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Form 8-K

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, DC 20549

FORM 8-K

CURRENT REPORT

Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

April 23, 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 April 23, 2010, Exelon Corporation (Exelon) announced via press release its results for the first quarter ended March 31, 2010. A copy of the press release and related attachments is attached hereto as Exhibit 99.1. Also attached as Exhibit 99.2 to this Current Report on Form 8-K are the presentation slides to be used at the first quarter 2010 earnings conference call. This Form 8-K and the attached exhibits are provided under Items 2.02, 7.01 and 9.01 of Form 8-K and are furnished to, but not filed with, the Securities and Exchange Commission.

Exelon has scheduled the conference call for 11:00 AM ET (10:00 AM CT) on April 23, 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 66924279. Media representatives are invited to participate on a listen-only basis. The call will be web-cast and archived on Exelon’s Web site: www.exeloncorp.com. (Please select the Investors page.)

Telephone replays will be available until May 7. 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 66924279.

Section 9 – Financial Statements and Exhibits

Item 9.01.

Financial Statements and Exhibits.

(d)	Exhibits.


Exhibit No.		Description
99.1		Press release and earnings release attachments

99.2		Earnings conference call presentation slides

* * * * *

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

This Current Report includes forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995 that are subject to risks and uncertainties. The factors that could cause actual results to differ materially from these forward-looking statements include those discussed herein as well as those discussed in (1) Exelon’s 2009 Annual Report on Form 10-K in (a) ITEM 1A. Risk Factors, (b) ITEM 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations and (c) ITEM 8. Financial Statements and Supplementary Data: Note 18; (2) Exelon’s First Quarter 2010 Quarterly Report on Form 10-Q (to be filed on April 23, 2010) in (a) Part II, Other Information, ITEM 1A. Risk Factors and (b) Part I, Financial Information, ITEM 1. Financial Statements: Note 12; 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

April 23, 2010

EXHIBIT INDEX


Exhibit No.		Description
99.1		Press release and earnings release attachments

99.2		Earnings conference call presentation slides

Press release and earnings release attachments

EXHIBIT 99.1

LOGO


Contact:	Stacie Frank	FOR IMMEDIATE RELEASE
	Investor Relations
	312-394-3094

	Judy Rader
	Corporate Communications
	312-394-7417

Exelon Announces First Quarter Results;

Raises Bottom End of Guidance Range for Full Year 2010 Earnings

CHICAGO (April 23, 2010) – Exelon Corporation (Exelon) announced first quarter 2010 consolidated earnings as follows:


	First Quarter
	2010		2009
Adjusted (non-GAAP) Operating Results:
Net Income ($ millions)	$	662	$	797
Diluted Earnings per Share	$	1.00	$	1.20
GAAP Results:
Net Income ($ millions)	$	749	$	712
Diluted Earnings per Share	$	1.13	$	1.08

“We again delivered on our financial and operating commitments with first quarter earnings topping our guidance range of $0.85 to $0.95 per share,” said John W. Rowe, Exelon’s chairman and CEO. “We continue to manage the factors in our control, such as our focus on strong operations, which resulted in our Generation company achieving a 92.3% nuclear capacity factor in the first quarter, even with five planned refueling outages, and our utilities ComEd and PECO attaining exceptional performance during adverse winter weather conditions. Expecting to sustain this performance and make further progress on cost management and reflecting market conditions and load slightly favorable to our previous forecast, we are raising the bottom end of our 2010 earnings per share guidance range from $3.60 to $3.70 and keeping the top end at $4.00.”

First Quarter Operating Results

The decrease in first quarter 2010 adjusted (non-GAAP) operating earnings to $1.00 per share from $1.20 per share in first quarter 2009 was primarily due to:

•

Lower energy gross margins at Exelon Generation Company, LLC (Generation) largely reflecting unfavorable market and portfolio conditions and lower nuclear output due to increased scheduled refueling outage days;

•

Increased planned nuclear outage costs due to the increased scheduled refueling outage days;

•

The benefit recognized in the first quarter of 2009 related to an Illinois Supreme Court tax ruling, which was subsequently reversed in the third quarter of 2009; and

•

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

Lower first quarter 2010 earnings were partially offset by:

•

Decreased operating and maintenance expense largely due to recovery of prior year uncollectible accounts expense at Commonwealth Edison Company (ComEd) and savings achieved through the ongoing cost management initiative.

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


	(in millions)			(per diluted share)
Mark-to-market gains primarily from Generation’s economic hedging activities	$	142		$	0.21
Non-cash charge resulting from health care legislation related to Federal income tax changes	$	(65	)	$	(0.10	)
Unrealized gains related to nuclear decommissioning trust (NDT) fund investments to the extent not offset by contractual accounting	$	20		$	0.03
Costs associated with the retirement of certain Generation fossil generating units	$	(8	)	$	(0.01	)
Costs associated with the 2007 Illinois electric rate settlement agreement	$	(2	)		—

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


	(in millions)			(per diluted share)
Charge related to impairments of certain Texas plants at Generation	$	(135	)	$	(0.20	)
Mark-to-market gains primarily from Generation’s economic hedging activities	$	112		$	0.17
Unrealized losses related to NDT fund investments to the extent not offset by contractual accounting	$	(33	)	$	(0.05	)
Costs associated with the 2007 Illinois electric rate settlement agreement	$	(21	)	$	(0.03	)
External costs related to Exelon’s proposed acquisition of NRG Energy, Inc.	$	(8	)	$	(0.01	)

2010 Earnings Outlook

Exelon narrowed its guidance range for 2010 adjusted (non-GAAP) operating earnings from $3.60 to $4.00 per share to $3.70 to $4.00 per share. Operating earnings guidance is based on the assumption of normal weather for the balance of the year.

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

•

Significant impairments of assets, including goodwill

•

Changes in decommissioning obligation estimates

•

Costs associated with 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

•

Non-cash charge resulting from the passage of Federal health care legislation

•

Other unusual items

•

Significant future changes to GAAP

First Quarter and Recent Highlights

•

Nuclear Operations: Generation’s nuclear fleet, including its owned output from the Salem Generating Station, produced 34,109 gigawatt-hours (GWh) in the first quarter of 2010, compared with 35,382 GWh in the first quarter of 2009. The Exelon-operated nuclear plants achieved a 92.3 percent capacity factor for the first quarter of 2010 compared with 96.2 percent for the first quarter of 2009. The Exelon-operated nuclear plants completed three scheduled refueling outages and began two others in the first quarter of 2010, compared with completing one and beginning two other scheduled refueling outages in the first quarter of 2009. The number of refueling outage days totaled 101 in the first quarter of 2010 versus 34 days in the first quarter of 2009. Among the planned outages completed in this year’s first quarter was the extended refueling outage at Three Mile Island Unit 1, which included the replacement of steam generators. The number of non-refueling outage days at the Exelon-operated plants totaled 5 days in the first quarter of 2010 compared with 13 days in the first quarter of 2009.

•

Fossil and Hydro Operations: The equivalent demand forced outage rate for Generation’s fossil fleet was 3.8 percent in the first quarter of 2010, down from 5.7 percent in the first quarter of 2009. This favorable change was largely attributable to forced outages at Eddystone and Schuylkill in the first quarter of 2009. The equivalent availability factor for the hydroelectric facilities was 95.4 percent in the first quarter of 2010, compared with 94.4 percent in the first quarter of 2009, largely due to an earlier than planned outage in March 2009 at Muddy Run.

•

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 March 31, 2010 is 95 to 98 percent for 2010, 79 to 82 percent for 2011 and 48 to 51 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.

•

Illinois Uncollectibles Recovery Rider: In July 2009, comprehensive legislation was enacted into law in Illinois that provides public utility companies the ability to bill or refund customers for the difference between the company’s annual uncollectible accounts expense and amounts collected in rates through a rider mechanism, beginning with 2008 and prospectively. ComEd under-collected approximately $26 million during 2008 and approximately $44 million during 2009. On February 2, 2010, the Illinois Commerce Commission (ICC) issued an order approving ComEd’s proposed tariffs for collecting the increases or decreases in uncollectible accounts expense, with minor modifications. With the ICC’s approval of the tariff, ComEd began collecting past due amounts this month. ComEd recorded the $70 million benefit related to 2008 and 2009 in the first quarter of 2010. As required by the legislation, ComEd also made a one-time contribution of approximately $10 million in the first quarter of 2010 to the Supplemental Low-Income Energy Assistance Fund to assist low-income residential customers.

•

ComEd Credit Facility: On March 25, 2010, ComEd closed on a $1 billion unsecured revolving credit facility that has an initial term expiring on March 25, 2013. ComEd may request up to two one-year extensions of this term. The facility is available for general corporate purposes and letters of credit. A total of 22 banks have commitments in the facility with no one bank having exposure of more than 6 percent of the total. The facility replaces a $952 million revolving credit facility that was due to expire on February 16, 2011.

•

ComEd Credit Rating Upgrade: On January 25, 2010, Fitch Ratings, Ltd. (Fitch) upgraded ComEd’s senior secured debt rating to “BBB+” from “BBB” and its commercial paper rating to “F3” from “B”. The Fitch rating outlook for all the Exelon companies is stable.

•

PECO Electric and Gas Delivery Rate Cases: On March 31, 2010, PECO filed proposals with the Pennsylvania Public Utility Commission (PAPUC) seeking approvals to increase its annual electric and natural gas delivery revenues by $316 million and $44 million, respectively, beginning January 1, 2011. The first electric delivery rate request since 1989 and only the second natural gas delivery rate request in 23 years, the increases will enable PECO to continue to meet customer demand and ensure the safe and reliable delivery of electricity and natural gas. The delivery charge, or the portion of the bill that covers PECO’s costs to deliver electricity and natural gas, represents about one-third of a customer’s overall bill, and is expected to increase 6.94% and 5.28%, respectively, as a percentage of the overall bill.

•

PECO Smart Meter/Smart Grid Program: Effective April 12, 2010, PECO entered into a Financial Assistance Agreement with the U.S. Department of Energy (DOE) for Smart Grid Investment Grant (SGIG) funds under the American Recovery and Reinvestment Act of 2009. Under the SGIG, PECO has been awarded $200 million, the maximum allowable grant under the program, for its SGIG project – Smart Future Greater Philadelphia. The SGIG project has a budget of approximately $436 million and includes demonstration projects by two sub-recipients,

Drexel University and Liberty Property Trust. As a result of SGIG funding, PECO will deploy 600,000 smart meters within three years and accelerate universal deployment of more than 1.6 million smart meters to 10 years from 15 years. The SGIG grant is considered non-taxable based on recent IRS guidance. In total, over the next ten years, PECO is planning to spend up to $650 million on its smart grid and smart meter infrastructure. The $200 million SGIG from the DOE will be used to significantly reduce the impact of those investments on PECO ratepayers. On April 22, 2010, the PAPUC approved PECO’s Smart Meter Procurement and Installation Plan.

OPERATING COMPANY RESULTS

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

First quarter 2010 net income was $561 million compared with $528 million in the first quarter of 2009. First quarter 2010 net income included (all after-tax) mark-to-market gains of $142 million from economic hedging activities before the elimination of intercompany transactions, unrealized gains of $20 million related to NDT fund investments, a charge of $26 million related to the passage of Federal health care legislation, costs of $8 million associated with the retirement of certain fossil generating units and a charge of $1 million for costs associated with the 2007 Illinois electric rate settlement. First quarter 2009 net income included (all after tax) mark-to-market gains of $112 million from economic hedging activities before the elimination of intercompany transactions, a charge of $135 million associated with the impairment of certain Texas plants (Handley and Mountain Creek), unrealized losses of $33 million related to NDT fund investments and a charge of $21 million for the costs associated with the 2007 Illinois electric rate settlement. Excluding the impact of these items, Generation’s net income in the first quarter of 2010 decreased $171 million compared with the same quarter last year primarily due to:

•

Lower energy gross margins, largely due to unfavorable market and portfolio conditions, lower pricing from PECO under the power purchase agreement, decreased nuclear output as a result of a higher number of scheduled refueling outage days and higher nuclear fuel costs; and

•

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

Generation’s average realized margin on all electric sales, including sales to affiliates and excluding trading activity, was $37.26 per MWh in the first quarter of 2010 compared with $39.25 per MWh in the first quarter of 2009.

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

ComEd recorded net income of $116 million in the first quarter of 2010, compared with net income of $114 million in the first quarter of 2009. First quarter net income in 2010 included after-tax charges of $12 million related to the passage of Federal health care legislation and $1 million associated with the 2007 Illinois electric rate settlement. Excluding the impact of these items, ComEd’s net income in the first quarter of 2010 was up $15 million from the same quarter last year reflecting:

•

Recovery of 2008 and 2009 under-collection of annual uncollectible accounts expense due to the approval by the ICC of ComEd’s rider mechanism; and

•

Lower operating and maintenance expense, primarily due to Exelon’s ongoing cost management initiative.

The increase in net income was partially offset by:

•

The benefit recognized in the first quarter of 2009 related to an Illinois Supreme Court tax ruling, which was subsequently reversed in the third quarter of 2009.

In the first quarter of 2010, heating degree-days in the ComEd service territory were down 6.3 percent relative to the same period in 2009 and were 3.1 percent below normal. ComEd’s total retail electric deliveries decreased by 1.9 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.

Weather-normalized retail electric deliveries decreased by 0.8 percent from the first quarter of 2009. For ComEd, weather had an unfavorable after-tax impact of $3 million on first quarter 2010 earnings relative to 2009 and an unfavorable after-tax impact of $1 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 first quarter of 2010 was $101 million, down from $113 million in the first quarter of 2009. First quarter net income in 2010 included an after-tax charge of $10 million related to the passage of Federal health care legislation. Excluding the impact of these items, PECO’s net income in the first quarter of 2010 was down $2 million from the same quarter last year reflecting:

•

Higher CTC amortization, which was in accordance with PECO’s 1998 restructuring settlement with the PAPUC; and

•

Increased storm costs.

The decrease in net income was partially offset by:

•

Lower energy prices under the power purchase agreement with Generation due to increased CTC revenue to ensure full recovery of stranded costs during 2010, the final year of the transition period, which resulted from lower than expected sales volume in 2009.

In the first quarter of 2010, heating degree-days in the PECO service territory were down 4.9 percent from 2009 and were 3.9 percent below normal. Total retail electric deliveries were down 0.5 percent from last year, reflecting a decline in deliveries across all customer classes, primarily driven by the impact of unfavorable weather conditions. On the retail gas side, deliveries in the first quarter of 2010 were down 3.6 percent from the first quarter of 2009.

Weather-normalized retail electric deliveries increased by 0.5 percent from the first quarter of 2009, primarily reflecting increased residential deliveries. For PECO, weather had an unfavorable after-tax impact of $7 million on first quarter 2010 earnings relative to 2009 and an unfavorable after-tax impact of $8 million relative to normal weather that was incorporated in earnings guidance.

Adjusted (non-GAAP) Operating Earnings

Adjusted (non-GAAP) operating earnings, which generally exclude significant one-time charges or credits that are not normally associated with ongoing operations, mark-to-market adjustments from economic hedging activities and unrealized gains and losses from NDT fund investments, are provided as a supplement to results reported in accordance with GAAP. Management uses such adjusted (non-GAAP) operating earnings measures internally to evaluate the company’s performance and manage its operations. Reconciliation of GAAP to adjusted (non-GAAP) operating earnings for historical periods is attached. Additional earnings release attachments, which include the reconciliation on page 6, are posted on Exelon’s Web site: www.exeloncorp.com and have been furnished to the Securities and Exchange Commission on Form 8-K on April 23, 2010.

Conference call information: Exelon has scheduled a conference call for 11:00 AM ET (10:00 AM CT) on April 23, 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 66924279. Media representatives are invited to participate on a listen-only basis. The call will be web-cast and archived on Exelon’s Web site: www.exeloncorp.com. (Please select the Investors page.)

Forward Looking Statements

This press release includes forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995, that are subject to risks and uncertainties. The factors that could cause actual results to differ materially from these forward-looking statements include those discussed herein as well as those discussed in (1) Exelon’s 2009 Annual Report on Form 10-K in (a) ITEM 1A. Risk Factors, (b) ITEM 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations and (c) ITEM 8. Financial Statements and Supplementary Data: Note 18; (2) Exelon’s First Quarter 2010 Quarterly Report on Form 10-Q (to be filed on April 23, 2010) in (a) Part II, Other Information, ITEM 1A. Risk Factors and (b) Part I, Financial Information, ITEM 1. Financial Statements: Note 12 and (3) other factors discussed in filings with the Securities and Exchange Commission (SEC) by Exelon Corporation, Commonwealth Edison Company, PECO Energy Company and Exelon Generation Company, LLC (Companies). Readers are cautioned not to place undue reliance on these forward-looking statements, which apply only as of the date of this press release. None of the Companies undertakes any obligation to publicly release any revision to its forward-looking statements to reflect events or circumstances after the date of this press release.

###

Exelon Corporation is one of the nation’s largest electric utilities with approximately $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 northern Illinois and southeastern Pennsylvania and natural gas to approximately 486,000 customers in the Philadelphia area. Exelon is headquartered in Chicago and trades on the NYSE under the ticker EXC.

EXELON CORPORATION

Earnings Release Attachments

Table of Contents


Consolidating Statements of Operations - Three Months Ended March 31, 2010 and 2009		1

Business Segment Comparative Statements of Operations - Generation and ComEd - Three Months Ended March 31, 2010 and 2009		2

Business Segment Comparative Statements of Operations - PECO and Other - Three Months Ended March 31, 2010 and 2009		3

Consolidated Balance Sheets - March 31, 2010 and December 31, 2009		4

Consolidated Statements of Cash Flows - Three Months Ended March 31, 2010 and 2009		5

Reconciliation of Adjusted (non-GAAP) Operating Earnings to GAAP Consolidated Statements of Operations - Exelon - Three Months Ended March 31, 2010 and 2009		6

Reconciliation of Adjusted (non-GAAP) Operating Earnings to GAAP Earnings By Business Segment - Three Months Ended March 31, 2010 and 2009		7

Reconciliation of Adjusted (non-GAAP) Operating Earnings to GAAP Consolidated Statements of Operations - Generation - Three Months Ended March 31, 2010 and 2009		8

Reconciliation of Adjusted (non-GAAP) Operating Earnings to GAAP Consolidated Statements of Operations - ComEd - Three Months Ended March 31, 2010 and 2009		9

Reconciliation of Adjusted (non-GAAP) Operating Earnings to GAAP Consolidated Statements of Operations - PECO - Three Months Ended March 31, 2010 and 2009		10

Reconciliation of Adjusted (non-GAAP) Operating Earnings to GAAP Consolidated Statements of Operations - Other - Three Months Ended March 31, 2010 and 2009		11

Exelon Generation Statistics - Three Months Ended March 31, 2010, December 31, 2009, September 30, 2009, June 30, 2009 and March 31, 2009		12

ComEd Statistics - Three Months Ended March 31, 2010 and 2009		13

PECO Statistics - Three Months Ended March 31, 2010 and 2009		14

EXELON CORPORATION

Consolidating Statements of Operations

(unaudited)

(in millions)


	Three Months Ended March 31, 2010
	Generation			ComEd			PECO			Other			Exelon Consolidated
Operating revenues	$	2,421		$	1,415		$	1,455		$	(830	)	$	4,461

Operating expenses
Purchased power		208			753			524			(827	)		658
Fuel		391			—			211			(1	)		601
Operating and maintenance		740			159			181			(18	)		1,062
Operating and maintenance for regulatory required programs (a)		—			19			8			—			27
Depreciation and amortization		109			130			265			10			514
Taxes other than income		57			63			72			5			197


Total operating expenses		1,505			1,124			1,261			(831	)		3,059


Operating income		916			291			194			1			1,402


Other income and deductions
Interest expense, net		(35	)		(84	)		(45	)		(19	)		(183	)
Other, net		79			3			4			7			93


Total other income and deductions		44			(81	)		(41	)		(12	)		(90	)


Income (loss) before income taxes		960			210			153			(11	)		1,312

Income taxes		399			94			52			18			563


Net income (loss)	$	561		$	116		$	101		$	(29	)	$	749


	Three Months Ended March 31, 2009
	Generation			ComEd			PECO			Other			Exelon Consolidated
Operating revenues	$	2,601		$	1,553		$	1,514		$	(946	)	$	4,722

Operating expenses
Purchased power		175			882			570			(944	)		683
Fuel		510			—			266			—			776
Operating and maintenance		928			253			177			3			1,361
Operating and maintenance for regulatory required programs (a)		—			11			—			—			11
Depreciation and amortization		76			123			225			12			436
Taxes other than income		50			78			66			6			200


Total operating expenses		1,739			1,347			1,304			(923	)		3,467


Operating income (loss)		862			206			210			(23	)		1,255


Other income and deductions
Interest expense, net		(29	)		(83	)		(50	)		(25	)		(187	)
Loss in equity method investments		(1	)		—			(7	)		—			(8	)
Other, net		(82	)		32			5			8			(37	)


Total other income and deductions		(112	)		(51	)		(52	)		(17	)		(232	)


Income (loss) before income taxes		750			155			158			(40	)		1,023

Income taxes		222			41			45			3			311


Net income (loss)	$	528		$	114		$	113		$	(43	)	$	712

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

EXELON CORPORATION

Business Segment Comparative Statements of Operations

(unaudited)

(in millions)


	Generation

	Three Months Ended March 31,
	2010			2009			Variance
Operating revenues	$	2,421		$	2,601		$	(180	)

Operating expenses
Purchased power		208			175			33
Fuel		391			510			(119	)
Operating and maintenance		740			928			(188	)
Depreciation and amortization		109			76			33
Taxes other than income		57			50			7


Total operating expenses		1,505			1,739			(234	)


Operating income		916			862			54


Other income and deductions
Interest expense, net		(35	)		(29	)		(6	)
Loss in equity method investments		—			(1	)		1
Other, net		79			(82	)		161


Total other income and deductions		44			(112	)		156


Income before income taxes		960			750			210

Income taxes		399			222			177


Net income	$	561		$	528		$	33


	ComEd

	Three Months Ended March 31,
	2010			2009			Variance
Operating revenues	$	1,415		$	1,553		$	(138	)

Operating expenses
Purchased power		753			882			(129	)
Operating and maintenance		159			253			(94	)
Operating and maintenance for regulatory required programs (a)		19			11			8
Depreciation and amortization		130			123			7
Taxes other than income		63			78			(15	)


Total operating expenses		1,124			1,347			(223	)


Operating income		291			206			85


Other income and deductions
Interest expense, net		(84	)		(83	)		(1	)
Other, net		3			32			(29	)


Total other income and deductions		(81	)		(51	)		(30	)


Income before income taxes		210			155			55

Income taxes		94			41			53


Net income	$	116		$	114		$	2

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

EXELON CORPORATION

Business Segment Comparative Statements of Operations

(unaudited)

(in millions)


	PECO

	Three Months Ended March 31,
	2010			2009			Variance
Operating revenues	$	1,455		$	1,514		$	(59	)

Operating expenses
Purchased power		524			570			(46	)
Fuel		211			266			(55	)
Operating and maintenance		181			177			4
Operating and maintenance for regulatory required programs (a)		8			—			8
Depreciation and amortization		265			225			40
Taxes other than income		72			66			6


Total operating expenses		1,261			1,304			(43	)


Operating income		194			210			(16	)


Other income and deductions
Interest expense, net		(45	)		(50	)		5
Loss in equity method investments		—			(7	)		7
Other, net		4			5			(1	)


Total other income and deductions		(41	)		(52	)		11


Income before income taxes		153			158			(5	)

Income taxes		52			45			7


Net income	$	101		$	113		$	(12	)

(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.


	Other (a)

	Three Months Ended March 31,
	2010			2009			Variance
Operating revenues	$	(830	)	$	(946	)	$	116

Operating expenses
Purchased power		(827	)		(944	)		117
Fuel		(1	)		—			(1	)
Operating and maintenance		(18	)		3			(21	)
Depreciation and amortization		10			12			(2	)
Taxes other than income		5			6			(1	)


Total operating expenses		(831	)		(923	)		92


Operating income (loss)		1			(23	)		24


Other income and deductions
Interest expense, net		(19	)		(25	)		6
Other, net		7			8			(1	)


Total other income and deductions		(12	)		(17	)		5


Loss before income taxes		(11	)		(40	)		29

Income taxes		18			3			15


Net loss	$	(29	)	$	(43	)	$	14

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

EXELON CORPORATION

Consolidated Balance Sheets

(unaudited)

(in millions)


	March 31, 2010			December 31, 2009
Assets

Current assets
Cash and cash equivalents	$	2,524		$	2,010
Restricted cash and investments		42			40
Restricted cash and cash equivalents of variable interest entity		197			—
Accounts receivable, net
Customer		1,628			1,563
Other		439			486
Mark-to-market derivative assets		463			376
Inventories, net
Fossil fuel		130			198
Materials and supplies		562			559
Other		399			209


Total current assets		6,384			5,441


Property, plant and equipment, net		27,737			27,341

Deferred debits and other assets
Regulatory assets		4,668			4,872
Nuclear decommissioning trust (NDT) funds		6,885			6,669
Investments		724			724
Goodwill		2,625			2,625
Mark-to-market derivative assets		867			649
Other		851			859


Total deferred debits and other assets		16,620			16,398

Total assets	$	50,741		$	49,180


Liabilities and shareholders’ equity
Current liabilities
Short-term borrowings	$	256		$	155
Short-term notes payable-accounts receivable agreement		225			—
Long-term debt due within one year		827			639
Long-term debt of variable interest entity due within one year		404			—
Long-term debt to PECO Energy Transition Trust due within one year		—			415
Accounts payable		1,143			1,345
Accrued expenses		1,191			923
Deferred income taxes		220			152
Mark-to-market derivative liabilities		183			198
Other		441			411


Total current liabilities		4,890			4,238

Long-term debt		10,808			10,995
Long-term debt to financing trusts		390			390

Deferred credits and other liabilities
Deferred income taxes and unamortized investment tax credits		5,983			5,750
Asset retirement obligations		3,481			3,434
Pension obligations		3,536			3,625
Non-pension postretirement benefits obligations		2,220			2,180
Spent nuclear fuel obligation		1,017			1,017
Regulatory liabilities		3,572			3,492
Mark-to-market derivative liabilities		8			23
Other		1,298			1,309


Total deferred credits and other liabilities		21,115			20,830

Total liabilities		37,203			36,453


Preferred securities of subsidiary		87			87

Shareholders’ equity
Common stock		8,940			8,923
Treasury stock, at cost		(2,328	)		(2,328	)
Retained earnings		8,534			8,134
Accumulated other comprehensive loss, net		(1,695	)		(2,089	)


Total shareholders’ equity		13,451			12,640


Total liabilities and shareholders’ equity	$	50,741		$	49,180

EXELON CORPORATION

Consolidated Statements of Cash Flows

(unaudited)

(in millions)


	Three Months Ended March 31,
	2010			2009
Cash flows from operating activities
Net income	$	749		$	712
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation, amortization and accretion, including nuclear fuel amortization		718			622
Impairment of long-lived assets		—			223
Deferred income taxes and amortization of investment tax credits		(4	)		(80	)
Net fair value changes related to derivatives		(233	)		(164	)
Net realized and unrealized (gains) losses on NDT fund investments		(36	)		68
Other non-cash operating activities		72			280
Changes in assets and liabilities:
Accounts receivable		40			108
Inventories		67			132
Accounts payable, accrued expenses and other current liabilities		(303	)		(542	)
Option premiums (paid) received, net		66			(68	)
Counterparty collateral received, net		477			784
Income taxes		517			161
Pension and non-pension postretirement benefit contributions		(98	)		(37	)
Other assets and liabilities		(171	)		(249	)

Net cash flows provided by operating activities		1,861			1,950


Cash flows from investing activities
Capital expenditures		(878	)		(712	)
Proceeds from NDT fund sales		5,968			3,050
Investment in NDT funds		(6,025	)		(3,109	)
Change in restricted cash		214			23
Other investing activities		12			(4	)

Net cash flows used in investing activities		(709	)		(752	)


Cash flows from financing activities
Changes in short-term debt		101			(4	)
Issuance of long-term debt		—			249
Retirement of long-term debt		(1	)		(64	)
Retirement of long-term debt of variable interest entity		(402	)		—
Retirement of long-term debt to financing affiliates		—			(169	)
Dividends paid on common stock		(347	)		(346	)
Proceeds from employee stock plans		11			9
Other financing activities		—			5

Net cash flows used in financing activities		(638	)		(320	)


Increase in cash and cash equivalents		514			878
Cash and cash equivalents at beginning of period		2,010			1,271

Cash and cash equivalents at end of period	$	2,524		$	2,149

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 March 31, 2010									Three Months Ended March 31, 2009
	GAAP (a)			Adjustments			Adjusted Non-GAAP			GAAP (a)			Adjustments			Adjusted Non-GAAP
Operating revenues	$	4,461		$	3	(c)	$	4,464		$	4,722		$	33	(c)	$	4,755

Operating expenses
Purchased power		658			185	(d)		843			683			201	(d)		884
Fuel		601			48	(d)		649			776			(16	)(d)		760
Operating and maintenance		1,062			2	(e)		1,064			1,361			(236	)(h),(i)		1,125
Operating and maintenance for regulatory required programs (b)		27			—			27			11			—			11
Depreciation and amortization		514			(15	)(e)		499			436			—			436
Taxes other than income		197			—			197			200			—			200

Total operating expenses		3,059			220			3,279			3,467			(51	)		3,416

Operating income		1,402			(217	)		1,185			1,255			84			1,339

Other income and deductions
Interest expense, net		(183	)		—			(183	)		(187	)		—			(187	)
Loss in equity method investments		—			—			—			(8	)		—			(8	)
Other, net		93			(58	)(f)		35			(37	)		96	(f)		59

Total other income and deductions		(90	)		(58	)		(148	)		(232	)		96			(136	)


Income before income taxes		1,312			(275	)		1,037			1,023			180			1,203

Income taxes		563			(188	)(c),(d),(e),(f),(g)		375			311			95	(c),(d),(f),(h),(i)		406


Net income	$	749		$	(87	)	$	662		$	712		$	85		$	797


Effective tax rate		42.9	%					36.2	%		30.4	%					33.7	%

Earnings per average common share
Basic:
Net income	$	1.13		$	(0.13	)	$	1.00		$	1.08		$	0.13		$	1.21

Diluted:
Net income	$	1.13		$	(0.13	)	$	1.00		$	1.08		$	0.12		$	1.20

Average common shares outstanding
Basic		661						661			659						659
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)				$	—								$	0.03
Mark-to-market impact of economic hedging activities (d)					(0.21	)								(0.17	)
Retirement of fossil generating units (e)					0.01									—
Unrealized gains and losses related to NDT fund investments (f)					(0.03	)								0.05
Non-cash charge resulting from health care legislation (g)					0.10									—
NRG acquisition costs (h)					—									0.01
Impairment of certain generating assets (i)					—									0.20

Total adjustments				$	(0.13	)							$	0.12

(a)	Results reported in accordance with GAAP.

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

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

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

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

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

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

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

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

EXELON CORPORATION

Reconciliation of Adjusted (non-GAAP) Operating

Earnings to GAAP Earnings (in millions)

Three Months Ended March 31, 2010 and 2009


	Exelon Earnings per Diluted Share			Generation			ComEd			PECO			Other			Exelon
2009 GAAP Earnings (Loss)	$	1.08		$	528		$	114		$	113		$	(43	)	$	712

2009 Adjusted (non-GAAP) Operating Earnings (Loss) Adjustments:
2007 Illinois Electric Rate Settlement		0.03			21			—			—			—			21
Mark-to-Market Impact of Economic Hedging Activities		(0.17	)		(112	)		—			—			—			(112	)
Unrealized Losses Related to NDT Fund Investments (1)		0.05			33			—			—			—			33
NRG Acquisition Costs (2)		0.01			—			—			—			8			8
Impairment of Certain Generating Assets (3)		0.20			135			—			—			—			135

2009 Adjusted (non-GAAP) Operating Earnings (Loss)		1.20			605			114			113			(35	)		797

Year Over Year Effects on Earnings:
Generation Energy Margins, Excluding Mark-to-Market:
Nuclear Output (4)		(0.04	)		(28	)		—			—			—			(28	)
Nuclear Fuel Costs (5)		(0.03	)		(18	)		—			—			—			(18	)
Market and Portfolio Conditions (6)		(0.05	)		(34	)		—			—			—			(34	)
ComEd and PECO Margins:
Weather		(0.02	)		—			(3	)		(7	)		—			(10	)
Load (7)		—			—			(1	)		1			—			—
Other Energy Delivery		(0.01	)		—			(7	)		(3	)		—			(10	)
Competitive Transition Charge (CTC) Recoveries (8)		—			(29	)		—			33			(4	)		—
Operating and Maintenance Expense:
Bad Debt (9)		0.01			(1	)		1			7			—			7
Recovery of Prior Year Bad Debt Expense at ComEd (10)		0.06			—			36			—			—			36
Labor, Contracting and Materials (11)		0.02			5			13			(2	)		—			16
Other Operating and Maintenance (12)		0.02			8			8			(6	)		—			10
Pension and Non-Pension Postretirement Benefits (13)		(0.01	)		(5	)		—			—			—			(5	)
Planned Nuclear Refueling Outages (14)		(0.05	)		(31	)		—			—			—			(31	)
Depreciation and Amortization Expense (15)		(0.03	)		(11	)		(4	)		(3	)		1			(17	)
Scheduled CTC Amortization Expense (16)		(0.04	)		—			—			(26	)		—			(26	)
Benefit From Illinois Tax Ruling (17)		(0.06	)		(8	)		(35	)		—			1			(42	)
Income Taxes (18)		—			(17	)		(2	)		—			19			—
Interest Expense		—			(6	)		—			3			2			(1	)
Other (19)		0.03			4			9			1			4			18

2010 Adjusted (non-GAAP) Operating Earnings (Loss)		1.00			434			129			111			(12	)		662

2010 Adjusted (non-GAAP) Operating Earnings (Loss) Adjustments:
2007 Illinois Electric Rate Settlement		—			(1	)		(1	)		—			—			(2	)
Mark-to-Market Impact of Economic Hedging Activities		0.21			142			—			—			—			142
Unrealized Gains Related to NDT Fund Investments		0.03			20			—			—			—			20
Retirement of Fossil Generating Units (20)		(0.01	)		(8	)		—			—			—			(8	)
Non-Cash Charge Resulting From Health Care Legislation (21)		(0.10	)		(26	)		(12	)		(10	)		(17	)		(65	)

2010 GAAP Earnings (Loss)	$	1.13		$	561		$	116		$	101		$	(29	)	$	749

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

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

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

(4)	Primarily reflects the impact of increased planned nuclear outage days in 2010, partially due to steam generator replacement at Three Mile Island.

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

(6)	Reflects the impact of a decrease in realized market prices for the sale of energy.

(7)	Reflects the weather-normalized impact of decreased electric deliveries of 0.8% at ComEd and increased electric deliveries of 0.5% at PECO.

(8)	Reflects the impact of lower energy prices under the PPA between Generation and PECO, which expires on December 31, 2010, resulting from increased CTC recoveries at PECO. Generation and PECO marginal tax rate differences are reflected at Exelon Corporate.

(9)	Primarily reflects decreased customer account charge-offs at PECO as a result of improved accounts receivable aging.

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

(11)	Primarily reflects the impact of Exelon’s ongoing cost management initiative, partially offset by inflation related to labor, contracting and materials expense (exclusive of incremental storm costs and planned nuclear refueling outages as disclosed in numbers 12 and 14 below).

(12)	Primarily reflects reduced stock-based compensation costs across the operating companies and the impact of Exelon’s ongoing cost management initiative, partially offset by increased storm costs in 2010 in the PECO service territory.

(13)	Primarily reflects the impact of a decrease in the assumed discount rate used in 2010 to calculate the pension and other postretirement benefit obligations.

(14)	Primarily reflects the impact of increased planned nuclear outage days in 2010, excluding Salem, partially due to steam generator replacement at Three Mile Island.

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

(16)	Reflects an increase in scheduled amortization expense of CTCs at PECO, which will be fully amortized at the end of the transition period on December 31, 2010.

(17)	Reflects the impact of benefits associated with a February 2009 Illinois Supreme Court decision granting Illinois investment tax credits to Exelon recognized in the first quarter of 2009, which were subsequently reversed in the third quarter of 2009.

(18)	Primarily reflects the 2009 impact of tax planning opportunities.

(19)	Primarily reflects decreased taxes other than income at ComEd and realized gains associated with NDT funds at Generation as a result of favorable market conditions in 2010.

(20)	Primarily reflects accelerated depreciation expense associated with the planned retirement of four fossil generating units.

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

EXELON CORPORATION

Reconciliation of Adjusted (non-GAAP) Operating Earnings to

GAAP Consolidated Statements of Operations

(unaudited)

(in millions)


	Generation
	Three Months Ended March 31, 2010									Three Months Ended March 31, 2009
	GAAP (a)			Adjustments			Adjusted Non-GAAP			GAAP (a)			Adjustments			Adjusted Non-GAAP
Operating revenues	$	2,421		$	2	(b)	$	2,423		$	2,601		$	33	(b)	$	2,634
Operating expenses
Purchased power		208			185	(c)		393			175			201	(c)		376
Fuel		391			48	(c)		439			510			(16	)(c)		494
Operating and maintenance		740			(1	)(d),(e)		739			928			(223	)(g)		705
Depreciation and amortization		109			(15	)(d)		94			76			—			76
Taxes other than income		57			—			57			50			—			50


Total operating expenses		1,505			217			1,722			1,739			(38	)		1,701

Operating income		916			(215	)		701			862			71			933

Other income and deductions
Interest expense, net		(35	)		—			(35	)		(29	)		—			(29	)
Loss in equity method investments		—			—			—			(1	)		—			(1	)
Other, net		79			(58	)(f)		21			(82	)		96	(f)		14


Total other income and deductions		44			(58	)		(14	)		(112	)		96			(16	)


Income before income taxes		960			(273	)		687			750			167			917

Income taxes		399			(146	)(b),(c),(d),(e),(f)		253			222			90	(b),(c),(f),(g)		312


Net income	$	561		$	(127	)	$	434		$	528		$	77		$	605

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

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

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

EXELON CORPORATION

Reconciliation of Adjusted (non-GAAP) Operating Earnings to

GAAP Consolidated Statements of Operations

(unaudited)

(in millions)


	ComEd
	Three Months Ended March 31, 2010									Three Months Ended March 31, 2009
	GAAP (a)			Adjustments			Adjusted Non-GAAP			GAAP (a)			Adjustments		Adjusted Non-GAAP
Operating revenues	$	1,415		$	1	(c)	$	1,416		$	1,553		$	—	$	1,553

Operating expenses
Purchased power		753			—			753			882			—		882
Operating and maintenance		159			(3	)(d)		156			253			—		253
Operating and maintenance for regulatory required programs (b)		19			—			19			11			—		11
Depreciation and amortization		130			—			130			123			—		123
Taxes other than income		63			—			63			78			—		78


Total operating expenses		1,124			(3	)		1,121			1,347			—		1,347


Operating income		291			4			295			206			—		206

Other income and deductions
Interest expense, net		(84	)		—			(84	)		(83	)		—		(83	)
Other, net		3			—			3			32			—		32


Total other income and deductions		(81	)		—			(81	)		(51	)		—		(51	)


Income before income taxes		210			4			214			155			—		155

Income taxes		94			(9	)(c),(d)		85			41			—		41


Net income	$	116		$	13		$	129		$	114		$	—	$	114

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

EXELON CORPORATION

Reconciliation of Adjusted (non-GAAP) Operating Earnings to

GAAP Consolidated Statements of Operations

(unaudited)

(in millions)


	PECO
	Three Months Ended March 31, 2010									Three Months Ended March 31, 2009
	GAAP (a)			Adjustments			Adjusted Non-GAAP			GAAP (a)			Adjustments		Adjusted Non-GAAP
Operating revenues	$	1,455		$	—		$	1,455		$	1,514		$	—	$	1,514

Operating expenses
Purchased power		524			—			524			570			—		570
Fuel		211			—			211			266			—		266
Operating and maintenance		181			(2	)(c)		179			177			—		177
Operating and maintenance for regulatory required programs (b)		8			—			8			—			—		—
Depreciation and amortization		265			—			265			225			—		225
Taxes other than income		72			—			72			66			—		66


Total operating expenses		1,261			(2	)		1,259			1,304			—		1,304


Operating income		194			2			196			210			—		210


Other income and deductions
Interest expense, net		(45	)		—			(45	)		(50	)		—		(50	)
Loss in equity method investments		—			—			—			(7	)		—		(7	)
Other, net		4			—			4			5			—		5


Total other income and deductions		(41	)		—			(41	)		(52	)		—		(52	)


Income before income taxes		153			2			155			158			—		158

Income taxes		52			(8	)(c)		44			45			—		45


Net income	$	101		$	10		$	111		$	113		$	—	$	113

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

EXELON CORPORATION

Reconciliation of Adjusted (non-GAAP) Operating Earnings to

GAAP Consolidated Statements of Operations

(unaudited)

(in millions)


	Other

	Three Months Ended March 31, 2010									Three Months Ended March 31, 2009
	GAAP (a)			Adjustments			Adjusted Non-GAAP			GAAP (a)			Adjustments			Adjusted Non-GAAP
Operating revenues	$	(830	)	$	—		$	(830	)	$	(946	)	$	—		$	(946	)

Operating expenses
Purchased power		(827	)		—			(827	)		(944	)		—			(944	)
Fuel		(1	)		—			(1	)		—			—			—
Operating and maintenance		(18	)		8	(b)		(10	)		3			(13	)(c)		(10	)
Depreciation and amortization		10			—			10			12			—			12
Taxes other than income		5			—			5			6			—			6


Total operating expenses		(831	)		8			(823	)		(923	)		(13	)		(936	)


Operating income (loss)		1			(8	)		(7	)		(23	)		13			(10	)


Other income and deductions
Interest expense, net		(19	)		—			(19	)		(25	)		—			(25	)
Other, net		7			—			7			8			—			8


Total other income and deductions		(12	)		—			(12	)		(17	)		—			(17	)


Loss before income taxes		(11	)		(8	)		(19	)		(40	)		13			(27	)

Income taxes		18			(25	)(b)		(7	)		3			5	(c)		8


Net loss	$	(29	)	$	17		$	(12	)	$	(43	)	$	8		$	(35	)

(a)	Results reported in accordance with GAAP.

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

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

EXELON CORPORATION

Exelon Generation Statistics


	Three Months Ended
	Mar. 31, 2010			Dec. 31, 2009			Sept. 30, 2009			Jun. 30, 2009			Mar. 31, 2009
Supply (in GWhs)
Nuclear Generation
Mid-Atlantic (a)		11,776			11,137			12,349			12,276			12,104
Midwest		22,333			22,472			23,335			22,719			23,278

Total Nuclear Generation		34,109			33,609			35,684			34,995			35,382
Fossil and Hydro Generation
Mid-Atlantic (b)		2,564			1,986			2,044			2,279			2,629
Midwest		—			—			—			3			1
South		119			48			645			419			135

Total Fossil and Hydro Generation		2,683			2,034			2,689			2,701			2,765
Purchased Power
Mid-Atlantic		463			342			531			372			502
Midwest		1,914			1,991			1,923			1,673			2,151
South		2,701			2,851			4,215			3,231			3,424

Total Purchased Power		5,078			5,184			6,669			5,276			6,077
Total Supply by Region
Mid-Atlantic		14,803			13,465			14,924			14,927			15,235
Midwest		24,247			24,463			25,258			24,395			25,430
South		2,820			2,899			4,860			3,650			3,559

Total Supply		41,870			40,827			45,042			42,972			44,224


	Three Months Ended
	Mar. 31, 2010			Dec. 31, 2009			Sept. 30, 2009			Jun. 30, 2009			Mar. 31, 2009
Electric Sales (in GWhs)
ComEd (e)		3,428			3,439			3,639			4,215			5,537
PECO		10,228			9,588			10,809			9,277			10,223
Market and Retail (e)		28,214			27,800			30,594			29,480			28,464

Total Electric Sales (c) (d)		41,870			40,827			45,042			42,972			44,224


Average Margin ($/MWh) (f)
Mid-Atlantic	$	41.41		$	43.15		$	41.47		$	45.76		$	45.56
Midwest		41.00			41.98			40.94			41.73			42.26
South		(16.67	)		(14.49	)		(3.50	)		(6.85	)		(9.18	)
Average Margin - Overall Portfolio	$	37.26		$	38.36		$	36.32		$	38.96		$	39.25

Around-the-clock Market Prices ($/MWh) (g)
PJM West Hub	$	44.54		$	37.31		$	33.20		$	33.70		$	49.18
NiHub		34.47			29.61			25.69			26.11			34.09
Henry Hub		5.15			4.25			3.15			3.69			4.58

(a)	Includes Generation’s proportionate share of the output of its nuclear generating plants, including Salem Generating Station (Salem), which is operated by PSEG Nuclear, LLC.

(b)	Includes New England generation.

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

(d)	Total sales do not include trading volume of 920 GWhs, 1,599 GWhs, 1,645 GWhs, 2,003 GWhs and 2,331 GWhs for the three months ended March 31, 2010, December 31, 2009, September 30, 2009, June 30, 2009 and March 31, 2009, respectively.

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

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

(g)	Represents the average for the quarter.

EXELON CORPORATION

ComEd Statistics

Three Months Ended March 31, 2010 and 2009


	Electric Deliveries (in GWhs)						Revenue (in millions)
	2010	2009	% Change		Weather-Normal % Change		2010			2009		% Change
Retail Deliveries and Sales (a)
Residential	6,943	7,063	(1.7	)%	0.1	%	$	778		$	846	(8.0	)%
Small Commercial & Industrial	7,930	8,149	(2.7	)%	(1.7	)%		387			449	(13.8	)%
Large Commercial & Industrial	6,663	6,775	(1.7	)%	(1.1	)%		97			100	(3.0	)%
Public Authorities & Electric Railroads	367	346	6.1	%	9.1	%		18			15	20.0	%


Total Retail	21,903	22,333	(1.9	)%	(0.8	)%		1,280			1,410	(9.2	)%


Other Revenue (b)								135			143	(5.6	)%

Total Electric Revenue							$	1,415		$	1,553	(8.9	)%


Purchased Power							$	753		$	882	(14.6	)%


Heating and Cooling Degree-Days					% Change
	2010	2009	Normal		From 2009		From Normal
Heating Degree-Days	3,110	3,320	3,208		(6.3	)%		(3.1	)%
Cooling Degree-Days	—	—	—		—			—

Number of Electric Customers	2010	2009
Residential	3,441,055	3,438,554
Small Commercial & Industrial	361,370	359,523
Large Commercial & Industrial	1,967	2,059
Public Authorities & Electric Railroads	4,986	5,045

Total	3,809,378	3,805,181

(a)

Reflects delivery volumes and revenues from customers purchasing electricity directly from ComEd and customers electing to receive electric generation services from a competitive electric generation supplier. All customers are assessed charges for delivery. For customers purchasing electricity from ComEd, revenue also reflects the cost of energy.

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

EXELON CORPORATION

PECO Statistics

Three Months Ended March 31, 2010 and 2009


	Electric and Gas Deliveries						Revenue (in millions)
	2010	2009	% Change		Weather-Normal % Change		2010			2009		% Change
Electric (in GWhs)
Retail Deliveries and Sales (a)
Residential	3,527	3,535	(0.2	)%	1.8	%	$	473		$	466	1.5	%
Small Commercial & Industrial	2,150	2,196	(2.1	)%	(0.9	)%		248			250	(0.8	)%
Large Commercial & Industrial	3,794	3,792	0.1	%	0.1	%		324			319	1.6	%
Public Authorities & Electric Railroads	246	246	0.0	%	(0.3	)%		23			24	(4.2	)%

Total Retail	9,717	9,769	(0.5	)%	0.5	%		1,068			1,059	0.8	%

Other Revenue (b)								61			67	(9.0	)%

Total Electric Revenue								1,129			1,126	0.3	%

Gas (in mmcfs)
Retail Sales	27,584	28,614	(3.6	)%	1.4	%		318			380	(16.3	)%
Transportation and Other	8,617	7,878	9.4	%	9.6	%		8			8	0.0	%

Total Gas	36,201	36,492	(0.8	)%	3.1	%		326			388	(16.0	)%

Total Electric and Gas Revenues							$	1,455		$	1,514	(3.9	)%

Purchased Power							$	524		$	570	(8.1	)%
Fuel								211			266	(20.7	)%

Total Purchased Power and Fuel							$	735		$	836	(12.1	)%

					% Change
Heating and Cooling Degree-Days	2010	2009	Normal		From 2009		From Normal
Heating Degree-Days	2,411	2,534	2,510		(4.9	%)		(3.9	%)
Cooling Degree-Days	—	—	—		—			—
Number of Electric Customers	2010	2009	Number of Gas Customers				2010			2009
Residential	1,406,614	1,407,089	Residential					446,440			444,349
Small Commercial & Industrial	156,374	156,065	Commercial & Industrial					41,286			41,285

Large Commercial & Industrial	3,091	3,088	Total Retail					487,726			485,634
Public Authorities & Electric Railroads	1,084	1,080	Transportation					795			732

Total	1,567,163	1,567,322	Total					488,521			486,366

(a)

Reflects delivery volumes and revenues from customers purchasing electricity directly from PECO and customers electing to receive electric generation service from a competitive electric generation supplier. All customers are assessed charges for transmission, distribution and a CTC. For customers purchasing electricity from PECO, revenue also reflects the cost of energy.

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

Earnings conference call presentation slides

Earnings Conference Call •

Quarter 2010

April 23, 2010

Exhibit 99.2

Forward-Looking Statements

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

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

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

statements include those discussed herein as well as those discussed in (1) Exelon’s 2009

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

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

Financial Statements and Supplementary Data: Note 18; (2) Exelon’s First Quarter 2010

Quarterly Report on Form 10-Q (to be filed on April 23, 2010) in (a) Part II, Other Information,

Item 1A. Risk Factors and (b) Part I, Financial Information, Item 1. Financial Statements: Note

12 and (3) other factors discussed in filings with the Securities and Exchange Commission

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

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

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

presentation. None of the Companies undertakes any obligation to publicly release any

revision to its forward-looking statements to reflect events or circumstances after the date of

this presentation.

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

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

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

the Companies. Please refer to the appendix to this presentation for a reconciliation of

adjusted (non-GAAP) operating earnings to GAAP earnings. Please refer to the footnotes of

the following slides for a reconciliation non-GAAP cash flows to GAAP cash flows.

2010 Operating Earnings Guidance

2010 Revised

2010 Original

$0.40 -

$0.50

$2.55 -

$2.80

$3.60 -

$4.00

(1)

ComEd

PECO

Exelon

Generation

ComEd

PECO

Exelon

Generation

Holdco

Exelon

$0.60 -

$0.70

Exelon

$3.70 -

$4.00

(1)

$0.60 -

$0.70

$0.40 -

$0.50

$2.70 -

$2.90

Revising 2010 operating earnings guidance to $3.70

–

$4.00/share

(1)

Key Drivers of Guidance Revision

Higher Exelon Generation revenue

net fuel

Improved PECO load outlook

Final 2010 pension/OPEB expense

lower than anticipated

(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.

Key Financial Messages

Operating results for 1Q10

•

Operating

earnings

$1.00/share

(1)

•

92.3% nuclear capacity factor

•

Initial

signs

economic

recovery

with

improved

load

outlook

our

service

areas

Revising

2010

operating

earnings

guidance

$3.70

$4.00/share

(1)

•

Expect 2Q10 earnings in the range of $0.80

$0.90/share

•

On track to meet 2010 O&M targets

Improved

cash

flow

from

operations

for

2010

(2)

•

Anticipate using cash and debt to make an incremental pension contribution of about

$500 million

Executing

regulatory

plan

PECO

and

ComEd

•

PECO

filed

electric

and

gas

distribution

rate

cases

March

31,

2010

•

ComEd is planning to file electric distribution rate case in 2Q10

(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.

Note: Data contained on this slide is rounded.

$0.91

$0.17

$0.66

$0.17

$0.19

$0.17

2009

2010

Operating EPS

HoldCo/Other

ExGen

PECO

ComEd

1st

Quarter (1Q)

(1)

Lower ExGen margins are driving lower quarter over quarter earnings; however,

1Q10 earnings were higher than the guidance of $0.85

$0.95/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.

$1.08

$1.13

GAAP EPS

$1.00

$1.20

Exelon Generation

Operating EPS Contribution

2010

2009

Key Drivers –

1Q10 vs. 1Q09

(1)

Unfavorable market/portfolio conditions:

$(0.05)

Lower energy prices under the PECO

PPA, offset at PECO: $(0.05)

Lower nuclear volume: $(0.04)

Higher O&M, primarily due to higher

nuclear outage days, partially offset by

cost management initiatives: $(0.04)

Higher nuclear fuel costs: $(0.03)

(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.

101

Refueling

Non-refueling

1Q10

1Q09

Outage Days

(2)

$0.91

$0.66

0.00

2.00

4.00

6.00

8.00

10.00

12.00

14.00

16.00

2007

2008

2009

2010

2011

2012

2013

2014

Actuals

PJM Oct '09 FTR Auction

6/30/2009

12/31/2009

3/31/2010

Power Markets Update

$32.19

$30.71

$29.73

Ni-Hub ATC ($/MWh)

$43.47

$42.04

$39.69

PJM-W ATC ($/MWh)

Reference Prices

2010

2011

2012

Percentage of Expected

Generation Hedged

(1)

95-98%

79-82%

48-51%

Midwest

92-95

79-82

52-55

Mid-Atlantic

96-99

81-84

44-47

South

97-100

68-71

41-44

10,300 MW

8,700 MW

1,500 MW

RTO

EMAAC

MAAC

Capacity

Region

Eligible

for

2013/14

RPM

Base

Residual

Auction

(2)

(1)

See footnote 2 on page 34.

(2)

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

Notes: All capacity values are in installed capacity terms (summer ratings) located in the areas. Reflects the retirements of Eddystone 1 and 2 and Cromby Station.

MAAC = Mid-Atlantic Area Council; EMAAC = Eastern MAAC; MAAC area encompasses EMAAC

50%

43%

Key drivers expected to impact clearing prices:

•

Rule change allowing existing demand response

resources to bid in above $0

•

PJM raised the forecast for demand by 1.7%

•

First Energy has joined PJM with a net load increase

•

Delay in Susquehanna-Roseland Transmission line

reduces available import capability into EMAAC

•

Net CONE increasing by 15% and 23% for RTO and

EMAAC, respectively

AEP-Dayton / NiHub ATC Energy Basis

As of March 31, 2010

Key Drivers –

1Q10 vs. 1Q09

(1)

Uncollectible expense rider: $0.06

Lower O&M primarily due to cost

management initiatives:

$0.03

‘09 benefit from Illinois tax ruling,

which was later reversed in 3Q09:

$(0.05)

ComEd Operating EPS Contribution

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

2010

2009

$0.17

$0.19

1Q10

Actual

Normal

% Change

Heating Degree Days 3,110 3,208 (3.1)%

-10.0%

-7.5%

-5.0%

-2.5%

0.0%

2.5%

5.0%

7.5%

10.0%

1Q09

2Q09

3Q09

4Q09

1Q10

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

ComEd Load Trends

Weather-Normalized Load

Key Economic Indicators

Note: C&I = Commercial & Industrial

Weather-Normalized Load Year-over-Year

(4)

Chicago

Unemployment rate

(1)

10.9%

2010 annualized growth in

gross domestic/metro product

(2)

2.9%

1/10 Home price index

(3)

(4.4)%

(1) Source: Illinois Dept. of Employment Security (February 2010)

(2)

Source: Global Insight (March 2010)

(3)

Source: S&P Case-Shiller Index

(4)

Not adjusted for leap year effect

2009

(4)

1Q10 2010E

Average Customer Growth

(0.4)% (0.1)% 0.1%

Average Use-Per-Customer

(1.0)%

0.2%

0.1%

Total Residential

(1.4)% 0.1% 0.2%

Small C&I

(2.2)% (1.7)% 0.4%

Large C&I

(6.7)% (1.1)% 1.7%

All Customer Classes

(3.3)% (0.8)% 0.8%

ComEd Credit Facility

One of the largest utility bank refinancings launched to-date in 2010,

with strong participation and new benchmark pricing

Successfully closed refinancing of $1 billion revolving credit

facility

March

•

3-year unsecured facility; initial term to expire 3/25/13

•

Use for general corporate purposes and letters of credit

•

Replaces previous $952 million facility that was due to expire on 2/16/11

Moved the bar on market pricing

•

Undrawn fee of 0.375%; fully drawn fee of LIBOR + 2.25%

•

Refinancing

deals

for

similar

rated

utilities

launched

late

last

year

priced

approximately 0.50-0.75% higher (drawn fee)

Reflects strong relationships with large, diverse bank group

•

22 banks in facility

–

none with exposure of more than 6%

•

Syndication 1.6x oversubscribed

PECO Operating EPS Contribution

Key Drivers –

1Q10 vs. 1Q09

(1)

Lower energy prices paid to Generation

under the PPA, offset at Generation:

$0.05

Increased storm costs: $(0.01)

CTC amortization: $(0.04)

2010

2009

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

$0.17

1Q10

Actual

Normal

% Change

Heating Degree Days 2,411

2,510 (3.9)%

PECO Load Trends

Weather-Normalized Electric Load

Key Economic Indicators

Weather-Normalized Load Year-over-Year

(3)

Philadelphia

Unemployment rate

(1)

9.2%

2010 annualized growth in

gross domestic/metro product

(2)

0.8%

(1) Source:

U.S

Dept.

Labor

(PHL

February

2010)

(2) Source: Moody’s Economy.com (March 2010)

(3) Not adjusted for leap year effect

-10.0%

-7.5%

-5.0%

-2.5%

0.0%

2.5%

5.0%

7.5%

10.0%

1Q09

2Q09

3Q09

4Q09

1Q10

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

Note: C&I = Commercial & Industrial

2009

(3)

1Q10 2010E

Average Customer Growth

(0.2)% (0.2)% (0.0)%

Average Use-Per-Customer

(2.1)%

2.1%

1.2%

Total Residential

(2.3)% 1.8% 1.1%

Small C&I

(2.7)% (0.9)% (0.2)%

Large C&I

(3.0)% 0.1% (0.3)%

All Customer Classes

(2.6)% 0.5% 0.3%

PECO –

Electric & Gas Distribution

Rate Case Filings

On March 31, PECO filed electric and gas distribution rate cases

•

First electric distribution rate case since 1989

–

Act 129 energy efficiency and smart meter costs recovered separately through rider

•

Last gas delivery rate case in 2008

53.18%

Common Equity Ratio

R-2010-216-1592

R-2010-216-1575

Docket #

2010

(1)

2010

(1)

Test Year

ROE: 11.75%

ROR: 8.95%

ROE: 11.75%

ROR: 8.95%

Requested Returns

$1,100 million

$3,236 million

Rate Base

6.94%

(2)

$316 million

Electric

$44 million

Revenue Requirement Increase

5.28%

2011 Proposed Distribution Price

Increase as % of Overall Customer Bill

Gas

Rate Case Request

The PAPUC has a nine-month process for litigation of the

rate case filings

(1) With pro forma adjustments.

(2) Excluding Alternative Energy Portfolio Standards and default service surcharge.

Note: Electric and gas rate case filings available on PAPUC website or www.peco.com/know.

2010 Projected Sources and Uses of Cash

($ millions)

Exelon

(9)

Beginning Cash Balance

(1)

$1,050

Cash Flow from Operations

(1)(2)

975

1,050

2,475

4,600

CapEx

(excluding Nuclear Fuel, Nuclear

Uprates

and Solar Project, Utility Growth

CapEx)

(675)

(400)

(775)

(1,900)

Nuclear Fuel

n/a

(850)

Dividend

(3)

(1,400)

Nuclear Uprates

and Solar Project

n/a

(350)

Utility Growth CapEx

(4)

(250)

(100)

n/a

(350)

Net Financing (excluding Dividend):

Planned Debt Issuances

(5)(6)

500

250

750

Planned Debt Retirements

(7)

(225)

(400)

(1,025)

Other

(8)

(75)

175

(25)

Ending Cash Balance

(1)

$500

(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 $551 million for competitive transition charges.

(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 $212 million and ComEd’s $191 million of tax-exempt bonds that are backed by letters of credit (LOCs). Excludes PECO’s $225 million

Accounts Receivable (A/R) Agreement with Bank of Tokyo. Assumes PECO’s A/R Agreement is extended in accordance with its terms beyond September 16, 2010.

(6)

Exelon Generation’s financing includes $250 million of debt to refinance a portion of Exelon Corp’s $400 million maturity.

(7)

Excludes Exelon Generation’s and ComEd’s tax-exempt bonds. 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.

Appendix

2010 Events of Interest

RPM Base Residual

Auction (May)

Uncollectibles rider

tariff (2/2)

Illinois Power Agency supply

procurement RFP (4/28, ICC

decision to follow)

Illinois Primaries

(2/2)

Pennsylvania

Primaries (5/18)

Electric and gas

distribution rate

case filings (3/31)

Procurement RFP

(May, results in June)

Procurement RFP

(Sep., results in Oct.)

Electric distribution

rate case filing (2Q)

Illinois Elections

(11/2)

Pennsylvania

Elections (11/2)

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.

Outstanding Facility Draws

(431)

(163)

(3)

(261)

Outstanding Letters of Credit

$7,365

$4,834

$574

$1,000

Aggregate Bank Commitments

(1)

6,934

4,671

571

739

Available Capacity Under Facilities

(2)

(164)

Outstanding Commercial Paper

$6,770

$4,671

$571

$575

Available Capacity Less Outstanding

Commercial Paper

Exelon

(3)

($ millions)

Exelon bank facilities are largely untapped

Available Capacity Under Bank Facilities as of April 15, 2010

Projected 2010 Key Credit Measures

14.3x

9.4x

FFO / Interest

Generation /

Corp:

68%

39%

FFO / Debt

54%

68%

Rating Agency Debt Ratio

BBB

A-

BBB-

S&P Credit

Ratings

(3)

BBB+

Fitch Credit

Ratings

(3)

Baa1

Moody’s Credit

Ratings

(3)

4.7x

5.2x

FFO / Interest

ComEd:

23%

21%

FFO / Debt

43%

48%

Rating Agency Debt Ratio

5.1x

5.0x

FFO / Interest

PECO:

26%

23%

FFO / Debt

45%

49%

Rating Agency Debt Ratio

29%

45%

Rating Agency Debt Ratio

94%

47%

FFO / Debt

20.9x

11.4x

FFO / Interest

Generation:

47%

41%

8.0x

Without PPA &

Pension / OPEB

(2)

56%

Rating Agency Debt Ratio

30%

FFO / Debt

7.1x

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:

debt

equivalents

for

Operating

Leases,

PPAs,

unfunded

Pension

and

OPEB

obligations

(after-tax),

Capital

Adequacy

for Energy Trading, and other minor debt equivalents.

(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 April 20, 2010.

FFO Calculation and Ratios

+ Other Non-Cash items

(1)

AFUDC/Cap. Interest

Decommissioning activity

+/-

Change in Working Capital

FFO Calculation

= FFO

PECO Transition Bond Principal Paydown

Net Cash Flows provided by Operating Activities

Net Interest Expense

Adjusted Interest

FFO + Adjusted Interest

= Adjusted Interest

+ 6% interest on Present Value (PV) of Operating Leases

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

(PPA)

+ AFUDC & Capitalized interest

PECO Transition Bond Interest Expense

FFO Interest Coverage

FFO

= Adjusted Debt

+ Off-balance sheet debt equivalents

(2)

PECO Transition Bond Principal Balance

+ STD

+ LTD

Debt:

Adjusted Debt

(3)

FFO Debt Coverage

Rating Agency Capitalization

Rating Agency Debt

Total Adjusted Capitalization

Adjusted Book Debt

= Total Rating Agency Capitalization

+ Off-balance sheet debt equivalents

(2)

Total Adjusted Capitalization

= Rating Agency Debt

+ Off-balance sheet debt equivalents

(2)

Adjusted Book Debt

= Total Adjusted Capitalization

+ Adjusted Book Debt

+ Preferred Securities of Subsidiaries

+ Total Shareholders' Equity

Capitalization:

= Adjusted Book Debt

Transition Bond Principal Balance

+ STD

+ LTD

Debt:

Debt to Total Cap

(1)

Reflects depreciation adjustment for PPAs and operating leases.

(2)

Metrics are calculated in presentation unadjusted and adjusted for debt equivalents for PV of Operating Leases, PPAs, unfunded Pension and OPEB obli

gations (after-tax), Capital Adequacy for Energy Trading, and other minor debt equivalents.

(3)

Uses current year-end adjusted debt balance.

1Q GAAP EPS Reconciliation

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

(0.05)

Unrealized losses related to nuclear decommissioning trust funds

(0.01)

NRG acquisition costs

(0.03)

2007 Illinois electric rate settlement

0.17

Mark-to-market adjustments from economic hedging activities

(0.20)

Impairment of certain generating assets

$1.08

$(0.06)

$0.17

$0.80

1Q09 GAAP Earnings (Loss) Per Share

$1.20

$(0.05)

$0.17

$0.91

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

Exelon

Other

PECO

ComEd

ExGen

Three Months Ended March 31, 2009

(0.01)

Retirement of fossil generating units

0.03

Unrealized gains related to nuclear decommissioning trust funds

0.21

Mark-to-market adjustments from economic hedging activities

(0.10)

(0.02)

(0.04)

Non-cash charge resulting from healthcare legislation

$1.13

$(0.04)

$0.15

$0.17

$0.85

1Q10 GAAP Earnings (Loss) Per Share

$1.00

$(0.02)

$0.17

$0.19

$0.66

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

Exelon

Other

PECO

ComEd

ExGen

Three Months Ended March 31, 2010

Retiring Cromby Station and

Eddystone Units 1&2

•

Cromby Station

–

Placed in service in 1954-55

–

144 MW coal and 201 MW oil/gas

•

Eddystone Station Units 1&2

–

Placed in service in 1960

–

588 MW of coal capacity at units 1&2

–

Units 3&4 (760 MW oil/gas) and 4 peaking units

(60 MW) will continue to operate

•

Retirements yield ~$165-200 million incremental NPV vs. continuing to operate the units

–

Avoids ongoing operating and capital costs on aging units

–

Cromby and Eddystone have not cleared in the past two RPM capacity auctions (2011/12 and 2012/13)

–

Anticipates more stringent environmental regulations and avoids related capital investment

•

Agreed to delay deactivation of two units to maintain reliability, provided receipt of required

environmental permits and adequate cost-based compensation

–

Maintaining scheduled retirement date of 5/31/11 for Cromby

and Eddystone

1; delaying Cromby

to 5/31/12 and Eddystone

2 to 12/31/13

–

Pursuing

RMR

compensate

for

cost

maintaining

and

operating

units

beyond

5/31/11

$80

$85

$40

Capital Expenditure

Reduction

$40

$18

$24

Incremental Pre-Tax

Operating Income

Depreciation Savings

Operating O&M Savings

$(80)

$(50)

Revenue Net Fuel

2012

2011

2010

($ in millions)

Smaller, less efficient coal plants are challenged by economic and

environmental considerations

Ongoing Savings Impact

Note: RMR = reliability must-run agreement

Illinois Power Agency (IPA) RFP

Procurement

•

On December 28, 2009, the Illinois

Commerce Commission approved the

IPA’s Updated Procurement Plan for the

2010/11 planning period, which includes

the procurement of:

–

Monthly peak and off-peak standard

wholesale block energy products

–

1,887,014 MWh of Renewable

Energy Credits (RECs)

–

1,400,000 MWh/year of renewable

energy and associated RECs

through 20-year contracts beginning

delivery in June 2012

Delivery

Period

Peak

Off-Peak

June 2010 -

May 2011

5,528

4,344

June 2011 -

May 2012

1,980

549

Volume to be procured in the 2010

IPA Procurement Event (GWh)

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

2009 RFP

2010 RFP

2011 RFP

2012 RFP

2013 RFP

Financial

Swap

Auction

Contract

Jun 2009

Jun 2010

Jun 2011

Jun 2012

Jun 2013

Jun 2014

By May 26

By May 5

ComEd files retail generation rates

By May 24

By May 3

ICC decision on RFP results and public

release of wholesale energy prices

By May 19

By April 29

Procurement administrator submits

confidential report

May 18

April 28

Bids due

April 7 –

Potential bidders submit qualifying

proposals

RECs

(1)

Standard

Product

Event

2010 RFP –

Key Dates

(1) Timeline and procurement administrator for long-term PPAs has not yet been determined by the IPA.

ComEd Customer Usage Breakdown

Customer Usage by Revenue Class

Top 380 Customer Usage by Segment

Leisure & Hospitality

Trade, Transportation & Utilities

11%

Finance, Professional &

Business Services

12%

Health & Educational Services

13%

Government

52%

Manufacturing

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

longer production runs and additional shifts due to improved economic conditions for

customers in the steel, automotive, and plastic industries

Residential

31%

Small C&I

36%

380 Large

C&I

18%

Other Large

C&I

13%

Other

PECO Procurement Results

RFP

held

May

24,

2010,

with

results

public

days

thereafter

Residential

Sept ’09 RFP average price of

$79.96/MWh

(2)

June ’09 RFP average price of

$88.61/MWh

(2)

49% of full requirements product

procured

80 MW of block energy procured

Small and Medium Commercial

Sept ’09 RFP average blended

price of $85.85/MWh

(2)

24% of Small Commercial full

requirements product procured

16% of Medium Commercial full

requirements product procured

85% full requirements

15% full requirements spot

Medium Commercial

(peak demand >100 kW

but <= 500 kW)

Fixed-Priced Full

requirements

(3)

Hourly Full requirements

Large Commercial &

Industrial

(peak

demand

>500 kW)

90% full requirements

10% full requirements spot

75% full requirements

20% block energy

5% energy only spot

Products

Small Commercial

(peak demand <100 kW)

Residential

Customer Class

PECO

Procurement

Plan

(1)

2011 Supply procured to

date (including June and

September 2009 RFPs)

Large Commercial and Industrial

100% of planned Fixed -

price

full requirements contracts (12-mo

term)

Residential

23% of planned full requirements

contracts (17 and 29-mo terms)

140 MW of baseload (24x7)

block energy products (12, 24

and 60-mo duration)

40 MW of Jan-Feb 2011 on-peak

block energy

Small Commercial

36% of planned full requirements

contracts (17 and 29-mo term)

Medium Commercial

42% of planned full requirements

contracts (17-mo term)

May 24, 2010 RFP

(1)

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

(2)

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

(3)

For Large C&I customers who have opted to participate in the Fixed-priced Full requirements product.

PECO –

Timeline for Rate Cases

•

Filed: March 31, 2010

•

Opposing Parties’

Testimony: June 2010

•

Rebuttal Testimony: July 2010

•

Hearings: August 2010

•

Administrative Law Judge (ALJ) Orders: October 2010

•

Final Orders Expected: December 2010

•

New Rates Effective: January 1, 2011

Note:

Dates

are

based

typical

approach

rate

cases

but

the

Pennsylvania

Public

Utility

Commission

(PAPUC)

will

set

the actual schedule. Expect schedule to be set at pre-hearing with ALJ around mid-May.

5.03

6.26

6.23

0.51

0.70

2.57

9.01

PECO Electric Residential Rate

Increases 2010 to 2011

January 1, 2011

January 1, 2010

Total = 14.7¢

Unit Rates (¢/kWh)

Proposed Total Bill

Increase ~11 %

Total = 16.3¢

AEPS

~0.6%

Default Service Surcharge

Mechanism based on results of

first two procurements ~1.2%

Transmission surcharge

mechanism ~1.3%

Energy / Capacity

Competitive Transition

Charge

Transmission

Distribution

Distribution rate case ~8.2%

0.38

Energy Efficiency

Surcharge

Breakdown of 2010 to 2011

~11% Increase (On Total Bill)

Notes:

•

Rates effective January 1, 2010 include Act 129 Energy Efficiency surcharge of 2%.

•

Act 129 Smart Meter surcharge will be calculated following approval of PECO’s Smart Meter Plan expected in 2Q10. The Smart Meter surcharge,

which

will

likely

effective

3Q10,

expected

less

than

and

not

expected

increase

until

2Q/3Q

2011.

result,

the

Smart

Meter surcharge will have a minimal impact on rate increases effective January 1, 2011.

•

Low income discounted rates were subsidized in the PPA in 2010 and will be recovered through distribution rates in 2011.

0.29

PECO Customer Usage Breakdown

Other

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

Other

13%

Transportation, Communication &

Utilities

18%

Health & Educational Services

18%

Manufacturing

22%

Petroleum

Retail Trade

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

ComEd and PECO Accounts Receivable

ComEd Accounts

Receivable

(1)

Both ComEd and PECO continue to see an improvement in accounts receivable aging

1Q08

1Q09

1Q10

PECO Accounts

Receivable

(1)

% of AR

$846M

$831M

$764M

(1) Accounts receivable amounts include unbilled receivables and are gross of allowance for uncollectible accounts at ComEd and PECO and include, for PECO, pledged and

long-term receivables.

>60 days

31-60 days

0-30 days

Note: Data contained on this slide is rounded.

1Q08

1Q09

1Q10

$723M

$730M

$821M

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 to the extent not

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

•

Significant impairments of assets, including goodwill

•

Changes in decommissioning obligation estimates

•

Costs

associated

with

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

•

Non-cash charge resulting from passage of Federal health care legislation

•

Other unusual

items

•

Significant future changes to GAAP

Operating

earnings

guidance

assumes

normal

weather

for

remainder of the year

Operating

O&M

target

excludes

the

following

items:

•

Exelon Generation: Decommissioning accretion expense

•

ComEd: Impact of riders, primarily Rider EDA (Energy Efficiency and Demand Response

Adjustment)

•

PECO: Impact of energy efficiency and smart grid/meter riders

Important Information

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

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

Generation’s

gross

margin

(operating

revenues

less

purchased

power

and

fuel

expense).

The

information

the

following

slides

not

intended

represent

earnings

guidance

forecast

future

events.

fact,

many

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

the

following

slides

March

31,

2010.

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

future

periods

will

likely

differ

–

and

may

differ

significantly

–

from

the

assumptions underlying the simulation results included in the slides. In addition, the forward-

looking

information

included

the

following

slides

will

likely

change

over

time

due

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

conditions.

Portfolio Management Objective

Align Hedging Activities with Financial Commitments

•

Power Team utilizes several product

types and channels to market

•

Wholesale and retail sales

•

Block products

•

Load-following products

and load auctions

•

Put/call options

•

Exelon’s hedging program is designed to

protect the long-term value of our

generating fleet and maintain an

investment-grade balance sheet

•

Hedge enough commodity risk to meet future cash

requirements if prices drop

•

Consider: financing policy (credit rating objectives,

capital structure, liquidity); spending (capital and

O&M); shareholder value return policy

•

Consider market, credit, operational risk

•

Approach to managing volatility

•

Increase hedging as delivery approaches

•

Have enough supply to meet peak load

•

Purchase fossil fuels as power is sold

•

Choose hedging products based on generation

portfolio –

sell what we own

•

Heat rate options

•

Fuel products

•

Capacity

•

Renewable credits

% Hedged

High End of Profit

Low End of Profit

Open Generation

with LT Contracts

Portfolio

Optimization

Portfolio

Management

Portfolio Management Over Time

Percentage of Expected

Generation Hedged

•

How many equivalent MW have been

hedged at forward market prices; all hedge

products used are converted to an

equivalent average MW volume

•

Takes ALL

hedges into account whether

they are power sales or financial products

Equivalent MWs Sold

Expected Generation

•

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

over the three years leading to the spot market

•

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

risks

•

using

the

appropriate

product

mix,

expected

generation

hedged

approaches

the

mid-90s percentile as the delivery period approaches

•

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

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

quarter to quarter

Exelon Generation Hedging Program

2010

2011

2012

Estimated Open Gross Margin ($ millions)

(1,2)

$5,050

$4,900

$4,750

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)

$4.48

$29.73

$39.69

$0.43

$5.34

$30.71

$42.04

$(0.42)

$5.79

$32.19

$43.47

$0.14

Exelon Generation Open Gross Margin and

Reference Prices

(1)

Based on March 31, 2010 market conditions.

(2)

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

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

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

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

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

(3)

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

2010

2011

2012

Expected Generation

(GWh)

(1)

164,600

161,700

161,200

Midwest

98,600

98,100

97,000

Mid-Atlantic

58,000

56,600

South

8,000

7,000

7,600

Percentage of Expected Generation Hedged

(2)

95-98%

79-82%

48-51%

Midwest

92-95

79-82

52-55

Mid-Atlantic

96-99

81-84

44-47

South

97-100

68-71

41-44

Effective Realized Energy Price

($/MWh)

(3)

Midwest

$46.50

$44.50

Mid-Atlantic

$36.00

$58.00

$51.50

ERCOT North ATC Spark Spread

$0.50

$(6.50)

Generation Profile

(1)

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

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

options. Expected generation assumes 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.

(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.

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

$(20)

$20

$(15)

$ -

+/-

$30

2011

$125

$(110)

$125

$(115)

$75

$(70)

+/-

$40

2012

$320

$(315)

$235

$(225)

$175

$(170)

+/-

$45

Exelon Generation Gross Margin Sensitivities

(with Existing Hedges)

(1)

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

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

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

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

95% case

5% case

$6,500

$6,200

$4,800

$7,200

$6,300

$6,600

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 March 31, 2010.

Midwest

Mid-Atlantic

ERCOT

Step 1

Start

with

fleetwide

open

gross

margin

$5.05 billion

Step 2

Determine the mark-to-market value

of energy hedges

98,600GWh * 93% *

($46.50/MWh-$29.73/MWh)

= $1.54 billion

58,000GWh * 97% *

($36.00/MWh-$39.69/MWh)

= $(0.21 billion)

8,000GWh * 98% *

($0.50/MWh-$0.43/MWh)

= $0.00 billion

Step 3

Estimate

hedged

gross

margin

adding open gross margin to mark-to-

market value of energy hedges

Open gross margin: $5.05 billion

MTM value of energy hedges: $1.54

billion

$(0.21

billion)

$0.00

billion

Estimated hedged gross margin: $6.38 billion

Illustrative Example

of Modeling Exelon Generation 2010 Gross Margin

(with Existing Hedges)

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5.5

6.5

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8.5

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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

$5.31

2012 $5.75

Rolling 12 months, as of April 15, 2010. Source: OTC quotes and electronic trading system. Quotes are daily.

Forward NYMEX Coal

2011

$66.00

2012

$75.15

2011 Ni-Hub $38.34

2012 Ni-Hub

$40.07

2012 PJM-West $51.68

2011 PJM-West

$50.21

2011 Ni-Hub

$23.49

2012 Ni-Hub

$24.74

2012 PJM-West

$36.97

2011 PJM-West

$36.26

5.5

6.5

7.5

8.5

9.5

10.5

11.5

12.5

13.5

4/09

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8.2

8.4

8.6

8.8

9.2

9.4

9.6

9.8

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6/09

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5.5

6.5

7.5

8.5

4/09

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Market Price Snapshot

2012

$9.03

2011

$8.86

2011

$46.41

2012

$51.22

2011

$5.24

2012

$5.67

Houston Ship Channel Natural Gas

Forward Prices

ERCOT North On-Peak Forward Prices

ERCOT North On-Peak v. Houston Ship Channel

Implied Heat Rate

2011

$6.09

2012

$7.79

ERCOT North On Peak Spark Spread

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

Rolling 12 months, as of April 15, 2010. Source: OTC quotes and electronic trading system. Quotes are daily.