reflecting a decline in deliveries across all customer classes, primarily driven by the impact of current economic and unfavorable weather conditions. The number of residential electric customers being served in the PECO region decreased 0.4 percent from the fourth quarter of 2008. On the retail gas side, deliveries in the fourth quarter of 2009 were down 7.7 percent from the fourth quarter of 2008.

Weather-normalized retail kWh deliveries decreased by 1.3 percent from the fourth quarter of 2008, primarily reflecting decreased small and large commercial and industrial deliveries. For PECO, weather had an unfavorable after-tax impact of $7 million on fourth quarter 2009 earnings relative to 2008 and an unfavorable after-tax impact of $6 million relative to normal weather that was incorporated in earnings guidance.

Adjusted (non-GAAP) Operating Earnings

Adjusted (non-GAAP) operating earnings, which generally exclude significant one-time charges or credits that are not normally associated with ongoing operations, mark-to-market adjustments from economic hedging activities and unrealized gains and losses from NDT fund investments, are provided as a supplement to results reported in accordance with GAAP. Management uses such adjusted (non-GAAP) operating earnings measures internally to evaluate the company’s performance and manage its operations. Reconciliation of GAAP to adjusted (non-GAAP) operating earnings for historical periods is attached. Additional earnings release attachments, which include the reconciliation on pages 7 and 8, are posted on Exelon’s Web site: www.exeloncorp.com and have been filed with the Securities and Exchange Commission on Form 8-K on January 22, 2010.

Conference call information: Exelon has scheduled a conference call for 11:00 AM ET (10:00 AM CT) on January 22, 2010. 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 49405882. Media representatives are invited to participate on a listen-only basis. The call will be web-cast and archived on Exelon’s Web site: www.exeloncorp.com. (Please select the Investor Relations page.)

Telephone replays will be available until February 5. 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 49405882.

Forward Looking Statements

This press release includes forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995, that are subject to risks and uncertainties. The factors that could cause actual results to differ materially from these forward-looking statements include those discussed herein as well as those discussed in (1) Exelon’s 2008 Annual Report on Form 10-K in (a) ITEM 1A. Risk Factors, (b) ITEM 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations and (c) ITEM 8. Financial Statements and Supplementary Data: Note 18; (2) Exelon’s Third Quarter 2009 Quarterly Report on Form 10-Q in (a) Part II, Other Information, ITEM 1A. Risk Factors and (b) Part I, Financial Information, ITEM 1. Financial Statements: Note 14 and (3) other factors discussed in filings with the Securities and Exchange Commission (SEC) by Exelon Corporation, Commonwealth Edison Company, PECO Energy Company and Exelon Generation Company,

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LLC (Companies). Readers are cautioned not to place undue reliance on these forward-looking statements, which apply only as of the date of this press release. None of the Companies undertakes any obligation to publicly release any revision to its forward-looking statements to reflect events or circumstances after the date of this press release.

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Exelon Corporation is one of the nation’s largest electric utilities with approximately 5.4 million customers and $17 billion in annual revenues. The company has one of the industry’s largest portfolios of electricity generation capacity, with a nationwide reach and strong positions in the Midwest and Mid-Atlantic. Exelon distributes electricity to approximately 5.4 million customers in Illinois and Pennsylvania and natural gas to approximately 485,000 customers in southeastern Pennsylvania. Exelon is headquartered in Chicago and trades on the NYSE under the ticker EXC.

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EXELON CORPORATION

Earnings Release Attachments

Table of Contents

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

EXELON CORPORATION

Consolidating Statements of Operations

(unaudited)

(in millions)

	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, net		(36	)		(78	)		(42	)		(20	)		(176	)
Equity in losses of unconsolidated affiliates and 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
	Three Months Ended December 31, 2008
	Generation			ComEd			PECO			Other			Exelon Consolidated
Operating revenues	$	2,443		$	1,542		$	1,372		$	(864	)	$	4,493
Operating expenses
Purchased power		163			853			553			(865	)		704
Fuel		494			—			210			—			704
Operating and maintenance		694			268			174			19			1,155
Operating and maintenance for regulatory required programs (a)		—			11			—			—			11
Depreciation and amortization		72			121			200			12			405
Taxes other than income		44			72			61			4			181
Total operating expenses		1,467			1,325			1,198			(830	)		3,160
Operating income (loss)		976			217			174			(34	)		1,333
Other income and deductions
Interest expense, net		(28	)		(69	)		(55	)		(42	)		(194	)
Equity in losses of unconsolidated affiliates and investments		—			(2	)		(5	)		—			(7	)
Other, net		(177	)		6			5			15			(151	)
Total other income and deductions		(205	)		(65	)		(55	)		(27	)		(352	)
Income (loss) before income taxes		771			152			119			(61	)		981
Income taxes		239			61			39			(45	)		294
Income (loss) from continuing operations		532			91			80			(16	)		687
Income (loss) from discontinued operations		21			—			—			(1	)		20
Net income (loss)	$	553		$	91		$	80		$	(17	)	$	707

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

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EXELON CORPORATION

Consolidating Statements of Operations

(unaudited)

(in millions)

	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, net		(113	)		(319	)		(187	)		(112	)		(731	)
Equity in losses of unconsolidated affiliates and investments		(3	)		—			(24	)		—			(27	)
Other, net		376			79			13			(42	)		426
Total other income and deductions		260			(240	)		(198	)		(154	)		(332	)
Income (loss) before income taxes		3,555			603			499			(239	)		4,418
Income taxes		1,433			229			146			(96	)		1,712
Income (loss) from continuing operations		2,122			374			353			(143	)		2,706
Income from discontinued operations		—			—			—			1			1
Net income (loss)	$	2,122		$	374		$	353		$	(142	)	$	2,707
	Twelve Months Ended December 31, 2008
	Generation			ComEd			PECO			Other			Exelon Consolidated
Operating revenues	$	10,754		$	6,136		$	5,567		$	(3,598	)	$	18,859
Operating expenses
Purchased power		1,867			3,582			2,411			(3,590	)		4,270
Fuel		1,705			—			607			—			2,312
Operating and maintenance		2,717			1,097			731			(7	)		4,538
Operating and maintenance for regulatory required programs (a)		—			28			—			—			28
Depreciation and amortization		274			464			854			42			1,634
Taxes other than income		197			298			265			18			778
Total operating expenses		6,760			5,469			4,868			(3,537	)		13,560
Operating income (loss)		3,994			667			699			(61	)		5,299
Other income and deductions
Interest expense, net		(136	)		(348	)		(226	)		(122	)		(832	)
Equity in losses of unconsolidated affiliates and investments		(1	)		(8	)		(16	)		(1	)		(26	)
Other, net		(469	)		18			18			26			(407	)
Total other income and deductions		(606	)		(338	)		(224	)		(97	)		(1,265	)
Income (loss) from continuing operations before income taxes		3,388			329			475			(158	)		4,034
Income taxes		1,130			128			150			(91	)		1,317
Income (loss) from continuing operations		2,258			201			325			(67	)		2,717
Income from discontinued operations		20			—			—			—			20
Net income (loss)	$	2,278		$	201		$	325		$	(67	)	$	2,737

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

2

EXELON CORPORATION

Business Segment Comparative Statements of Operations

(unaudited)

(in millions)

	Generation
	Three Months Ended December 31,									Twelve Months Ended December 31,
	2009			2008			Variance			2009			2008			Variance
Operating revenues	$	2,278		$	2,443		$	(165	)	$	9,703		$	10,754		$	(1,051	)
Operating expenses
Purchased power		375			163			212			1,338			1,867			(529	)
Fuel		300			494			(194	)		1,594			1,705			(111	)
Operating and maintenance		727			694			33			2,938			2,717			221
Depreciation and amortization		110			72			38			333			274			59
Taxes other than income		55			44			11			205			197			8
Total operating expenses		1,567			1,467			100			6,408			6,760			(352	)
Operating income		711			976			(265	)		3,295			3,994			(699	)
Other income and deductions
Interest expense, net		(36	)		(28	)		(8	)		(113	)		(136	)		23
Equity in losses of investments		—			—			—			(3	)		(1	)		(2	)
Other, net		50			(177	)		227			376			(469	)		845
Total other income and deductions		14			(205	)		219			260			(606	)		866
Income from continuing operations before income taxes		725			771			(46	)		3,555			3,388			167
Income taxes		300			239			61			1,433			1,130			303
Income from continuing operations		425			532			(107	)		2,122			2,258			(136	)
Income from discontinued operations		—			21			(21	)		—			20			(20	)
Net income	$	425		$	553		$	(128	)	$	2,122		$	2,278		$	(156	)
	ComEd
	Three Months Ended December 31,									Twelve Months Ended December 31,
	2009			2008			Variance			2009			2008			Variance
Operating revenues	$	1,357		$	1,542		$	(185	)	$	5,774		$	6,136		$	(362	)
Operating expenses
Purchased power		692			853			(161	)		3,065			3,582			(517	)
Operating and maintenance		232			268			(36	)		1,028			1,097			(69	)
Operating and maintenance for regulatory required programs (a)		19			11			8			63			28			35
Depreciation and amortization		123			121			2			494			464			30
Taxes other than income		67			72			(5	)		281			298			(17	)
Total operating expenses		1,133			1,325			(192	)		4,931			5,469			(538	)
Operating income		224			217			7			843			667			176
Other income and deductions
Interest expense, net		(78	)		(69	)		(9	)		(319	)		(348	)		29
Equity in losses of unconsolidated affiliates		—			(2	)		2			—			(8	)		8
Other, net		11			6			5			79			18			61
Total other income and deductions		(67	)		(65	)		(2	)		(240	)		(338	)		98
Income before income taxes		157			152			5			603			329			274
Income taxes		59			61			(2	)		229			128			101
Net income	$	98		$	91		$	7		$	374		$	201		$	173

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

3

EXELON CORPORATION

Business Segment Comparative Statements of Operations

(unaudited)

(in millions)

	PECO
	Three Months Ended December 31,									Twelve Months Ended December 31,
	2009			2008			Variance			2009			2008			Variance
Operating revenues	$	1,266		$	1,372		$	(106	)	$	5,311		$	5,567		$	(256	)
Operating expenses
Purchased power		532			553			(21	)		2,274			2,411			(137	)
Fuel		126			210			(84	)		472			607			(135	)
Operating and maintenance		159			174			(15	)		640			731			(91	)
Depreciation and amortization		225			200			25			952			854			98
Taxes other than income		64			61			3			276			265			11
Total operating expenses		1,106			1,198			(92	)		4,614			4,868			(254	)
Operating income		160			174			(14	)		697			699			(2	)
Other income and deductions
Interest expense, net		(42	)		(55	)		13			(187	)		(226	)		39
Equity in losses of unconsolidated affiliates		(5	)		(5	)		—			(24	)		(16	)		(8	)
Other, net		5			5			—			13			18			(5	)
Total other income and deductions		(42	)		(55	)		13			(198	)		(224	)		26
Income before income taxes		118			119			(1	)		499			475			24
Income taxes		40			39			1			146			150			(4	)
Net income	$	78		$	80		$	(2	)	$	353		$	325		$	28
	Other (a)
	Three Months Ended December 31,									Twelve Months Ended December 31,
	2009			2008			Variance			2009			2008			Variance
Operating revenues	$	(785	)	$	(864	)	$	79		$	(3,470	)	$	(3,598	)	$	128
Operating expenses
Purchased power		(784	)		(865	)		81			(3,462	)		(3,590	)		128
Fuel		(1	)		—			(1	)		—			—			—
Operating and maintenance		2			19			(17	)		6			(7	)		13
Depreciation and amortization		16			12			4			55			42			13
Taxes other than income		1			4			(3	)		16			18			(2	)
Total operating expenses		(766	)		(830	)		64			(3,385	)		(3,537	)		152
Operating loss		(19	)		(34	)		15			(85	)		(61	)		(24	)
Other income and deductions
Interest expense, net		(20	)		(42	)		22			(112	)		(122	)		10
Equity in losses of unconsolidated affiliates and investments		(1	)		—			(1	)		—			(1	)		1
Other, net		(6	)		15			(21	)		(42	)		26			(68	)
Total other income and deductions		(27	)		(27	)		—			(154	)		(97	)		(57	)
Loss from continuing operations before income taxes		(46	)		(61	)		15			(239	)		(158	)		(81	)
Income taxes		(26	)		(45	)		19			(96	)		(91	)		(5	)
Loss from continuing operations		(20	)		(16	)		(4	)		(143	)		(67	)		(76	)
Income (loss) from discontinued operations		—			(1	)		1			1			—			1
Net loss	$	(20	)	$	(17	)	$	(3	)	$	(142	)	$	(67	)	$	(75	)

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

4

EXELON CORPORATION

Consolidated Balance Sheets

(unaudited)

(in millions)

	December 31, 2009			December 31, 2008
Current assets
Cash and cash equivalents	$	2,010		$	1,271
Restricted cash and investments		40			75
Accounts receivable, net
Customer		1,563			1,928
Other		486			324
Mark-to-market derivative assets		376			480
Inventories, net
Fossil fuel		198			315
Materials and supplies		559			528
Other		209			209
Total current assets		5,441			5,130
Property, plant and equipment, net		27,341			25,813
Deferred debits and other assets
Regulatory assets		4,872			5,940
Nuclear decommissioning trust (NDT) funds		6,669			5,500
Investments		724			715
Goodwill		2,625			2,625
Mark-to-market derivative assets		649			679
Other		859			1,144
Total deferred debits and other assets		16,398			16,603
Total assets	$	49,180		$	47,546
Liabilities and equity
Current liabilities
Short-term borrowings	$	155		$	211
Long-term debt due within one year		639			29
Long-term debt to PECO Energy Transition Trust due within one year		415			319
Accounts payable		1,345			1,416
Mark-to-market derivative liabilities		198			212
Accrued expenses		923			1,151
Deferred income taxes		152			77
Other		411			396
Total current liabilities		4,238			3,811
Long-term debt		10,995			11,397
Long-term debt to PECO Energy Transition Trust		—			805
Long-term debt to other financing trusts		390			390
Deferred credits and other liabilities
Deferred income taxes and unamortized investment tax credits		5,750			4,939
Asset retirement obligations		3,434			3,734
Pension obligations		3,625			4,111
Non-pension postretirement benefits obligations		2,180			2,255
Spent nuclear fuel obligation		1,017			1,015
Regulatory liabilities		3,492			2,520
Mark-to-market derivative liabilities		23			23
Other		1,309			1,412
Total deferred credits and other liabilities		20,830			20,009
Total liabilities		36,453			36,412
Preferred securities of subsidiary		87			87
Shareholders’ equity
Common stock		8,923			8,816
Treasury stock, at cost		(2,328	)		(2,338	)
Retained earnings		8,134			6,820
Accumulated other comprehensive loss, net		(2,089	)		(2,251	)
Total shareholders’ equity		12,640			11,047
Total liabilities and shareholders’ equity	$	49,180		$	47,546

5

EXELON CORPORATION

Consolidated Statements of Cash Flows

(unaudited)

(in millions)

	For the Years Ended December 31,
	2009			2008
Cash flows from operating activities
Net income	$	2,707		$	2,737
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation, amortization and accretion, including nuclear fuel amortization		2,601			2,308
Impairment of long-lived assets		223			—
Deferred income taxes and amortization of investment tax credits		756			374
Net fair value changes related to derivatives		(95	)		(515	)
Net realized and unrealized (gains) losses on NDT fund investments		(207	)		363
Other non-cash operating activities		652			870
Changes in assets and liabilities:
Accounts receivable		234			67
Inventories		51			(109	)
Accounts payable, accrued expenses and other current liabilities		(254	)		(44	)
Option premiums (paid) received, net		(40	)		(124	)
Counterparty collateral received, net		196			1,027
Income taxes		(29	)		(38	)
Pension and non-pension postretirement benefit contributions		(588	)		(230	)
Other assets and liabilities		(113	)		(135	)
Net cash flows provided by operating activities		6,094			6,551
Cash flows from investing activities
Capital expenditures		(3,273	)		(3,117	)
Proceeds from NDT fund sales		22,905			17,202
Investment in NDT funds		(23,144	)		(17,487	)
Proceeds from sales of investments		41			—
Purchases of investments		(28	)		—
Change in restricted cash		35			29
Other investing activities		6			(5	)
Net cash flows used in investing activities		(3,458	)		(3,378	)
Cash flows from financing activities
Changes in short-term debt		(56	)		(405	)
Issuance of long-term debt		1,987			2,265
Retirement of long-term debt		(1,773	)		(1,398	)
Retirement of long-term debt to financing affiliates		(709	)		(1,038	)
Dividends paid on common stock		(1,385	)		(1,335	)
Proceeds from employee stock plans		42			130
Purchase of treasury stock		—			(436	)
Purchase of forward contract in relation to certain treasury stock		—			(64	)
Other financing activities		(3	)		68
Net cash flows used in financing activities		(1,897	)		(2,213	)
Increase in cash and cash equivalents		739			960
Cash and cash equivalents at beginning of period		1,271			311
Cash and cash equivalents at end of period	$	2,010		$	1,271

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, 2009									Three Months Ended December 31, 2008
	GAAP (a)			Adjustments			Adjusted Non-GAAP			GAAP (a)			Adjustments			Adjusted Non-GAAP
Operating revenues	$	4,116		$	32	(c),(d)	$	4,148		$	4,493		$	56	(c),(d)	$	4,549
Operating expenses
Purchased power		815			(36	)(e)		779			704			204	(e)		908
Fuel		425			78	(e)		503			704			(50	)(e)		654
Operating and maintenance		1,120			(24	)(f)		1,096			1,155			(23	)(c),(i)		1,132
Operating and maintenance for regulatory required programs (b)		19			—			19			11			—			11
Depreciation and amortization		474			(32	)(f)		442			405			—			405
Taxes other than income		187			—			187			181			—			181
Total operating expenses		3,040			(14	)		3,026			3,160			131			3,291
Operating income		1,076			46			1,122			1,333			(75	)		1,258
Other income and deductions
Interest expense, net		(176	)		—			(176	)		(194	)		—			(194	)
Equity in losses of unconsolidated affiliates and investments		(6	)		—			(6	)		(7	)		—			(7	)
Other, net		60			(18	)(g),(h)		42			(151	)		189	(h)		38
Total other income and deductions		(122	)		(18	)		(140	)		(352	)		189			(163	)
Income before income taxes		954			28			982			981			114			1,095
Income taxes		373			(1	)(c),(d),(e),(f),(g),(h)		372			294			91	(c),(d),(e),(h),(i)		385
Income from continuing operations		581			29			610			687			23			710
Income (loss) from discontinued operations		—			—			—			20			(21	)(j)		(1	)
Net income	$	581		$	29		$	610		$	707		$	2		$	709
Effective tax rate		39.1	%					37.9	%		30.0	%					35.2	%
Earnings per average common share
Basic:
Income from continuing operations	$	0.88		$	0.04		$	0.92		$	1.04		$	0.03		$	1.07
Income from discontinued operations		—			—			—			0.03			(0.03	)		—
Net income	$	0.88		$	0.04		$	0.92		$	1.07		$	—		$	1.07
Diluted:
Income from continuing operations	$	0.88		$	0.04		$	0.92		$	1.04		$	0.03		$	1.07
Income from discontinued operations		—			—			—			0.03			(0.03	)		—
Net income	$	0.88		$	0.04		$	0.92		$	1.07		$	—		$	1.07
Average common shares outstanding
Basic		660						660			658						658
Diluted		662						662			661						661
Effect of adjustments on earnings per average diluted common share recorded in accordance with GAAP:
2007 Illinois electric rate settlement (c)				$	0.02								$	0.04
City of Chicago settlement (d)					0.01									0.02
Mark-to-market impact of economic hedging activities (e)					(0.04	)								(0.15	)
Retirement of fossil generating units (f)					0.05									—
Costs associated with early debt retirements (g)					0.02									—
Unrealized gains and losses related to NDT fund investments (h)					(0.02	)								0.10
NRG acquisition costs (i)					—									0.02
Resolution of tax matters related to Sithe (j)					—									(0.03	)
Total adjustments				$	0.04								$	—

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

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

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

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

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

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

(i) Adjustment to exclude external costs in 2008 associated with Exelon’s proposed acquisition of NRG Energy, Inc. (NRG), which was terminated in July 2009.

(j) Adjustment to exclude the resolution of tax matters at Generation related to Sithe.

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, 2009									Twelve Months Ended December 31, 2008
	GAAP (a)			Adjustments			Adjusted Non-GAAP			GAAP (a)			Adjustments			Adjusted Non-GAAP
Operating revenues	$	17,318		$	114	(c),(d)	$	17,432		$	18,859		$	245	(c),(d)	$	19,104
Operating expenses
Purchased power		3,215			94	(e)		3,309			4,270			414	(e)		4,684
Fuel		2,066			87	(e)		2,153			2,312			38	(e)		2,350
Operating and maintenance		4,612			(265	)(c),(f),(g),(h),(i),(j)		4,347			4,538			—	(c),(f),(i)		4,538
Operating and maintenance for regulatory required programs (b)		63			—			63			28			—			28
Depreciation and amortization		1,834			(32	)(j)		1,802			1,634			—			1,634
Taxes other than income		778			—			778			778			—			778
Total operating expenses		12,568			(116	)		12,452			13,560			452			14,012
Operating income		4,750			230			4,980			5,299			(207	)		5,092
Other income and deductions
Interest expense, net		(731	)		12	(k),(l)		(719	)		(832	)		—			(832	)
Equity in losses of unconsolidated affiliates and investments		(27	)		—			(27	)		(26	)		—			(26	)
Other, net		426			(324	)(k),(l),(m)		102			(407	)		524	(m)		117
Total other income and deductions		(332	)		(312	)		(644	)		(1,265	)		524			(741	)
Income from continuing operations before income taxes		4,418			(82	)		4,336			4,034			317			4,351
Income taxes		1,712			(98	)(c),(d),(e),(f),(g),(h),(i),(j),(k),(l),(m)		1,614			1,317			253	(c),(d),(e),(f),(i),(m)		1,570
Income from continuing operations		2,706			16			2,722			2,717			64			2,781
Income from discontinued operations		1			—			1			20			(20	)(n)		—
Net Income	$	2,707		$	16		$	2,723		$	2,737		$	44		$	2,781
Effective tax rate		38.8	%					37.2	%		32.6	%					36.1	%
Earnings per average common share
Basic:
Income from continuing operations	$	4.10		$	0.03		$	4.13		$	4.13		$	0.10		$	4.23
Income from discontinued operations		—			—			—			0.03			(0.03	)		—
Net income	$	4.10		$	0.03		$	4.13		$	4.16		$	0.07		$	4.23
Diluted:
Income from continuing operations	$	4.09		$	0.03		$	4.12		$	4.10		$	0.10		$	4.20
Income from discontinued operations		—			—			—			0.03			(0.03	)		—
Net income	$	4.09		$	0.03		$	4.12		$	4.13		$	0.07		$	4.20
Average common shares outstanding
Basic		659						659			658						658
Diluted		662						662			662						662
Effect of adjustments on earnings per average diluted common share recorded in accordance with GAAP:
2007 Illinois electric rate settlement (c)				$	0.10								$	0.22
City of Chicago settlement (d)					0.01									0.02
Mark-to-market impact of economic hedging activities (e)					(0.16	)								(0.41	)
NRG acquisition costs (f)					0.03									0.02
Impairment of certain generating assets (g)					0.20									—
2009 restructuring charges (h)					0.03									—
Decommissioning obligation reduction (i)					(0.05	)								(0.02	)
Retirement of fossil generating units (j)					0.05									—
Non-cash income tax matters and state taxes (k)					(0.10	)								—
Costs associated with early debt retirements (l)					0.11									—
Unrealized gains and losses related to NDT fund investments (m)					(0.19	)								0.27
Resolution of tax matters related to Sithe (n)					—									(0.03	)
Total adjustments				$	0.03								$	0.07

(a) Results reported in accordance with GAAP.

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

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

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

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

(h) Adjustment to exclude 2009 restructuring charges.

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

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

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

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

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

(n) Adjustment to exclude the resolution of tax matters at Generation related to Sithe.

8

EXELON CORPORATION

Reconciliation of Adjusted (non-GAAP) Operating Earnings

to GAAP Earnings By Business Segment (in millions)

Three Months Ended December 31, 2009 and 2008

	Exelon Earnings per Diluted Share			Generation			ComEd			PECO			Other			Exelon
2008 GAAP Earnings (Loss)	$	1.07		$	553		$	91		$	80		$	(17	)	$	707
2008 Adjusted (non-GAAP) Operating Earnings (Loss) Adjustments:
2007 Illinois Electric Rate Settlement		0.04			23			3			—			—			26
Mark-to-Market Impact of Economic Hedging Activities		(0.15	)		(93	)		—			—			—			(93	)
Unrealized Losses Related to NDT Fund Investments		0.10			68			—			—			—			68
City of Chicago Settlement with ComEd		0.02			—			11			—			—			11
Resolution of Tax Matters at Generation Related to Sithe		(0.03	)		(21	)		—			—			—			(21	)
NRG Acquisition Costs (1)		0.02			—			—			—			11			11
2008 Adjusted (non-GAAP) Operating Earnings (Loss)		1.07			530			105			80			(6	)		709
Year Over Year Effects on Earnings:
Generation Energy Margins, Excluding Mark-to-Market:
Nuclear Output (2)		(0.04	)		(23	)		—			—			—			(23	)
Nuclear Fuel Costs (3)		(0.02	)		(13	)		—			—			—			(13	)
Market and Portfolio Conditions (4)		(0.03	)		(18	)		—			—			—			(18	)
ComEd and PECO Margins:
Weather (5)		(0.02	)		—			(8	)		(7	)		—			(15	)
Other Energy Delivery (6)		(0.02	)		—			(17	)		6			—			(11	)
Operating and Maintenance Expense:
Bad Debt (7)		0.02			—			1			10			—			11
Labor, Contracting and Materials (8)		0.07			16			22			3			—			41
Other Operating and Maintenance (9)		(0.01	)		(14	)		3			(1	)		1			(11	)
Pension and Non-Pension Postretirement Benefits (10)		(0.04	)		(14	)		(7	)		(1	)		(3	)		(25	)
Depreciation and Amortization Expense (11)		(0.04	)		(4	)		(1	)		(17	)		(1	)		(23	)
Tax Method Change - Overhead Costs (12)		(0.02	)		—			(15	)		(3	)		4			(14	)
Income Taxes (13)		(0.04	)		(15	)		4			(1	)		(12	)		(24	)
Interest Expense (14)		0.02			(6	)		8			11			—			13
Other (15)		0.02			2			10			(2	)		3			13
2009 Adjusted (non-GAAP) Operating Earnings (Loss)		0.92			441			105			78			(14	)		610
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		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 (16)		(0.05	)		(34	)		—			—			—			(34	)
2009 GAAP Earnings (Loss)	$	0.88		$	425		$	98		$	78		$	(20	)	$	581

(1) Reflects external costs incurred in 2008 associated with Exelon’s proposed acquisition of NRG, which was terminated in July 2009.

(2) Reflects the impact of increased planned and unplanned nuclear outage days in 2009, primarily due to steam generator replacement at Three Mile Island.

(3) Reflects the impact of higher nuclear fuel costs.

(4) Primarily reflects the impact of lower energy prices, partially offset by the impact of 2008 impairments of stored oil inventory.

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

(6) For ComEd, primarily reflects lower transmission revenues and the impact of reduced load. For PECO, primarily reflects increased gas distribution rates effective January 2009, partially offset by the impact of reduced load.

(7) Reflects the impact of improved accounts receivable aging at PECO as a result of enhancements to its credit processes and increased termination and collection activities in late 2008 and 2009.

(8) Primarily reflects the impact of Exelon’s 2009 cost savings program, partially offset by inflation related to labor, contracting and materials expense.

(9) Primarily reflects the 2008 impact of a nuclear insurance credit at Generation, partially offset by the impact of Exelon’s 2009 cost savings program.

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

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

(12) Reflects the impact of income tax benefits in 2008 associated with Exelon’s tax method of capitalizing overhead costs.

(13) Primarily reflects the 2008 impacts of benefits from state tax settlements and tax planning.

(14) Primarily reflects decreased interest expense due to lower outstanding debt at PECO.

(15) Primarily reflects decreased taxes other than income at ComEd.

(16) Reflects incremental accelerated depreciation, inventory write-downs and severance costs associated with the planned retirement of four fossil generating units in 2011.

9

EXELON CORPORATION

Reconciliation of Adjusted (non-GAAP) Operating Earnings

to GAAP Earnings By Business Segment (in millions)

Twelve Months Ended December 31, 2009 and 2008

	Exelon Earnings per Diluted Share			Generation			ComEd			PECO			Other			Exelon
2008 GAAP Earnings (Loss)	$	4.13		$	2,278		$	201		$	325		$	(67	)	$	2,737
2008 Adjusted (non-GAAP) Operating Earnings (Loss) Adjustments:
2007 Illinois Electric Rate Settlement		0.22			138			7			—			—			145
Mark-to-Market Impact of Economic Hedging Activities		(0.41	)		(272	)		—			—			—			(272	)
Unrealized Losses Related to NDT Fund Investments		0.27			184			—			—			—			184
Decommissioning Obligation Reduction (1)		(0.02	)		(15	)		—			—			—			(15	)
City of Chicago Settlement with ComEd		0.02			—			11			—			—			11
Resolution of Tax Matters at Generation Related to Sithe		(0.03	)		(20	)		—			—			—			(20	)
NRG Acquisition Costs (2)		0.02			—			—			—			11			11
2008 Adjusted (non-GAAP) Operating Earnings (Loss)		4.20			2,293			219			325			(56	)		2,781
Year Over Year Effects on Earnings:
Generation Energy Margins, Excluding Mark-to-Market:
Nuclear Output (3)		0.02			10			—			—			—			10
Nuclear Fuel Costs (4)		(0.07	)		(46	)		—			—			—			(46	)
Market and Portfolio Conditions (5)		(0.20	)		(128	)		—			—			—			(128	)
ComEd and PECO Margins:
Weather (6)		(0.06	)		—			(27	)		(15	)		—			(42	)
Other Energy Delivery (7)		0.19			—			97			26			—			123
Operating and Maintenance Expense:
Bad Debt (8)		0.11			14			(9	)		69			—			74
Labor, Contracting and Materials (9)		0.08			22			40			(7	)		—			55
Other Operating and Maintenance (10)		0.09			(2	)		36			11			11			56
Pension and Non-Pension Postretirement Benefits (11)		(0.15	)		(52	)		(31	)		(6	)		(9	)		(98	)
Planned Nuclear Refueling Outages (12)		0.03			17			—			—			—			17
Discrete Items Resulting From the Distribution Rate Case (13)		0.02			—			15			—			—			15
Depreciation and Amortization Expense (14)		(0.17	)		(17	)		(20	)		(69	)		(7	)		(113	)
Tax Method Change - Overhead Costs (15)		(0.03	)		6			(24	)		(7	)		5			(20	)
Income Taxes (16)		(0.07	)		(41	)		14			12			(30	)		(45	)
Interest Expense (17)		0.11			15			30			27			3			75
Other (18)		0.02			1			16			(12	)		4			9
2009 Adjusted (non-GAAP) Operating Earnings (Loss)		4.12			2,092			356			354			(79	)		2,723
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		0.19			132			—			—			—			132
Decommissioning Obligation Reduction (1)		0.05			32			—			—			—			32
City of Chicago Settlement with ComEd		(0.01	)		—			(5	)		—			—			(5	)
NRG Acquisition Costs (2)		(0.03	)		—			—			—			(20	)		(20	)
Impairment of Certain Generating Assets (19)		(0.20	)		(135	)		—			—			—			(135	)
2009 Restructuring Charges (20)		(0.03	)		(7	)		(13	)		(1	)		(1	)		(22	)
Non-Cash Remeasurement of Income Tax Uncertainties and Reassessment of State Deferred Income Taxes (21)		0.10			38			40			—			(12	)		66
Costs Associated with Early Debt Retirements		(0.11	)		(44	)		—			—			(30	)		(74	)
Retirement of Fossil Generating Units (22)		(0.05	)		(34	)		—			—			—			(34	)
2009 GAAP Earnings (Loss)	$	4.09		$	2,122		$	374		$	353		$	(142	)	$	2,707

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

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

(3) Primarily reflects the impact of decreased planned and unplanned nuclear outage days in 2009.

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

(5) Primarily reflects the 2008 impacts of revenue from certain long options in Generation’s proprietary trading portfolio and gains related to the settlement of uranium supply agreements and the 2009 impact of lower energy prices, partially offset by the impact of 2008 impairments of stored oil inventory.

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

(7) Primarily reflects increased distribution rates at ComEd effective September 2008, increased gas distribution rates at PECO effective January 2009 and the impact of a reduction in PECO’s 2008 distribution rates made to refund the 2007 Pennsylvania Public Utility Realty Tax Act tax settlement to customers (completely offset by increased taxes other than income as noted in number 18 below), partially offset by reduced load at ComEd and PECO.

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

(9) Primarily reflects the impact of Exelon’s 2009 cost savings program, partially offset by inflation related to labor, contracting and materials expense (exclusive of planned nuclear refueling outages as disclosed in number 12 below).

(10) Primarily reflects the impact of decreased storm costs in 2009 in the ComEd and PECO service territories, decreased nuclear refueling outage costs related to Generation’s ownership interest in Salem and the impact of Exelon’s 2009 cost savings program, partially offset by the 2008 impact of a nuclear insurance credit at Generation.

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

(12) Reflects fewer planned nuclear refueling outages, excluding Salem, despite increased outage days for steam generator replacement at Three Mile Island.

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

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

(15) Reflects the impact of income tax benefits in 2008 associated with Exelon’s tax method of capitalizing overhead costs.

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

(17) Primarily reflects decreased interest expense due to lower outstanding debt at ComEd, PECO and Exelon Corporate and lower interest rates on Generation’s spent nuclear fuel obligation.

(18) For ComEd, primarily reflects decreased taxes other than income. For PECO, primarily reflects increased taxes other than income (completely offset by increased revenues as noted in number 7 above), partially offset by a decrease in gross receipts tax expense due to a rate reduction.

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

(20) Reflects severance expense associated with the elimination of management and staff positions pursuant to Exelon’s 2009 cost savings program.

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

(22) Reflects incremental accelerated depreciation, inventory write-downs and severance costs associated with the planned retirement of four fossil generating units in 2011.

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, 2009									Three Months Ended December 31, 2008
	GAAP (a)			Adjustments			Adjusted Non-GAAP			GAAP (a)			Adjustments			Adjusted Non-GAAP
Operating revenues	$	2,278		$	20	(b)	$	2,298		$	2,443		$	37	(b)	$	2,480
Operating expenses
Purchased power		375			(36	)(c)		339			163			204	(c)		367
Fuel		300			78	(c)		378			494			(50	)(c)		444
Operating and maintenance		727			(24	)(d)		703			694			—			694
Depreciation and amortization		110			(32	)(d)		78			72			—			72
Taxes other than income		55			—			55			44			—			44
Total operating expenses		1,567			(14	)		1,553			1,467			154			1,621
Operating income		711			34			745			976			(117	)		859
Other income and deductions
Interest expense, net		(36	)		—			(36	)		(28	)		—			(28	)
Equity in losses of investments		—			—			—			—			—			—
Other, net		50			(28	)(e),(f)		22			(177	)		189	(f)		12
Total other income and deductions		14			(28	)		(14	)		(205	)		189			(16	)
Income from continuing operations before income taxes		725			6			731			771			72			843
Income taxes		300			(10	)(b),(c),(d),(e),(f)		290			239			74	(b),(c),(f)		313
Income from continuing operations		425			16			441			532			(2	)		530
Income from discontinued operations		—			—			—			21			(21	)(g)		—
Net Income	$	425		$	16		$	441		$	553		$	(23	)	$	530
	Twelve Months Ended December 31, 2009									Twelve Months Ended December 31, 2008
	GAAP (a)			Adjustments			Adjusted Non-GAAP			GAAP (a)			Adjustments			Adjusted Non-GAAP
Operating revenues	$	9,703		$	98	(b)	$	9,801		$	10,754		$	221	(b)	$	10,975
Operating expenses
Purchased power		1,338			94	(c)		1,432			1,867			414	(c)		2,281
Fuel		1,594			87	(c)		1,681			1,705			38	(c)		1,743
Operating and maintenance		2,938			(207	)(d),(h),(i),(j)		2,731			2,717			25	(j)		2,742
Depreciation and amortization		333			(32	)(d)		301			274			—			274
Taxes other than income		205			—			205			197			—			197
Total operating expenses		6,408			(58	)		6,350			6,760			477			7,237
Operating income		3,295			156			3,451			3,994			(256	)		3,738
Other income and deductions
Interest expense, net		(113	)		2	(e)		(111	)		(136	)		—			(136	)
Equity in losses of investments		(3	)		—			(3	)		(1	)		—			(1	)
Other, net		376			(320	)(e),(f),(j)		56			(469	)		524	(f)		55
Total other income and deductions		260			(318	)		(58	)		(606	)		524			(82	)
Income from continuing operations before income taxes		3,555			(162	)		3,393			3,388			268			3,656
Income taxes		1,433			(132	)(b),(c),(d),(e),(f),(h),(i),(j),(k)		1,301			1,130			233	(b),(c),(f),(j)		1,363
Income from continuing operations		2,122			(30	)		2,092			2,258			35			2,293
Income from discontinued operations		—			—			—			20			(20	)(g)		—
Net income	$	2,122		$	(30	)	$	2,092		$	2,278		$	15		$	2,293

(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 the planned retirement of fossil generating units.

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

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

(g) Adjustment to exclude the resolution of tax matters at Generation related to Sithe.

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

(i) Adjustment to exclude 2009 restructuring charges.

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

(k) 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, 2009									Three Months Ended December 31, 2008
	GAAP (a)			Adjustments			Adjusted Non-GAAP			GAAP (a)			Adjustments			Adjusted Non-GAAP
Operating revenues	$	1,357		$	12	(c),(d)	$	1,369		$	1,542		$	19	(c),(d)	$	1,561
Operating expenses
Purchased power		692			—			692			853			—			853
Operating and maintenance		232			—			232			268			(4	)(c)		264
Operating and maintenance for regulatory required programs (b)		19			—			19			11			—			11
Depreciation and amortization		123			—			123			121			—			121
Taxes other than income		67			—			67			72			—			72
Total operating expenses		1,133			—			1,133			1,325			(4	)		1,321
Operating income		224			12			236			217			23			240
Other income and deductions
Interest expense, net		(78	)		—			(78	)		(69	)		—			(69	)
Equity in losses of unconsolidated affiliates		—			—			—			(2	)		—			(2	)
Other, net		11			—			11			6			—			6
Total other income and deductions		(67	)		—			(67	)		(65	)		—			(65	)
Income before income taxes		157			12			169			152			23			175
Income taxes		59			5	(c),(d)		64			61			9	(c),(d)		70
Net income	$	98		$	7		$	105		$	91		$	14		$	105
	Twelve Months Ended December 31, 2009									Twelve Months Ended December 31, 2008
	GAAP (a)			Adjustments			Adjusted Non-GAAP			GAAP (a)			Adjustments			Adjusted Non-GAAP
Operating revenues	$	5,774		$	16	(c),(d)	$	5,790		$	6,136		$	24	(c),(d)	$	6,160
Operating expenses
Purchased power		3,065			—			3,065			3,582			—			3,582
Operating and maintenance		1,028			(20	)(c),(e)		1,008			1,097			(7	)(c)		1,090
Operating and maintenance for regulatory required programs (b)		63			—			63			28						28
Depreciation and amortization		494			—			494			464			—			464
Taxes other than income		281			—			281			298			—			298
Total operating expenses		4,931			(20	)		4,911			5,469			(7	)		5,462
Operating income		843			36			879			667			31			698
Other income and deductions
Interest expense, net		(319	)		(6	)(f)		(325	)		(348	)		—			(348	)
Equity in losses of unconsolidated affiliates		—			—			—			(8	)		—			(8	)
Other, net		79			(60	)(f)		19			18			—			18
Total other income and deductions		(240	)		(66	)		(306	)		(338	)		—			(338	)
Income before income taxes		603			(30	)		573			329			31			360
Income taxes		229			(12	)(c),(d),(e),(f)		217			128			13	(c),(d)		141
Net income	$	374		$	(18	)	$	356		$	201		$	18		$	219

(a) Results reported in accordance with GAAP.

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

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

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

(e) Adjustment to exclude 2009 restructuring charges.

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

12

EXELON CORPORATION

Reconciliation of Adjusted (non-GAAP) Operating Earnings to

GAAP Consolidated Statements of Operations

(unaudited)

(in millions)

	PECO
	Three Months Ended December 31, 2009									Three Months Ended December 31, 2008
	GAAP (a)			Adjustments			Adjusted Non-GAAP			GAAP (a)			Adjustments		Adjusted Non-GAAP
Operating revenues	$	1,266		$	—		$	1,266		$	1,372		$	—	$	1,372
Operating expenses
Purchased power		532			—			532			553			—		553
Fuel		126			—			126			210			—		210
Operating and maintenance		159			—			159			174			—		174
Depreciation and amortization		225			—			225			200			—		200
Taxes other than income		64			—			64			61			—		61
Total operating expenses		1,106			—			1,106			1,198			—		1,198
Operating income		160			—			160			174			—		174
Other income and deductions
Interest expense, net		(42	)		—			(42	)		(55	)		—		(55	)
Equity in losses of unconsolidated affiliates		(5	)		—			(5	)		(5	)		—		(5	)
Other, net		5			—			5			5			—		5
Total other income and deductions		(42	)		—			(42	)		(55	)		—		(55	)
Income before income taxes		118			—			118			119			—		119
Income taxes		40			—			40			39			—		39
Net income	$	78		$	—		$	78		$	80		$	—	$	80
	Twelve Months Ended December 31, 2009									Twelve Months Ended December 31, 2008
	GAAP (a)			Adjustments			Adjusted Non-GAAP			GAAP (a)			Adjustments		Adjusted Non-GAAP
Operating revenues	$	5,311		$	—		$	5,311		$	5,567		$	—	$	5,567
Operating expenses
Purchased power		2,274			—			2,274			2,411			—		2,411
Fuel		472			—			472			607					607
Operating and maintenance		640			(3	)(b)		637			731			—		731
Depreciation and amortization		952			—			952			854			—		854
Taxes other than income		276			—			276			265			—		265
Total operating expenses		4,614			(3	)		4,611			4,868			—		4,868
Operating income		697			3			700			699			—		699
Other income and deductions
Interest expense, net		(187	)		—			(187	)		(226	)		—		(226	)
Equity in losses of unconsolidated affiliates		(24	)		—			(24	)		(16	)		—		(16	)
Other, net		13			—			13			18			—		18
Total other income and deductions		(198	)		—			(198	)		(224	)		—		(224	)
Income before income taxes		499			3			502			475			—		475
Income taxes		146			2	(b)		148			150			—		150
Net income	$	353		$	1		$	354		$	325		$	—	$	325

(a) Results reported in accordance with GAAP.

(b) Adjustment to exclude 2009 restructuring charges.

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, 2009									Three Months Ended December 31, 2008
	GAAP (a)			Adjustments			Adjusted Non-GAAP			GAAP (a)			Adjustments			Adjusted Non-GAAP
Operating revenues	$	(785	)	$	—		$	(785	)	$	(864	)	$	—		$	(864	)
Operating expenses
Purchased power		(784	)		—			(784	)		(865	)		—			(865	)
Fuel		(1	)		—			(1	)		—			—			—
Operating and maintenance		2			—			2			19			(18	)(c)		1
Depreciation and amortization		16			—			16			12			—			12
Taxes other than income		1			—			1			4			—			4
Total operating expenses		(766	)		—			(766	)		(830	)		(18	)		(848	)
Operating loss		(19	)		—			(19	)		(34	)		18			(16	)
Other income and deductions
Interest expense, net		(20	)		—			(20	)		(42	)		—			(42	)
Equity in losses of unconsolidated affiliates and investments		(1	)		—			(1	)		—			—			—
Other, net		(6	)		10	(b)		4			15			—			15
Total other income and deductions		(27	)		10			(17	)		(27	)		—			(27	)
Loss before income taxes		(46	)		10			(36	)		(61	)		18			(43	)
Income taxes		(26	)		4	(b)		(22	)		(45	)		7	(d)		(38	)
Income (loss) from continuing operations		(20	)		6			(14	)		(16	)		11			(5	)
Loss from discontinued operations		—			—			—			(1	)		—			(1	)
Net loss	$	(20	)	$	6		$	(14	)	$	(17	)	$	11		$	(6	)

	Twelve Months Ended December 31, 2009									Twelve Months Ended December 31, 2008
	GAAP (a)			Adjustments			Adjusted Non-GAAP			GAAP (a)			Adjustments			Adjusted Non-GAAP
Operating revenues	$	(3,470	)	$	—		$	(3,470	)	$	(3,598	)	$	—		$	(3,598	)
Operating expenses
Purchased power		(3,462	)		—			(3,462	)		(3,590	)		—			(3,590	)
Fuel		—			—			—			—			—			—
Operating and maintenance		6			(35	)(c),(d)		(29	)		(7	)		(18	)(c)		(25	)
Depreciation and amortization		55			—			55			42			—			42
Taxes other than income		16			—			16			18			—			18
Total operating expenses		(3,385	)		(35	)		(3,420	)		(3,537	)		(18	)		(3,555	)
Operating loss		(85	)		35			(50	)		(61	)		18			(43	)
Other income and deductions
Interest expense, net		(112	)		16	(b),(e)		(96	)		(122	)		—			(122	)
Equity in losses of unconsolidated affiliates and investments		—			—			—			(1	)		—			(1	)
Other, net		(42	)		56	(b),(e)		14			26			—			26
Total other income and deductions		(154	)		72			(82	)		(97	)		—			(97	)
Loss before income taxes		(239	)		107			(132	)		(158	)		18			(140	)
Income taxes		(96	)		44	(b),(c),(d),(e),(f)		(52	)		(91	)		7	(c)		(84	)
Loss from continuing operations		(143	)		63			(80	)		(67	)		11			(56	)
Income from discontinued operations		1			—			1			—			—			—
Net loss	$	(142	)	$	63		$	(79	)	$	(67	)	$	11		$	(56	)

(a) Results reported in accordance with GAAP.

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

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

(d) Adjustment to exclude 2009 restructuring charges.

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

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

14

EXELON CORPORATION

Exelon Generation Statistics

	Three Months Ended
	Dec. 31, 2009		Sept. 30, 2009		Jun. 30, 2009		Mar. 31, 2009		Dec. 31, 2008
Supply (in GWhs)
Nuclear		33,609		35,684		34,995		35,382		34,887
Purchased Power		5,184		6,669		5,276		6,077		6,100
Fossil and Hydro		2,034		2,689		2,701		2,765		2,162
Power Team Supply		40,827		45,042		42,972		44,224		43,149
	Three Months Ended
	Dec. 31, 2009		Sept. 30, 2009		Jun. 30, 2009		Mar. 31, 2009		Dec. 31, 2008
Electric Sales (in GWhs)
ComEd (a)		3,439		3,639		4,215		5,537		5,261
PECO (a)		9,588		10,809		9,277		10,223		9,760
Market and Retail (a)		27,800		30,594		29,480		28,464		28,128
Total Electric Sales (b) (c)		40,827		45,042		42,972		44,224		43,149
Average Margin ($/MWh)
Average Realized Revenue
ComEd (a)	$	63.39	$	64.03	$	63.58	$	63.21	$	63.30
PECO (a)		48.60		51.35		51.74		49.30		49.28
Market and Retail (a)		54.96		52.99		54.27		57.12		54.18
Total Electric Sales		54.18		53.48		54.64		56.08		54.18
Average Purchased Power and Fuel Cost (d)	$	15.82	$	17.16	$	15.68	$	16.82	$	15.90
Average Margin (d)	$	38.36	$	36.32	$	38.96	$	39.25	$	38.28
Around-the-clock Market Prices ($/MWh) (e)
PJM West Hub	$	37.31	$	33.20	$	33.70	$	49.18	$	52.62
NiHub		29.61		25.69		26.11		34.09		38.06

(a) $88 million, $104 million, $69 million, $31 million and $20 million of pre-tax revenue resulting from the settlement of the ComEd swap starting in June 2008, have been excluded from ComEd and included in Market and Retail sales for the quarters ended December 31, 2009, September 30, 2009, June 30, 2009, March 31, 2009 and December 31, 2008, respectively. Additionally, $12 million (411 GWhs), $11 million (397 GWhs), $7 million (209 GWhs), $58 million (898 GWhs) and $29 million (486 GWhs) of pre-tax revenue, resulting from sales to ComEd under the RFP, which started in September 2008, have been excluded from ComEd and included in Market and Retail sales for the quarters ended December 31, 2009, September 30, 2009, June 30, 2009, March 31, 2009 and December 31, 2008, respectively. In addition, renewable energy credits sales to affiliates have been included within Market and Retail Sales.

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

(c) Total sales do not include trading volume of 1,599 GWhs, 1,645 GWhs, 2,003 GWhs, 2,331 GWhs and 2,153 GWhs for the three months ended December 31, 2009, September 30, 2009, June 30, 2009, March 31, 2009 and December 31, 2008, respectively.

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

(e) Represents the average for the quarter.

15

EXELON CORPORATION

Exelon Generation Statistics

Twelve Months Ended December 31, 2009 and 2008

	December 31, 2009		December 31, 2008
Supply (in GWhs)
Nuclear		139,670		139,342
Purchased Power		23,206		26,263
Fossil and Hydro		10,189		10,569
Power Team Supply		173,065		176,174
	December 31, 2009		December 31, 2008
Electric Sales (in GWhs)
ComEd (a)		16,830		23,200
PECO (a)		39,897		40,966
Market and Retail (a)		116,338		112,008
Total Electric Sales (b) (c)		173,065		176,174
Average Margin ($/MWh)
Average Realized Revenue
ComEd (a)	$	63.52	$	63.71
PECO (a)		50.25		50.85
Market and Retail (a)		54.79		59.99
Total Electric Sales		54.59		58.35
Average Purchased Power and Fuel Cost (d)	$	16.39	$	19.87
Average Margin (d)	$	38.20	$	38.48
Around-the-clock Market Prices ($/MWh) (e)
PJM West Hub	$	38.30	$	68.52
NiHub		28.85		49.00

(a) $292 million of pre-tax revenue, and $2 million of a pre-tax reduction in revenue, resulting from the settlement of the ComEd swap starting in June 2008, have been excluded from ComEd and included in Market and Retail sales for the twelve months ended December 31, 2009 and December 31, 2008, respectively. Additionally, $88 million (1,916 GWhs) and $29 million (486 GWhs) of pre-tax revenue, resulting from sales to ComEd under the RFP, which started in September 2008, have been excluded from ComEd and included in Market and Retail sales for the twelve months ended December 31, 2009 and December 31, 2008, respectively. In addition, renewable energy credits sales to affiliates have been included within Market and Retail Sales.

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

(c) Total sales do not include trading volume of 7,578 GWhs and 8,891 GWhs for the twelve months ended December 31, 2009 and December 31, 2008, respectively.

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

(e) Represents the average for the year.

16

EXELON CORPORATION

ComEd Statistics

Three Months Ended December 31, 2009 and 2008

	Electric Deliveries (in GWhs)				Revenue (in millions)
	2009	2008	% Change		2009		2008		% Change
Full Service (a)
Residential	6,541	6,868	(4.8	)%	$	741	$	839	(11.7	)%
Small Commercial & Industrial	3,188	3,545	(10.1	)%		297		373	(20.4	)%
Large Commercial & Industrial	292	242	20.7	%		17		18	(5.6	)%
Public Authorities & Electric Railroads	116	97	19.6	%		12		12	0.0	%
Total Full Service	10,137	10,752	(5.7	)%		1,067		1,242	(14.1	)%
Delivery Only (b)
Residential (c)	—	—	n.m.			—		—	n.m.
Small Commercial & Industrial	4,709	4,521	4.2	%		81		78	3.8	%
Large Commercial & Industrial	6,213	6,630	(6.3	)%		76		80	(5.0	)%
Public Authorities & Electric Railroads	213	213	0.0	%		3		4	(25.0	)%
Total Delivery Only	11,135	11,364	(2.0	)%		160		162	(1.2	)%
Total Retail	21,272	22,116	(3.8	)%		1,227		1,404	(12.6	)%
Other Revenue (d)						130		138	(5.8	)%
Total Revenues					$	1,357	$	1,542	(12.0	)%
Purchased Power					$	692	$	853	(18.9	)%
Heating and Cooling Degree-Days (e)	2009	2008	Normal
Heating Degree-Days	2,264	2,455	2,278
Cooling Degree-Days	—	10	7

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

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

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

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

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

n.m. Not meaningful.

Twelve Months Ended December 31, 2009 and 2008

	Electric Deliveries (in GWhs)				Revenue (in millions)
	2009	2008	% Change		2009		2008		% Change
Full Service (a)
Residential	26,619	28,389	(6.2	)%	$	3,115	$	3,284	(5.1	)%
Small Commercial & Industrial	13,633	14,937	(8.7	)%		1,335		1,542	(13.4	)%
Large Commercial & Industrial	1,216	1,045	16.4	%		73		90	(18.9	)%
Public Authorities & Electric Railroads	421	578	(27.2	)%		44		52	(15.4	)%
Total Full Service	41,889	44,949	(6.8	)%		4,567		4,968	(8.1	)%
Delivery Only (b)
Residential	2	—	n.m.			—		—	n.m.
Small Commercial & Industrial	18,601	18,550	0.3	%		325		289	12.5	%
Large Commercial & Industrial	25,452	27,764	(8.3	)%		314		295	6.4	%
Public Authorities & Electric Railroads	816	636	28.3	%		13		7	85.7	%
Total Delivery Only	44,871	46,950	(4.4	)%		652		591	10.3	%
Total Retail	86,760	91,899	(5.6	)%		5,219		5,559	(6.1	)%
Other Revenue (c)						555		577	(3.8	)%
Total Revenues					$	5,774	$	6,136	(5.9	)%
Purchased Power					$	3,065	$	3,582	(14.4	)%
Heating and Cooling Degree-Days (d)	2009	2008	Normal
Heating Degree-Days	6,429	6,680	6,362
Cooling Degree-Days	589	828	855

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

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

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

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

n.m. Not meaningful.

17

EXELON CORPORATION

PECO Statistics

Three Months Ended December 31, 2009 and 2008

	Electric and Gas Deliveries				Revenue (in millions)
	2009	2008	% Change		2009		2008		% Change
Electric (in GWhs)
Full Service (a)
Residential	3,083	3,136	(1.7	)%	$	429	$	430	(0.2	)%
Small Commercial & Industrial	1,889	1,953	(3.3	)%		228		235	(3.0	)%
Large Commercial & Industrial	3,871	3,954	(2.1	)%		312		332	(6.0	)%
Public Authorities & Electric Railroads	228	229	(0.4	)%		22		22	0.0	%
Total Full Service	9,071	9,272	(2.2	)%		991		1,019	(2.7	)%
Delivery Only (b)
Residential	5	6	(16.7	)%		—		—	n.m.
Small Commercial & Industrial	76	98	(22.4	)%		4		5	(20.0	)%
Large Commercial & Industrial	7	1	600.0	%		—		—	n.m.
Total Delivery Only	88	105	(16.2	)%		4		5	(20.0	)%
Total Electric Retail	9,159	9,377	(2.3	)%		995		1,024	(2.8	)%
Other Revenue (c)						59		70	(15.7	)%
Total Electric Revenue						1,054		1,094	(3.7	)%
Gas (in mmcfs)
Retail Sales	17,659	19,131	(7.7	)%		202		272	(25.7	)%
Transportation and Other	7,078	6,818	3.8	%		10		6	66.7	%
Total Gas	24,737	25,949	(4.7	)%		212		278	(23.7	)%
Total Electric and Gas Revenues					$	1,266	$	1,372	(7.7	)%
Purchased Power					$	532	$	553	(3.8	)%
Fuel						126		210	(40.0	)%
Total Purchased Power and Fuel					$	658	$	763	(13.8	)%
Heating and Cooling Degree-Days	2009	2008	Normal
Heating Degree-Days	1,567	1,659	1,634
Cooling Degree-Days	10	19	21

Twelve Months Ended December 31, 2009 and 2008

	Electric and Gas Deliveries				Revenue (in millions)
	2009	2008	% Change		2009		2008		% Change
Electric (in GWhs)
Full Service (a)
Residential	12,871	13,287	(3.1	)%	$	1,857	$	1,916	(3.1	)%
Small Commercial & Industrial	8,044	8,211	(2.0	)%		1,015		1,028	(1.3	)%
Large Commercial & Industrial	15,832	16,474	(3.9	)%		1,307		1,406	(7.0	)%
Public Authorities & Electric Railroads	930	909	2.3	%		90		87	3.4	%
Total Full Service	37,677	38,881	(3.1	)%		4,269		4,437	(3.8	)%
Delivery Only (b)
Residential	22	30	(26.7	)%		2		2	0.0	%
Small Commercial & Industrial	353	469	(24.7	)%		19		25	(24.0	)%
Large Commercial & Industrial	16	3	433.3	%		—		—	n.m.
Total Delivery Only	391	502	(22.1	)%		21		27	(22.2	)%
Total Electric Retail	38,068	39,383	(3.3	)%		4,290		4,464	(3.9	)%
Other Revenue (c)						259		282	(8.2	)%
Total Electric Revenue						4,549		4,746	(4.2	)%
Gas (in mmcfs)
Retail Sales	57,103	56,110	1.8	%		732		795	(7.9	)%
Transportation and Other	27,206	27,624	(1.5	)%		30		26	15.4	%
Total Gas	84,309	83,734	0.7	%		762		821	(7.2	)%
Total Electric and Gas Revenues					$	5,311	$	5,567	(4.6	)%
Purchased Power					$	2,274	$	2,411	(5.7	)%
Fuel						472		607	(22.2	)%
Total Purchased Power and Fuel					$	2,746	$	3,018	(9.0	)%
Heating and Cooling Degree-Days (d)	2009	2008	Normal
Heating Degree-Days	4,534	4,403	4,638
Cooling Degree-Days	1,246	1,354	1,292

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

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

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

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

n.m. Not meaningful.

18

EX-99.2

Earnings Conference Call •

4

th

Quarter 2009

January 22, 2010

EXHIBIT 99.2

2

Forward-Looking Statements

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

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

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

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

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

of

Financial

Condition

and

Results

of

Operations

and

(c)

ITEM

8.

Financial

Statements

and

Supplementary

Data:

Note

18;

(2)

Exelon’s

Third

Quarter

2009

Quarterly

Report

on

Form

10-Q

in

(a)

Part

II,

Other

Information,

ITEM

1A.

Risk

Factors

and

(b)

Part

I,

Financial

Information,

ITEM 1. Financial Statements: Note 14 and (3) other factors discussed in filings with the

Securities and Exchange Commission (SEC) by Exelon Corporation, Commonwealth Edison

Company,

PECO

Energy

Company

and

Exelon

Generation

Company,

LLC

(Companies).

Readers are cautioned not to place undue reliance on these forward-looking statements, which

apply only as of the date of this presentation. None of the Companies undertakes any

obligation to publicly release any revision to its forward-looking statements to reflect events or

circumstances after the date of this presentation.

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

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

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

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

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

earnings.

Please

refer

to

the

footnotes

of

the

following

slides

for

a

reconciliation

non-GAAP

cash flows to GAAP cash flows.

3

Nuclear

Uprates

Deploying Capital for Shareholder Value

Smart Grid

Carbon

Price

Recovery

Transmission

-

1,300–1,500 MW of new Exelon nuclear capacity by 2017, the

equivalent of a new nuclear plant at roughly half the cost of a

new plant and no incremental operating costs

-

Approximately $725 million in investments to build smart grid

infrastructure over the coming years with a regulated return on

investment

-

Lowest carbon intensity in the sector, significant upside if and

when legislation enacted or regulations promulgated, and

enhancing industry-leading position with Exelon 2020

-

Positioned to benefit from our fundamental view of recovery in

natural gas and coal prices, heat rates, and demand growth

-

Leveraging transmission expertise to build Exelon

Transmission Company with the goal of improving reliability,

reducing congestion and moving renewable energy to

population centers

4

Key Financial Messages

Operating results

•

Operating

earnings

of

$0.92/share

for

4Q09

and

$4.12/share

for

2009

(1)

•

93.6% nuclear capacity factor for 2009

•

2009

cash

flow

from

operations

(2)

of

$5.78

billion,

$1

billion

over

original

plan

Far exceeded cost savings expectations in 2009 to offset

unfavorable drivers

•

Realized an additional $200 million of cost savings over plan

Reaffirming 2010 operating earnings guidance of $3.60 -

$4.00/share

(1)

•

Committed to 2010 O&M target of $4.35 billion, offsetting inflation and $35 million

of higher pension and OPEB expense with additional cost savings

•

Initial signs that load stabilization will begin in 2010

•

91-94%

of

2010

expected

generation

hedged

(3)

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

investing activities other than capital expenditures.

(3)    As of December 31, 2009.

Note: Data contained on this slide is rounded.

5

$0.80

$0.12

$0.66

$0.12

$0.16

$0.16

2008

2009

Operating EPS

$3.46

$3.16

$0.49

$0.54

$0.33

$0.54

2008

2009

HoldCo/Other

ExGen

PECO

ComEd

4

th

Quarter (4Q)

(1)

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

original

guidance

range

of

$4.00

-

$4.30/share

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

$1.07

$0.88

GAAP EPS

Full Year (FY)

(1)

$4.12

$4.20

$4.13

$4.09

$0.92

$1.07

6

Exelon Generation                         

Operating EPS Contribution

2009

2008

Key Drivers –

4Q09 vs. 4Q08

(1)

Lower nuclear volume: $(0.04)

Unfavorable market/portfolio

conditions: $(0.03)

Higher nuclear fuel costs: $(0.02)

Higher O&M due to pension and

OPEB expense and 2008 nuclear

insurance credit, partially offset by

cost savings initiatives: $(0.02)

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

(2) Outage days exclude Salem. 

136

80

Refueling

23

22

Non-refueling

4Q09

4Q08

Outage Days

(2)

4Q

FY

$0.80

$0.66

$3.16

$3.46

7

2010

2011

2012

Hedging Update

2010

2011

2012

Percentage of Expected

Generation

Hedged

(1)

91-94%

69-72%

37-40%

Midwest

89-92

71-74

43-46

Mid-Atlantic

93-96

65-68

25-28

South

97-100

66-69

39-42

95% case

5% case

$6,500

$6,100

$4,800

$7,800

$6,200

$8,000

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

conditions, while positioning us to participate in long-term upside potential

Exelon

Generation

Gross

Margin

Upside/Risk

(2)

Expected Generation Hedged

(1)

Percent of expected generation hedged represents how many equivalent MW have been hedged at forward market prices as of December 31, 2009; all hedge products used

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

retire Cromby Station and Eddystone Units 1&2 as of May 31, 2011, pending PJM approval.

(2)

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 2011 and 2012 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, 2009.

($ millions)

8

Key Drivers –

4Q09 vs. 4Q08

(1)

Lower O&M due to cost savings

initiatives, partially offset by higher

pension and OPEB expense:

+$0.03

Reduced load: $(0.01)

Weather: $(0.01)

’08 tax method change: $(0.02)

ComEd Operating EPS Contribution

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

2009

2008

4Q

FY

$0.16

$0.16

$0.54

$0.33

4Q09

Actual

Normal

Heating Degree Days     2,264

2,278

9

ComEd Load Trends

Weather-Normalized Load

Key Economic Indicators

Note: C&I = Commercial & Industrial

Weather-Normalized Load Year-over-Year

(4)

Chicago

U.S.

Unemployment

rate

(1)

10.9%

10.0%

2009 annualized growth in

gross

domestic/metro

product

(2)

(3.1)%

(2.5)%

10/09

Home

price

index

(3)

(10.1)%

(7.3)%

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

Dept. of Labor (December 2009)

(2)

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

(3)

Source: S&P Case-Shiller Index

(4)

Not adjusted for leap year effect

4Q09       2009

(4)

2010E

Customer Growth

(0.5)%

(0.4)%

0.1%

Average Use-Per-Customer

(1.1)%

(1.0)%

0.0%

Total Residential

(1.6)%

(1.4)%

0.0%

Small C&I

0.1%

(2.2)%

0.8%

Large C&I

(4.0)%

(6.7)%

1.5%

All Customer Classes

(1.6)%

(3.3)%

0.8%

-10.0%

-7.5%

-5.0%

-2.5%

0.0%

2.5%

5.0%

7.5%

10.0%

1Q09

2Q09

3Q09

4Q09

1Q10E

2Q10E

3Q10E

4Q10E

-10.0%

-7.5%

-5.0%

-2.5%

0.0%

2.5%

5.0%

7.5%

10.0%

All Customer Classes

Large C&I

Residential

Gross Metro Product

10

PECO Operating EPS Contribution

Key Drivers –

4Q09 vs. 4Q08

(1)

Higher other revenue net fuel, including

gas distribution revenues: +$0.02

Lower bad debt expense: +$0.02

Reduced load: $(0.01)

Weather: $(0.01)

Competitive Transition Charge (CTC)

amortization: $(0.02)

2009

2008

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

4Q

FY

$0.12

$0.12

$0.54

$0.49

4Q09

Actual

Normal

Heating Degree Days   1,567

1,634

11

PECO Load Trends

Weather-Normalized Electric Load

Key Economic Indicators

Weather-Normalized Load Year-over-Year

(3)

Philadelphia

U.S.

Unemployment rate

(1)

8.5%               10.0%

2009 annualized growth in

gross domestic/metro product

(2)

(3.6)%             (2.5)%

(1)  Source:

U.S

Dept.

of

Labor

(PHL

-

November

2009,

US

–

December

2009)

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

(3)  Not adjusted for leap year effect

Note: C&I = Commercial & Industrial

4Q09        2009

(3)

2010E

Customer Growth

(0.4)%

(0.2)%

(0.1)%

Average Use-Per-Customer

0.2%

(2.1)%

(1.2)%

Total Residential

(0.2)%

(2.3)%

(1.3)%

Small C&I

(2.5)%

(2.7)%

(0.7)%

Large C&I

(1.4)%

(3.0)%

(2.4)%

All Customer Classes

(1.3)%

(2.6)%

(1.5)%

-10.0%

-7.5%

-5.0%

-2.5%

0.0%

2.5%

5.0%

7.5%

10.0%

1Q09

2Q09

3Q09

4Q09

1Q10E

2Q10E

3Q10E

4Q10E

-10.0%

-7.5%

-5.0%

-2.5%

0.0%

2.5%

5.0%

7.5%

10.0%

All Customer Classes

Large C&I

Residential

Gross Metro Product

12

Pension and OPEB Expense and Contributions

Pension

Assets

$7,840

Obligations

$11,480

2010E

2009

$210

$250

$205

$200

$440

$260

$155

$155

2010E

2009

(1)

(2)

(3)

OPEB

Assets

$1,475

Obligations

$3,660

Key Metrics

2009 asset return

12/31/09 discount rate

Assumed long-term EROA

Pension and OPEB expense is

increasing by $35 million pre-tax

Pre-Tax Expense

(4)

$0

$50

$100

$150

$200

$250

$300

Pension

OPEB

Pension and OPEB Plans Key Metrics – 12/31/09E   ($ in millions)

(1)

Includes settlement charges.

(2)

Contributions reflect the application of recently issued U.S. Treasury Department guidance and cover both the qualified and non-qualified plans.  2009 contributions include a

$350 million discretionary contribution.  2010 pension contributions are based on minimum regulatory requirements and additional amounts required to avoid benefit

restrictions.  Management may elect to make additional discretionary contributions.

(3)

Approximately $100 million of the 2009/2010 OPEB contributions is discretionary.Management has not yet made a decision regarding its 2010 OPEB contributions.

Contributions shown above include amounts paid out of corporate assets.

(4)

Assumes an ~20% overall capitalization rate for pension and OPEB costs.

Note: OPEB = other postretirement benefits; EROA = expected return on assets.  Data contained on this slide is rounded.

21%

5.83%

8.50%

Cash Contributions

$0

$100

$200

$300

$400

Pension

OPEB

13

Delivering on Cost Savings Commitments

Holding O&M below 2008 levels for second consecutive year

Committed to 2010 O&M target of $4.35 billion, offsetting inflation and $35 million of higher

pension and OPEB expense with additional cost savings

•

Reduced positions by 500 (400 in corporate support and 100 at ComEd) in 2009

•

Freezing executive salaries and reducing other compensation benefits for 2010

Note: Data contained on this slide is rounded.

($ millions)

$0.7

$0.6

PECO

(1)

$1.0

$1.0

ComEd

(1)

$2.7

$2.7

Generation

2010E

2009A

$ billions

(2)

(2)

(2)

O&M Expense

(1)

(1)

Reflects operating O&M data and excludes decommissioning effect. ComEd and PECO operating O&M exclude energy efficiency and smart

meter costs recoverable under a rider.

(2)

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

$4,500

$4,300

$4,350

$450

$415

$245

2008A

2009A

2010E

Total O&M

Pension/OPEB Expense

14

2010 Operating Earnings Guidance

2010E

2009A

$0.54

$3.16

$4.12

(1)

ComEd

PECO

Exelon

Generation

2010 Earnings Drivers

ComEd

PECO

Exelon

Generation

Holdco

Holdco

Exelon

$0.54

Exelon

$3.60 -

$4.00

(1)

$0.60 -

$0.70

$0.40 -

$0.50

$2.55 -

$2.80

Reaffirming

2010

operating

earnings

guidance

of

$3.60

–

$4.00/share

(1)

–

expect

1Q10

results

between

$0.85

–

$0.95/share

(1)

Depreciation and Amortization

O&M

Cost Savings Initiative

Inflation

Pension/OPEB

ComEd

RNF

PECO RNF

Generation RNF

(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.

15

Appendix

16

2010 Projected Sources and Uses of Cash

(325)

n/a

(100)

(225)

Utility Growth CapEx

(4)

($ millions)

Exelon

(9)

Beginning Cash Balance

(1)

$1,050

Cash Flow from Operations

(1)(2)

1,025

900

2,325

4,250

CapEx (excluding Nuclear Fuel, Nuclear

Uprates and Solar Project, Utility Growth

CapEx)

(625)

(400)

(750)

(1,825)

Nuclear Fuel

n/a

n/a

(850)

(850)

Dividend

(3)

(1,400)

Nuclear Uprates and Solar Project

n/a

n/a

(375)

(375)

Net Financing (excluding Dividend):

Planned Debt Issuances

(5,6)

250

--

300

550

Planned Debt Retirements

(7)

(225)

(400)

--

(1,025)

Other

(8)

25

175

--

125

Ending Cash Balance

(1)

$175

(1)

Excludes counterparty collateral activity.

(2)

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

Operations for PECO and Exelon includes $572 million for competitive transition charges. Net cash flow from operations includes $225 million of timing differences from 2009.

(3)

Assumes 2010 dividend of $2.10/share.  Dividends are subject to declaration by the Board of Directors.

(4)

Represents new business and smart grid/smart meter investment.

(5)

Excludes Exelon Generation’s $213 million and ComEd’s $191 million 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.  Assumes PECO’s A/R Agreement is extended in accordance with its terms beyond September 16, 2010.

(6)

Exelon

Generation’s

$300

million

financing

includes

a

$50

million

DOE

loan

for

the

City

Solar

Project

and

$250

million

of

debt

to

refinance

a

portion

of

Exelon

Corp’s

$400

million

maturity.

(7)

PECO’s planned debt retirement of $400 million represents the final retirement of the PECO Energy Transition Trust.

(8)

“Other”

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

(9)

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

17

Sufficient Liquidity

(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.

(45)

--

--

(45)

Outstanding Facility Draws

(447)

(171)

(10)

(261)

Outstanding Letters of Credit

$7,317

$4,834

$574

$952

Aggregate Bank Commitments

(1)

6,825

4,663

564

646

Available Capacity Under Facilities

(2)

--

--

--

--

Outstanding Commercial Paper

$6,825

$4,663

$564

$646

Available Capacity Less Outstanding

Commercial Paper

Exelon

(3)

($ millions)

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

Available Capacity Under Bank Facilities as of January 14, 2010

18

Projected 2010 Key Credit Measures

13.8x

8.1x

FFO / Interest

Generation /

Corp:

62%

34%

FFO / Debt

53%

68%

Rating Agency Debt Ratio

BBB

A-

A-

BBB-

S&P Credit

Ratings

(3)

BBB+

A

BBB

BBB+

Fitch Credit

Ratings

(3)

A3

A2

Baa1

Baa1

Moody’s Credit

Ratings

(3)

3.7x

3.8x

FFO / Interest

ComEd:

18%

14%

FFO / Debt

42%

49%

Rating Agency Debt Ratio

5.2x

5.0x

FFO / Interest

PECO:

28%

23%

FFO / Debt

46%

50%

Rating Agency Debt Ratio

29%

47%

Rating Agency Debt Ratio

87%

44%

FFO / Debt

18.6x

9.9x

FFO / Interest

Generation:

46%

37%

7.2x

Without PPA &

Pension / OPEB

(2)

57%

Rating Agency Debt Ratio

25%

FFO / Debt

6.0x

FFO / Interest

Exelon

Consolidated:

With PPA & Pension /

OPEB

(1)

Notes:

Exelon

and

PECO

metrics

exclude

securitization

debt.

See

following

slide

for

FFO

(Funds

from

Operations)/Interest,

FFO/Debt

and

Adjusted

Book

Debt

Ratio

reconciliations

to

GAAP.

(1)

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

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

obligations by operating company.

(2)

Excludes items listed in note (1) above.

(3)

Current senior unsecured ratings for Exelon and Exelon Generation and senior secured ratings for ComEd and PECO as of January 20, 2010.

19

FFO Calculation and Ratios

FFO Calculation

= FFO

-

PECO Transition Bond Principal Paydown

+ Gain

on

Sale,

Extraordinary

Items

and

Other

Non-Cash

Items

(3)

+ Change in Deferred Taxes

+ Depreciation,

Amortization

(including

nucl

fuel

amortization),

AFUDC/Cap.

Interest

Add back non-cash items:

Net Income

Adjusted Interest

FFO + Adjusted Interest

= Adjusted Interest

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

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

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

obligations,

and

Capital

Adequacy

for

Energy

Trading

(2)

,

as

applicable

-

PECO Transition Bond Interest Expense

Net Interest Expense (Before AFUDC & Cap. Interest)

FFO Interest Coverage

+ Capital

Adequacy

for

Energy

Trading

(2)

FFO

= Adjusted Debt

+ PV of Operating Leases

+ 100%

of

PV

of

Purchased

Power

Agreements

(2)

+ Unfunded

Pension

and

OPEB

obligations

(2)

+ A/R Financing

Add off-balance sheet debt equivalents:

-

PECO Transition Bond Principal Balance

+ STD

+ LTD

Debt:

Adjusted Debt

(1)

FFO Debt Coverage

Rating Agency Capitalization

Rating Agency Debt

Total Adjusted Capitalization

Adjusted Book Debt

= Total Rating Agency Capitalization

+ Off-balance

sheet

debt

equivalents

(2)

Total Adjusted Capitalization

= Rating Agency Debt

+ ComEd Transition Bond Principal Balance

+ Off-balance

sheet

debt

equivalents

(2)

Adjusted Book Debt

= Total Adjusted Capitalization

+ Adjusted Book Debt

+ Preferred Securities of Subsidiaries

+ Total Shareholders' Equity

Capitalization:

= Adjusted Book Debt

-

Transition Bond Principal Balance

+ STD

+ LTD

Debt:

Debt to Total Cap

(1)

Uses current year-end adjusted debt balance.

(2)

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

Adequacy for Energy Trading.

(3)

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

20

Q4 GAAP EPS Reconciliation

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

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

0.03

-

-

-

0.03

Settlement of tax matter at Generation related to Sithe

(0.02)

-

-

(0.02)

-

City of Chicago settlement with ComEd

(0.02)

(0.02)

-

-

-

NRG acquisition costs

$1.07

$(0.03)

$0.12

$0.14

$0.84

4Q 2008 GAAP Earnings (Loss) Per Share

$1.07

$(0.01)

$0.12

$0.16

$0.80

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

(0.04)

-

-

-

(0.04)

2007 Illinois electric rate settlement

0.15

-

-

-

0.15

Mark-to-market adjustments from economic hedging activities

(0.10)

-

-

-

(0.10)

Unrealized losses related

to nuclear decommissioning trust funds

Exelon

Other

PECO

ComEd

ExGen

Three Months Ended December 31, 2008

21

YTD GAAP EPS Reconciliation

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

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

(0.02)

-

-

(0.02)

-

City of Chicago settlement with ComEd

(0.02)

(0.02)

-

-

-

NRG acquisition costs

0.03

-

-

-

0.03

Settlement of tax matter at Generation related to Sithe

0.02

-

-

-

0.02

Decommissioning obligation reduction

$4.13

$(0.10)

$0.49

$0.30

$3.44

YTD 2008 GAAP Earnings (Loss) Per Share

$4.20

$(0.08)

$0.49

$0.33

$3.46

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

(0.22)

-

-

(0.01)

(0.21)

2007 Illinois electric

rate

settlement

0.41

-

-

-

0.41

Mark-to-market adjustments from economic hedging activities

(0.27)

-

-

-

(0.27)

Unrealized losses related

to nuclear decommissioning trust funds

Exelon

Other

PECO

ComEd

ExGen

Twelve Months Ended December 31, 2008

22

Exelon Generation 2010 EPS Contribution

(1) 

Estimated contribution to Exelon’s operating earnings guidance.

$ / Share

$(0.32)

$0.06

RNF

O&M

Other

Depreciation &

Amortization

$(0.09)

Key Items:

Inflation                                      $(0.05)

Pension/OPEB                         $(0.03)

Cost Savings Initiative              $0.11

2009A

2010E

(1)

$2.55 -

$2.80

$3.16

Key Items:

Market/Portfolio

Conditions/Generation      $(0.29)

Nuclear Fuel Expense       $(0.12)

PECO CTC                       

$(0.11)

Capacity Market Prices       $0.19

$(0.01)

$(0.04)

Interest

Expense

23

ComEd 2010 EPS Contribution

(1)

Estimated contribution to Exelon’s operating earnings guidance.

(2)

Excludes estimated impact of Rider EDA (Energy Efficiency and Demand Response Adjustment) of $0.05/share and Rider AMI (Advanced Metering Infrastructure) of $0.01/share in 2010.

(3)

Primarily recovery of 2008 and 2009 uncollectible expense.  Approximately $0.06/share we anticipate will be included in 1Q10 earnings.

2009A

Depreciation &

Amortization

Interest

Expense

$0.60 -

$0.70

$0.54

$0.15

$0.04

$(0.02)

2010E

(1)

$ / Share

$(0.02)

$(0.03)

Other

RNF

(2)

O&M

(2)

Key Items:

Uncollectible Rider

(3)

$0.05

Weather                              $0.04

Key Items:

Cost Savings Initiative              $0.05

Bad Debt

(3)

$0.05

Inflation                                     $(0.02)

Pension/OPEB                          $(0.01)

24

PECO 2010 EPS Contribution

$ / Share

RNF

$(0.12)

$0.54

(1)

Depreciation &

Amortization

2010E

(2)

Key Items:

CTC                          $0.11

Weather                    $0.04

Load                         $(0.03) 

Key Items:

Inflation                            $(0.02)

Bad Debt                         $(0.02)

$0.08

O&M

(3)

$0.04

$0.40 -

$0.50

(1)

Key Items:

CTC Amortization  $(0.11)

Interest

$(0.09)

Key Items:

CTC Interest Expense    $0.06

2009A

(1)

Excludes preferred dividends.

(2)

Estimated contribution to Exelon’s operating earnings guidance.

(3)

Excludes estimated impact of energy efficiency and smart meter costs recoverable under a rider of $0.10/share.

25

25

Key Assumptions for 2010

Earnings Guidance

(1)

2008 Actual

2009 Actual

2010 Est.

Nuclear

Capacity

Factor

(%)

(2)

93.9

93.6

93.5

Total Generation Sales Excluding Trading (GWh)

176,174

173,065

171,400

Total Generation Sales to PECO (GWh)

40,966

39,897

39,900

Total

Generation

Market

and

Retail

Sales

(GWh)

(3)

135,208

133,168

131,500

Henry Hub Gas Price ($/mmBtu)

8.85

3.92

6.21

PJM West Hub ATC Price ($/MWh)

68.52

38.30

48.40

Tetco M3 Gas Price ($/mmBtu)

9.83

4.64

6.95

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

6.97

8.25

6.96

NI Hub ATC Price ($/MWh)

49.00

28.85

32.57

Chicago City Gate Gas Price ($/mmBtu)

8.79

3.92

6.23

NI Hub Implied ATC Heat Rate (mmbtu/MWh)

5.57

7.36

5.22

PJM East Capacity Price ($/MW-day)

169.09

173.73

181.34

PJM West Capacity Price ($/MW-day)

82.39

106.13

144.40

Electric

Delivery

Growth

(%)

(4)

PECO

0.6

(2.6)

(1.3)

ComEd

(0.1)

(3.3)

0.8

Effective Tax Rate (%)

(5)

36.1

37.2

35.8

(1)

Reflects assumptions used in original 2010 Earnings Guidance provided on November 2, 2009; 2010 prices reflect observable prices as of September 30, 2009.

(2)

Excludes Salem.

.

(3)

Includes Illinois auction sales and ComEd swap.

(4)

Weather-normalized retail load growth.

(5)

Starting on January 1, 2011, effective tax rate is expected to increase to 37.1% due to lower tax benefit related to the PECO PPA roll off.

26

4Q07

4Q08

4Q09

ComEd and PECO Accounts Receivable

ComEd Accounts

Receivable

(1)

Both ComEd and PECO have experienced an improvement in accounts receivable aging

4Q07

4Q08

4Q09

PECO Accounts

Receivable

(1)

% of AR

$755M

$749M

$850M

$832M

$864M

$759M

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

>60 days

31-60 days

0-30 days

27

ComEd Customer Usage Breakdown

Customer Usage by Revenue Class

Top 380 Customer Usage by Segment

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

ComEd’s

territory

is

largely

manufacturing

focused,

which

is

beginning

to

see

increases

in

production due to improved economic conditions

28

PECO Customer Usage Breakdown

Other

3%

Other Large

C&I

24%

150 Large

C&I

17%

Small C&I

22%

Residential

34%

Customer Usage by Revenue Class

Top 150 Customer Usage by Segment

7%

Other

13%

Transportation, Communication &

Utilities

18%

Health & Educational Services

18%

Manufacturing

22%

Petroleum

2%

Retail Trade

9%

Finance, Insurance & Real Estate

12%

Pharmaceuticals

PECO’s

load

is

relatively

diversified

by

customer

class

and

industry,

a

slow

recovery

in

the

second half of 2010 is expected

29

2010 Earnings Outlook

•

Exelon’s 2010 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

•

Significant impairments of assets, including goodwill

•

Changes in decommissioning obligation estimates

•

Costs

associated

with

the

2007

Illinois

electric

rate

settlement

agreement

•

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

•

Costs associated with the retirement of fossil generating units

•

Other

unusual

items

•

Significant future changes to GAAP

•

Operating earnings guidance assumes normal weather for the

year

30

30

Important Information

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

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

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

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

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

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

control.  The information on the following slides is as of December 31, 2009. Going forward, we

plan to update the 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.

31

31

Portfolio Management Objective

Align Hedging Activities with Financial Commitments

•

Power Team utilizes several product

types and channels to market

•

Wholesale and retail sales

•

Block products

•

Load-following products

and load auctions

•

Put/call options

•

Exelon’s hedging program is designed to

protect the long-term value of our

generating fleet and maintain an

investment-grade balance sheet

•

Hedge enough commodity risk to meet future cash

requirements if prices drop

•

Consider:

financing

policy

(credit

rating

objectives,

capital structure, liquidity); spending (capital and

O&M); shareholder value return policy

•

Consider market, credit, operational risk

•

Approach to managing volatility

•

Increase hedging as delivery approaches

•

Have enough supply to meet peak load

•

Purchase fossil fuels as power is sold

•

Choose hedging products based on generation

portfolio

–

sell

what

we

own

•

Heat rate options

•

Fuel products

•

Capacity

•

Renewable credits

% Hedged

High End of Profit

Low End of Profit

Open Generation

with LT Contracts

Portfolio

Optimization

Portfolio

Management

Portfolio Management Over Time

32

32

32

Percentage of Expected

Generation Hedged

•

How many equivalent MW have been

hedged at forward market prices;  all hedge

products used are converted to an

equivalent average MW volume

•

Takes ALL

hedges into account whether

they are power sales or financial products

Equivalent MWs Sold

Expected Generation

=

•

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

over the three years leading to the spot market

•

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

risks

•

By

using

the

appropriate

product

mix,

expected

generation

hedged

approaches

the

mid-90s percentile as the delivery period approaches

•

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

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

quarter to quarter

Exelon Generation Hedging Program

33

33

33

2010

2011

2012

Estimated

Open

Gross

Margin

($

millions)

(1,2)

$5,900

$5,800

$5,750

Open gross margin assumes all expected generation is

sold at the Reference Prices listed below

Reference Prices

(1)

Henry Hub Natural Gas ($/MMBtu)

NI-Hub ATC Energy Price ($/MWh)

PJM-W ATC Energy Price ($/MWh)    

ERCOT North ATC Spark Spread ($/MWh)

(3)

$5.79

$33.83

$48.04

$(0.53)

$6.33

$34.75

$49.42

$(0.44)

$6.53

$36.13

$50.43

$0.89

Exelon Generation Open Gross Margin and

Reference Prices

(1)

Based on December 31, 2009 market conditions.  

(2)

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

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

margin assumes there 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)

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

34

34

34

2010

2011

2012

Expected Generation

(GWh)

(1)

167,100

163,000

162,600

Midwest

99,000

98,400

97,400

Mid-Atlantic

59,600

57,200

56,600

South

8,500

7,400

8,600

Percentage of Expected Generation Hedged

(2)

91-94%

69-72%

37-40%

Midwest

89-92

71-74

43-46

Mid-Atlantic

93-96

65-68

25-28

South

97-100

66-69

39-42

Effective Realized Energy Price

($/MWh)

(3)

Midwest

$46.50

$45.00

$46.00

Mid-Atlantic

$35.50

$60.00

$53.50

ERCOT North ATC Spark Spread

$(1.00)

$(0.50)

$(7.00)

Generation Profile

(1)

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

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

and options.  Expected generation assumes 10 refueling outages in 2010 and 11 refueling outages in 2011 and 2012 at Exelon-operated nuclear plants and Salem. 

Expected generation assumes capacity factors of 93.5%, 92.8% and 92.8% in 2010, 2011 and 2012 at Exelon-operated nuclear plants. These estimates of expected

generation in 2011 and 2012 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,

pending PJM approval.

(3)

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

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

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

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

35

35

35

Gross Margin Sensitivities with Existing Hedges ($ millions)

(1)

Henry Hub Natural Gas

+ $1/MMBtu

-

$1/MMBtu

NI-Hub ATC Energy Price

+$5/MWH

-$5/MWH

PJM-W ATC Energy Price

+$5/MWH

-$5/MWH

Nuclear Capacity Factor

+1% / -1%

2010

$40

$(40)

$30

$(25)

$20

$(15)

+/-

$50

2011

$190

$(160)

$165

$(155)

$135

$(130)

+/-

$50

2012

$395

$(395)

$275

$(270)

$230

$(230)

+/-

$50

Exelon Generation Gross Margin Sensitivities

(with Existing Hedges)

(1) 

Based on December 31, 2009 market conditions and hedged position. Gas price sensitivities are based on an assumed gas-power relationship derived from an

internal model that is updated periodically. Power prices sensitivities are derived by adjusting the power price assumption while keeping all other prices inputs

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

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

36

36

36

95% case

5% case

$6,500

$6,100

$4,800

$7,800

$6,200

$8,000

Exelon Generation Gross Margin Upside / Risk

(with Existing Hedges)

$3,000

$4,000

$5,000

$6,000

$7,000

$8,000

$9,000

2010

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 2011 and 2012 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, 2009.

37

37

37

Midwest

Mid-Atlantic

ERCOT

Step 1

Start

with

fleetwide

open

gross

margin 

$5.90 billion

Step 2

Determine the mark-to-market value

of energy hedges

99,000GWh * 90% *

($46.50/MWh-$33.83/MWh)

= $1.13 billion

59,600GWh * 94% *

($35.50/MWh-$48.04/MWh)

= $(0.70 billion)

8,500GWh * 98% *

($(1.00)/MWh-

$(0.53)/MWh)

= $0.00 billion

Step 3

Estimate

hedged

gross

margin

by

adding open gross margin to mark-to-

market value of energy hedges

Open gross margin:

MTM value of energy hedges:

Estimated hedged gross margin:

Illustrative Example

of Modeling Exelon Generation 2010 Gross Margin

(with Existing Hedges)

$1.13

billion

+

$(0.70

billion)

+

$0.00

billion

$5.90 billion

$6.33 billion

38

38

38

38

38

50

55

60

65

70

75

80

85

90

1/09

2/09

3/09

4/09

5/09

6/09

7/09

8/09

9/09

10/09

11/09

12/09

1/10

20

25

30

35

40

45

50

55

1/09

2/09

3/09

4/09

5/09

6/09

7/09

8/09

9/09

10/09

11/09

12/09

1/10

35

40

45

50

55

60

65

70

75

80

85

1/09

2/09

3/09

4/09

5/09

6/09

7/09

8/09

9/09

10/09

11/09

12/09

1/10

5

5.5

6

6.5

7

7.5

8

8.5

9

1/09

2/09

3/09

4/09

5/09

6/09

7/09

8/09

9/09

10/09

11/09

12/09

1/10

38

Market Price Snapshot

Forward NYMEX Natural Gas

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

PJM-West and Ni-Hub Wrap Forward Prices

2011

$6.41

2012  $6.54

Rolling 12 months, as of January 14, 2010. Source: OTC quotes and electronic trading system. Quotes are daily.

Forward NYMEX Coal

2011

$68.00

2012

$75.45

2011

Ni-Hub

$44.27

2012 Ni-Hub

$44.58

2012 PJM-West  $59.90

2011 PJM-West

$59.57

2011 Ni-Hub

$25.95

2012 Ni-Hub

$27.87

2012 PJM-West

$41.99

2011 PJM-West

$41.17

39

39

39

39

39

5.5

6.5

7.5

8.5

9.5

10.5

11.5

12.5

13.5

1/09

2/09

3/09

4/09

5/09

6/09

7/09

8/09

9/09

10/09

11/09

12/09

1/10

8

8.2

8.4

8.6

8.8

9

9.2

9.4

9.6

9.8

10

1/09

2/09

3/09

4/09

5/09

6/09

7/09

8/09

9/09

10/09

11/09

12/09

1/10

40

45

50

55

60

65

70

75

80

1/09

2/09

3/09

4/09

5/09

6/09

7/09

8/09

9/09

10/09

11/09

12/09

1/10

5

5.5

6

6.5

7

7.5

8

8.5

9

1/09

2/09

3/09

4/09

5/09

6/09

7/09

8/09

9/09

10/09

11/09

12/09

1/10

39

Market Price Snapshot

2012

$9.10

2011

$8.73

2011

$54.83

2012

$58.40

2011

$6.28

2012

$6.43

Houston Ship Channel Natural Gas

Forward Prices

ERCOT North On-Peak Forward Prices

ERCOT North On-Peak v. Houston Ship Channel

Implied Heat Rate

2011

$7.02

2012

$9.64

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 14, 2010. Source: OTC quotes and electronic trading system. Quotes are daily.