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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 27, 2011

Date of Report (Date of earliest event reported)


Commission File Number	Exact Name of Registrant as Specified in Its Charter; State of Incorporation; Address of Principal Executive Offices; and Telephone Number	IRS Employer Identification Number

1-16169	EXELON CORPORATION (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 27, 2011, Exelon Corporation (Exelon) announced via press release its results for the first quarter ended March 31, 2011. 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 2011 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 27, 2011. The call-in number in the U.S. and Canada is 800-690-3108, and the international call-in number is 973-935-8753. If requested, the conference ID number is 58390808. 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 11. 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 58390808.

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 2010 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 2011 Quarterly Report on Form 10-Q (to be filed on April 27, 2011) 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, Chief Financial Officer and Treasurer

Exelon Corporation

COMMONWEALTH EDISON COMPANY

/s/ Joseph R. Trpik, Jr.

Joseph R. Trpik, Jr.

Senior Vice President, Chief Financial Officer and Treasurer

Commonwealth Edison Company

PECO ENERGY COMPANY

/s/ Phillip S. Barnett

Phillip S. Barnett

Senior Vice President and Chief Financial Officer

PECO Energy Company

April 27, 2011

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

Exhibit 99.1

LOGO


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

	Kathleen Cantillon
	Corporate Communications
	312-394-7417

Exelon Announces First Quarter 2011 Results;

Reaffirms Full Year Operating Earnings Guidance Range

CHICAGO (April 27, 2011) – Exelon Corporation (NYSE: EXC) announced first quarter 2011 consolidated earnings as follows:


	First Quarter
	2011		2010
Adjusted (non-GAAP) Operating Results:
Net Income ($ millions)	$	778	$	662
Diluted Earnings per Share	$	1.17	$	1.00
GAAP Results:
Net Income ($ millions)	$	668	$	749
Diluted Earnings per Share	$	1.01	$	1.13

“Our first quarter earnings were above our expectations primarily driven by results at Generation, including the performance of our generating units during a February cold snap in the Dallas area,” said John W. Rowe, chairman and chief executive officer. “Our operating and financial performance in the first quarter keeps us comfortably on track to be within our earnings guidance range of $3.90 to $4.20 per share. Our nuclear operations also had a strong quarter, with a 94.8 percent capacity factor. Our fleet remains safe and reliable, and we are working closely with regulators, policymakers and the industry to ensure we stay current with any lessons learned from the Fukushima event.”

First Quarter Operating Results

As shown in the table above, Exelon’s adjusted (non-GAAP) operating earnings increased to $1.17 per share in the first quarter of 2011 from $1.00 per share in the first quarter of 2010, primarily due to:

•

The effect at Exelon Generation Company, LLC (Generation) of higher realized energy prices in the Mid-Atlantic region due to the expiration of the power purchase agreement (PPA) with PECO Energy Company (PECO), favorable capacity pricing primarily related to the Reliability

Pricing Model (RPM) for the PJM Interconnection, LLC (PJM) market, and increased nuclear volume primarily reflecting the effect of fewer nuclear outage days in 2011; and

•

The effect of new electric and gas distribution rates at PECO effective January 2011.

Higher first quarter 2011 earnings were partially offset by:

•

The effect of a credit in 2010 for the recovery of uncollectible accounts expense at Commonwealth Edison Company (ComEd);

•

The effect of competitive transition charge (CTC) recoveries in 2010, net of amortization expense, associated with PECO’s transition period, which ended on December 31, 2010; and

•

Higher operating and maintenance expense.

Adjusted (non-GAAP) operating earnings for the first quarter of 2011 do not include the following items (after tax) that were included in reported GAAP earnings:


	(in millions)			(per diluted share)
Mark-to-market losses primarily from Generation’s economic hedging activities	$	(89	)	$	(0.14	)
Non-cash charge to remeasure deferred taxes at higher Illinois corporate tax rates	$	(29	)	$	(0.04	)
Unrealized gains related to nuclear decommissioning trust (NDT) fund investments to the extent not offset by contractual accounting	$	24		$	0.04
Costs associated with the planned retirement of certain Generation fossil generating units	$	(16	)	$	(0.02	)

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


	(in millions)			(per diluted share)
Mark-to-market gains primarily from Generation’s economic hedging activities	$	142		$	0.21
Non-cash charge resulting from health care legislation related to Federal income tax changes	$	(65	)	$	(0.10	)
Unrealized gains related to 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	)		—

2011 Earnings Outlook

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

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

•

Mark-to-market adjustments from economic hedging activities

•

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

•

Significant impairments of assets, including goodwill

•

Changes in decommissioning obligation estimates

•

Non-cash charge to remeasure deferred taxes at higher Illinois corporate tax rates

•

Financial impacts associated with the planned retirement of fossil generating units

•

Other unusual items

•

Significant changes to GAAP

First Quarter and Recent Highlights

•

U.S. Environmental Protection Agency (EPA) Air Toxics and Cooling Water Rules: On March 16, 2011, the EPA issued a draft air toxics rule under the Clean Air Act, which will require existing and new coal-fired electricity generating plants to reduce emissions of mercury and other hazardous air pollutants. The proposed rule is in line with Exelon’s expectations and provides for facilities to meet the standards by late 2014, with limited exceptions. A public comment period lasts 60 days after the rule is published in the Federal Register. Final action by the EPA is required by November 2011.

On March 28, 2011, the EPA proposed standards to protect fish and other aquatic life under section 316(b) of the Clean Water Act for cooling water systems at large power plants and industrial facilities. The proposed rules address the primary issues in the manner Exelon anticipated; cooling towers are not required as the best technology available for entrainment standards and cost-benefit analysis must be performed. The public comment period lasts 90 days after the rule is published in the Federal Register. A final rule is due by July 2012.

•

Nuclear Operations: On March 11, 2011, Japan experienced a 9.0 magnitude earthquake and ensuing tsunami that seriously damaged the nuclear units at the Fukushima Daiichi plant, which is operated by Tokyo Electric Power Co. Generation is confident its nuclear generating facilities do not have the same operating risks as the Fukushima Daiichi plant because they are designed to withstand extreme environmental hazards, including floods and earthquakes, even though Generation’s plants are not located in significant earthquake zones or in regions where tsunamis are a threat. Generation continues to work with regulators and industry organizations to understand the events in Japan and apply lessons learned. The industry is already taking specific steps to respond. Generation has completed actions requested by the Institute of Nuclear Power Operations (INPO), which include tests that verified its emergency equipment is available and functional, walk-downs on its procedures related to critical safety equipment, and verification of current qualifications of operators and support staff needed to implement the procedures. Generation will continue to engage in industry assessments and actions.

Generation’s nuclear fleet, including its owned output from the Salem Generating Station, produced 35,192 gigawatt-hours (GWh) in the first quarter of 2011, compared with 34,109 GWh in the first quarter of 2010. The Exelon-operated nuclear plants achieved a 94.8 percent capacity

factor for the first quarter of 2011 compared with 92.3 percent for the first quarter of 2010. The Exelon-operated nuclear plants completed one scheduled refueling outage and began two others in the first quarter of 2011, compared with completing three scheduled refueling outages and beginning two others in the first quarter of 2010. Among the planned outages completed in last year’s first quarter was the extended refueling outage at Three Mile Island Unit 1, which included the replacement of steam generators. As a result, the number of refueling outage days totaled 44 in the first quarter of 2011 versus 101 days in the first quarter of 2010. The number of non-refueling outage days at the Exelon-operated plants totaled 14 days in the first quarter of 2011 compared with 5 days in the first quarter of 2010.

•

Nuclear Uprate Program: On April 8, 2011, the U.S. Nuclear Regulatory Commission (NRC) approved Generation’s request to increase the generating capacity of both units of the Limerick Generating Station by 1.65 percent, or 16 megawatts, each. The NRC’s evaluation determined that Generation could safely increase the power output of the units. Exelon plans to implement the uprate for Unit 1 within 90 days of the NRC’s approval and for Unit 2 within 90 days of the completion of its refueling outage on April 24, 2011.

•

Fossil and Hydro Operations: The equivalent demand forced outage rate for Generation’s fossil fleet was 2.3 percent in the first quarter of 2011, compared with 3.8 percent in the first quarter of 2010. The improvement was largely due to approximately the same forced outage hours in the first quarter of 2011 while the fossil units operated more hours, primarily reflecting cold weather in Texas in February. The equivalent availability factor for the hydroelectric facilities was 97.8 percent in the first quarter of 2011, compared with 95.4 percent in the first quarter of 2010. The improvement in 2011 was due to planned inspections that were performed in March 2010.

•

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, 2011 is 93 to 96 percent for 2011, 73 to 76 percent for 2012 and 38 to 41 percent for 2013. The primary objectives of Exelon’s hedging program are to manage market risks and protect the value of its generation and its investment grade balance sheet while preserving its ability to participate in improving long-term market fundamentals.

•

ComEd Electric Distribution Rate Case: On June 30, 2010, ComEd filed a rate increase request with the Illinois Commerce Commission (ICC) to allow the utility to continue modernizing its electric delivery system and recover the cost of substantial investments made since the last rate filing in 2007. In subsequent testimony, ComEd revised its requested revenue increase to $343 million, reflecting certain adjustments to its original request of $396 million. On April 1, 2011, the Administrative Law Judges issued a proposed order, which recommends a $152 million increase. After an 11-month proceeding with input from all stakeholders, the ICC is expected to issue its decision about any increase in rates in late May 2011.

•

Illinois Proposed Energy Infrastructure and Modernization Act: On February 8, 2011, legislation (House Bill 14) was introduced in the Illinois General Assembly that would

modernize Illinois’ electric grid. The proposal includes a policy-based approach which would provide a more predictable ratemaking system and would enable utilities to modernize the electric grid and set the stage for fostering economic development while creating and retaining jobs. The proposed legislation includes a process for determining formula rates that would provide for the recovery of actual costs of service that are prudent and reasonable. On April 14, 2011, House Bill 14 was unanimously passed out of the Illinois House Public Utilities Committee subject to the commitment that there would be further negotiations with stakeholders. The current legislative session is scheduled to adjourn at the end of May 2011.

•

Financing Activities: On March 23, 2011, Exelon Corporate, Generation and PECO replaced their unsecured revolving credit facilities with new facilities with aggregate bank commitments of $500 million, $5.3 billion and $600 million, respectively. These credit facilities expire on March 23, 2016, unless extended. On March 25, 2010, ComEd had replaced its $952 million credit facility with a similar $1 billion unsecured revolving credit facility that expires on March 25, 2013, unless extended.

OPERATING COMPANY RESULTS

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

First quarter 2011 net income was $495 million compared with $561 million in the first quarter of 2010. First quarter 2011 net income included (all after tax) mark-to-market losses of $89 million from economic hedging activities, a non-cash charge of $21 million to remeasure deferred taxes at higher Illinois corporate tax rates, unrealized gains of $24 million related to NDT fund investments and costs of $16 million associated with the planned retirement of certain fossil generating units. First quarter 2010 net income included (all after tax) mark-to-market gains of $142 million from economic hedging activities, 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. Excluding the effects of these items, Generation’s net income in the first quarter of 2011 increased $163 million compared with the same quarter in 2010 primarily due to:

•

The impact on energy gross margin of higher realized energy prices in the Mid-Atlantic region due to the expiration of the PPA with PECO, favorable capacity pricing primarily related to RPM and increased nuclear volume largely reflecting fewer outage days.

The increase in net income was partially offset by:

•

Increased depreciation expense;

•

The impact on energy gross margin of higher nuclear fuel costs; and

•

Higher interest expense.

Generation’s average realized margin on all electric sales, including sales to affiliates and excluding trading activity, was $44.30 per MWh in the first quarter of 2011 compared with $37.26 per MWh in the first quarter of 2010.

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

ComEd recorded net income of $69 million in the first quarter of 2011, compared with net income of $116 million in the first quarter of 2010. First quarter net income in 2011 included an after-tax non-cash charge of $4 million to remeasure deferred taxes at higher Illinois corporate tax rates. 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 effects of these items, ComEd’s net income in the first quarter of 2011 was down $56 million from the same quarter in 2010 primarily reflecting:

•

The credit in 2010 for the recovery of uncollectible accounts expense; and

•

The recording of an estimated refund obligation as a result of the September 2010 Illinois Appellate Court ruling regarding ComEd’s 2007 rate case.

In the first quarter of 2011, heating degree-days in the ComEd service territory were up 7.1 percent relative to the same period in 2010 and were 3.9 percent above normal. As a result, ComEd’s total retail electric deliveries increased 1.2 percent quarter over quarter.

Weather-normalized retail electric deliveries decreased 0.1 percent in the first quarter of 2011, primarily reflecting a decrease in deliveries to residential customers. For ComEd, weather had a favorable after-tax effect of $3 million on first quarter 2011 earnings relative to 2010 and a favorable after-tax effect of $2 million relative to normal weather that is incorporated in Exelon’s earnings guidance.

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

PECO’s net income in the first quarter of 2011 was $126 million, up from $101 million in the first quarter of 2010. 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 effect of this item, PECO’s net income in the first quarter of 2011 was up $15 million from the same quarter in 2010 primarily reflecting:

•

The effect of new electric and gas distribution rates effective January 2011; and

•

Lower interest expense on long-term debt.

The increase in net income was partially offset by the effect of CTC recoveries in 2010, net of amortization expense, associated with PECO’s transition period, which ended on December 31, 2010.

In the first quarter of 2011, heating degree-days in the PECO service territory were up 3.9 percent from 2010 and were close to normal. Total retail electric deliveries were down 0.6 percent from last year, primarily reflecting a decrease in deliveries to large commercial and industrial customers. On the retail gas side, deliveries in the first quarter of 2011 were up 4.2 percent from the first quarter of 2010, largely driven by the effects of colder weather conditions compared with last year.

Weather-normalized retail electric deliveries were down 1.1 percent in the first quarter of 2011, primarily reflecting a decline in large commercial and industrial deliveries. Weather-normalized retail gas deliveries were up 0.7 percent in the first quarter of 2011. For PECO, weather had a favorable after-tax effect of $4 million on first quarter 2011 earnings relative to 2010 and an unfavorable after-tax effect of $2 million relative to normal weather that is incorporated in Exelon’s earnings guidance.

Adjusted (non-GAAP) Operating Earnings

Adjusted (non-GAAP) operating earnings, which generally exclude significant one-time charges or credits that are not normally associated with ongoing operations, mark-to-market adjustments from economic hedging activities and unrealized gains and losses from NDT fund investments, are provided as a supplement to results reported in accordance with GAAP. Management uses such adjusted (non-GAAP) operating earnings measures internally to evaluate the company’s performance and manage its operations. Reconciliation of GAAP to adjusted (non-GAAP) operating earnings for historical periods is attached. Additional earnings release attachments, which include the 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 27, 2011.

Conference call information: Exelon has scheduled a conference call for 11:00 AM ET (10:00 AM CT) on April 27, 2011. The call-in number in the U.S. and Canada is 800-690-3108, and the international call-in number is 973-935-8753. If requested, the conference ID number is 58390808. 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 2010 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 2011 Quarterly Report on Form 10-Q (to be filed on April 27, 2011) in (a) Part II, Other Information, ITEM 1A. Risk Factors, (b) Part 1, Financial Information, ITEM 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations and (c) Part I, Financial Information, ITEM 1. Financial Statements: Note 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 more than $18 billion in annual

revenues. The company has one of the industry’s largest portfolios of electricity generation capacity,

with a nationwide reach and strong positions in the Midwest and Mid-Atlantic. Exelon distributes

electricity to approximately 5.4 million customers in northern Illinois and southeastern Pennsylvania

and natural gas to approximately 490,000 customers in the Philadelphia area. Exelon is

headquartered in Chicago and trades on the NYSE under the ticker EXC.

Earnings Release Attachments

Table of Contents


Consolidating Statements of Operations - Three Months Ended March 31, 2011 and 2010			10

Business Segment Comparative Statements of Operations - Generation and ComEd - Three Months Ended March 31, 2011 and 2010			11

Business Segment Comparative Statements of Operations - PECO and Other - Three Months Ended March 31, 2011 and 2010			12

Consolidated Balance Sheets - March 31, 2011 and December 31, 2010			13

Consolidated Statements of Cash Flows - Three Months Ended March 31, 2011 and 2010			14

Reconciliation of Adjusted (non - GAAP) Operating Earnings to GAAP Consolidated Statements of Operations - Exelon-Three Months Ended March 31, 2011 and 2010			15

Reconciliation of Adjusted (non-GAAP) Operating Earnings to GAAP Earnings By Business Segment - Three Months Ended March 31, 2011 and 2010			16

Reconciliation of Adjusted (non-GAAP) Operating Earnings to GAAP Consolidated Statements of Operations - Generation - Three Months Ended March 31, 2011 and 2010			18

Reconciliation of Adjusted (non-GAAP) Operating Earnings to GAAP Consolidated Statements of Operations - ComEd - Three Months Ended March 31, 2011 and 2010			19

Reconciliation of Adjusted (non-GAAP) Operating Earnings to GAAP Consolidated Statements of Operations - PECO - Three Months Ended March 31, 2011 and 2010			20

Reconciliation of Adjusted (non-GAAP) Operating Earnings to GAAP Consolidated Statements of Operations - Other - Three Months Ended March 31, 2011 and 2010			21

Exelon Generation Statistics-Three Months Ended March 31, 2011, December 31, 2010, September 30, 2010, June 30, 2010 and March 31, 2010			22

ComEd Statistics - Three Months Ended March 31, 2011 and 2010			23

PECO Statistics - Three Months Ended March 31, 2011 and 2010			24

EXELON CORPORATION

Consolidating Statements of Operations

(unaudited)

(in millions)


	Three Months Ended March 31, 2011
	Generation			ComEd			PECO			Other			Exelon Consolidated
Operating revenues	$	2,739		$	1,466		$	1,153		$	(306	)	$	5,052
Operating expenses
Purchased power		549			789			451			(304	)		1,485
Fuel		430			—			182			—			612
Operating and maintenance		754			248			186			(3	)		1,185
Operating and maintenance for regulatory required programs(a)		—			18			20			—			38
Depreciation and amortization		139			134			48			6			327
Taxes other than income		66			77			56			4			203

Total operating expenses		1,938			1,266			943			(297	)		3,850

Operating income (loss)		801			200			210			(9	)		1,202

Other income and deductions
Interest expense		(45	)		(85	)		(34	)		(17	)		(181	)
Other, net		75			4			6			8			93

Total other income and deductions		30			(81	)		(28	)		(9	)		(88	)

Income (loss) before income taxes		831			119			182			(18	)		1,114
Income taxes		336			50			56			4			446

Net income (loss)	$	495		$	69		$	126		$	(22	)	$	668


	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 (loss)		916			291			194			1			1,402

Other income and deductions
Interest expense		(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

(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.

EXELON CORPORATION

Business Segment Comparative Statements of Operations

(unaudited)

(in millions)


	Generation
	Three Months Ended March 31,
	2011			2010			Variance
Operating revenues	$	2,739		$	2,421		$	318
Operating expenses
Purchased power		549			208			341
Fuel		430			391			39
Operating and maintenance		754			740			14
Depreciation and amortization		139			109			30
Taxes other than income		66			57			9

Total operating expenses		1,938			1,505			433

Operating income		801			916			(115	)

Other income and deductions
Interest expense		(45	)		(35	)		(10	)
Other, net		75			79			(4	)

Total other income and deductions		30			44			(14	)

Income before income taxes		831			960			(129	)
Income taxes		336			399			(63	)

Net income	$	495		$	561		$	(66	)


	ComEd
	Three Months Ended March 31,
	2011			2010			Variance
Operating revenues	$	1,466		$	1,415		$	51
Operating expenses
Purchased power		789			753			36
Operating and maintenance		248			159			89
Operating and maintenance for regulatory required programs(a)		18			19			(1	)
Depreciation and amortization		134			130			4
Taxes other than income		77			63			14

Total operating expenses		1,266			1,124			142

Operating income		200			291			(91	)

Other income and deductions
Interest expense		(85	)		(84	)		(1	)
Other, net		4			3			1

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

Income before income taxes		119			210			(91	)
Income taxes		50			94			(44	)

Net income	$	69		$	116		$	(47	)

(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.

EXELON CORPORATION

Business Segment Comparative Statements of Operations

(unaudited)

(in millions)


	PECO
	Three Months Ended March 31,
	2011			2010			Variance
Operating revenues	$	1,153		$	1,455		$	(302	)
Operating expenses
Purchased power		451			524			(73	)
Fuel		182			211			(29	)
Operating and maintenance		186			181			5
Operating and maintenance for regulatory required programs(a)		20			8			12
Depreciation and amortization		48			265			(217	)
Taxes other than income		56			72			(16	)

Total operating expenses		943			1,261			(318	)

Operating income		210			194			16

Other income and deductions
Interest expense		(34	)		(45	)		11
Other, net		6			4			2

Total other income and deductions		(28	)		(41	)		13

Income before income taxes		182			153			29
Income taxes		56			52			4

Net income	$	126		$	101		$	25


	Other(b)
	Three Months Ended March 31,
	2011			2010			Variance
Operating revenues	$	(306	)	$	(830	)	$	524
Operating expenses
Purchased power		(304	)		(827	)		523
Fuel		—			(1	)		1
Operating and maintenance		(3	)		(18	)		15
Depreciation and amortization		6			10			(4	)
Taxes other than income		4			5			(1	)

Total operating expenses		(297	)		(831	)		534

Operating loss		(9	)		1			(10	)

Other income and deductions
Interest expense		(17	)		(19	)		2
Other, net		8			7			1

Total other income and deductions		(9	)		(12	)		3

Loss before income taxes		(18	)		(11	)		(7	)
Income taxes		4			18			(14	)

Net loss	$	(22	)	$	(29	)	$	7

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

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

EXELON CORPORATION

Consolidated Balance Sheets

(unaudited)

(in millions)


	March 31, 2011			December 31, 2010
ASSETS
Current assets
Cash and cash equivalents	$	487		$	1,612
Restricted cash and investments		22			30
Accounts receivable, net
Customer		1,800			1,932
Other		547			1,196
Mark-to-market derivative assets		462			487
Inventories, net
Fossil fuel		122			216
Materials and supplies		606			590
Deferred income taxes		90			—
Regulatory assets		87			10
Other		436			325

Total current assets		4,659			6,398

Property, plant and equipment, net		30,549			29,941
Deferred debits and other assets
Regulatory assets		4,178			4,140
Nuclear decommissioning trust (NDT) funds		6,625			6,408
Investments		740			732
Goodwill		2,625			2,625
Mark-to-market derivative assets		425			409
Pledged assets for Zion Station decommissioning		809			824
Other		766			763

Total deferred debits and other assets		16,168			15,901

Total assets	$	51,376		$	52,240

Liabilities and shareholders’ equity
Current liabilities
Short-term borrowings	$	50		$	—
Short-term notes payable - accounts receivable agreement		225			225
Long-term debt due within one year		1,049			599
Accounts payable		1,331			1,373
Accrued expenses		852			1,040
Deferred income taxes		—			85
Mark-to-market derivative liabilities		37			38
Regulatory liabilities		66			44
Other		561			836

Total current liabilities		4,171			4,240

Long-term debt		11,762			11,614
Long-term debt to financing trusts		390			390
Deferred credits and other liabilities
Deferred income taxes and unamortized investment tax credits		7,215			6,621
Asset retirement obligations		3,546			3,494
Pension obligations		1,516			3,658
Non-pension postretirement benefit obligations		2,251			2,218
Spent nuclear fuel obligation		1,019			1,018
Regulatory liabilities		3,722			3,555
Mark-to-market derivative liabilities		28			21
Payable for Zion Station decommissioning		644			659
Other		1,091			1,102

Total deferred credits and other liabilities		21,032			22,346

Total liabilities		37,355			38,590

Preferred securities of subsidiary		87			87
Shareholders’ equity
Common stock		9,032			9,006
Treasury stock, at cost		(2,327	)		(2,327	)
Retained earnings		9,623			9,304
Accumulated other comprehensive loss, net		(2,397	)		(2,423	)

Total shareholders’ equity		13,931			13,560
Noncontrolling interest		3			3

Total equity		13,934			13,563

Total liabilities and shareholders’ equity	$	51,376		$	52,240

EXELON CORPORATION

Consolidated Statements of Cash Flows

(unaudited)

(in millions)


	Three Months Ended March 31,
	2011			2010
Cash flows from operating activities
Net income	$	668		$	749
Adjustments to reconcile net income to net cash flows provided by (used in) operating activities:
Depreciation, amortization and accretion, including nuclear fuel amortization		552			718
Deferred income taxes and amortization of investment tax credits		340			(4	)
Net fair value changes related to derivatives		148			(233	)
Net realized and unrealized gains on NDT fund investments		(40	)		(36	)
Other non-cash operating activities		223			72
Changes in assets and liabilities:
Accounts receivable		53			40
Inventories		78			67
Accounts payable, accrued expenses and other current liabilities		(526	)		(303	)
Option premiums received, net		19			66
Counterparty collateral received (posted), net		(150	)		477
Income taxes		733			517
Pension and non-pension postretirement benefit contributions		(2,088	)		(98	)
Other assets and liabilities		(217	)		(171	)

Net cash flows provided by (used in) operating activities		(207	)		1,861

Cash flows from investing activities
Capital expenditures		(1,150	)		(878	)
Proceeds from nuclear decommissioning trust fund sales		1,195			909
Investment in nuclear decommissioning trust funds		(1,247	)		(966	)
Change in restricted cash		8			214
Other investing activities		15			12

Net cash flows used in investing activities		(1,179	)		(709	)

Cash flows from financing activities
Changes in short-term debt		50			101
Issuance of long-term debt		599			—
Retirement of long-term debt		(1	)		(1	)
Retirement of long-term debt of variable interest entity		—			(402	)
Dividends paid on common stock		(348	)		(347	)
Proceeds from employee stock plans		8			11
Other financing activities		(47	)		—

Net cash flows provided by (used in) financing activities		261			(638	)

Increase (decrease) in cash and cash equivalents		(1,125	)		514
Cash and cash equivalents at beginning of period		1,612			2,010

Cash and cash equivalents at end of period	$	487		$	2,524

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, 2011									Three Months Ended March 31, 2010
	GAAP (a)			Adjustments			Adjusted Non-GAAP			GAAP (a)			Adjustments			Adjusted Non-GAAP
Operating revenues	$	5,052		$	—		$	5,052		$	4,461		$	3	(g)	$	4,464
Operating expenses
Purchased power		1,485			(95	)(c)		1,390			658			185	(c)		843
Fuel		612			(52	)(c)		560			601			48	(c)		649
Operating and maintenance		1,185			(2	)(d)		1,183			1,062			2	(d)		1,064
Operating and maintenance for regulatory required programs (b)		38			—			38			27			—			27
Depreciation and amortization		327			(24	)(d)		303			514			(15	)(d)		499
Taxes other than income		203			—			203			197			—			197

Total operating expenses		3,850			(173	)		3,677			3,059			220			3,279

Operating income		1,202			173			1,375			1,402			(217	)		1,185

Other income and deductions
Interest expense		(181	)		—			(181	)		(183	)		—			(183	)
Other, net		93			(63	)(e)		30			93			(58	)(e)		35

Total other income and deductions		(88	)		(63	)		(151	)		(90	)		(58	)		(148	)

Income before income taxes		1,114			110			1,224			1,312			(275	)		1,037
Income taxes		446			—	(c),(d),(e),(f)		446			563			(188	)(c),(d),(e)(g),(h)		375

Net income	$	668		$	110		$	778		$	749		$	(87	)	$	662

Effective tax rate		40.0	%					36.4	%		42.9	%					36.2	%
Earnings per average common share
Basic	$	1.01		$	0.16		$	1.17		$	1.13		$	(0.13	)	$	1.00
Diluted	$	1.01		$	0.16		$	1.17		$	1.13		$	(0.13	)	$	1.00

Average common shares outstanding
Basic		662						662			661						661
Diluted		664						664			662						662
Effect of adjustments on earnings per average diluted common share recorded in accordance with GAAP:
Mark-to-market impact of economic hedging activities (c)				$	0.14								$	(0.21	)
Retirement of fossil generating units (d)					0.02									0.01
Unrealized gains related to NDT fund investments (e)					(0.04	)								(0.03	)
Charge resulting from Illinois tax rate change legislation (f)					0.04									—
2007 Illinois electric rate settlement (g)					—									—
Charge resulting from health care legislation (h)					—									0.10

Total adjustments				$	0.16								$	(0.13	)

(a)	Results reported in accordance with GAAP.

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

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

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

(e)	Adjustment to exclude the unrealized gains in 2011 and 2010 associated with Generation’s NDT fund investments and the associated contractual accounting relating to income taxes.

(f)	Adjustment to exclude a one-time, non-cash charge to remeasure deferred taxes at higher corporate tax rates pursuant to the Illinois tax rate change legislation.

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

(h)	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 Earnings (in milllions)

Three Months Ended March 31, 2011 and 2010


	Execlon Earnings per Diluted Share			Generation			ComEd			PECO			Other			Exclon
2010 GAAP Earnings (Loss)	$	1.13		$	561		$	116		$	101		$	(29	)	$	749
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 (1)		(0.03	)		(20	)		—			—			—			(20	)
Non-Cash Charge Resulting From Health Care Legislation (2)		0.10			26			12			10			17			65
Retirement of Fossil Generating Units (3)		0.01			8			—			—			—			8

2010 Adjusted (non-GAAP) Operating Earnings (Loss)		1.00			434			129			111			(12	)		662
Year Over Year Effects on Earnings:
Generation Energy Margins, Excluding Mark-to-Market:
Nuclear Volume (4)		0.04			29			—			—			—			29
Nuclear Fuel Costs (5)		(0.01	)		(8	)		—			—			—			(8	)
Capacity Pricing		0.06			37			—			—			—			37
Market and Portfolio Conditions (6)		0.21			139			—			—			—			139
ComEd and PECO Margins:
Weather		0.01			—			3			4			—			7
Load		(0.01	)		—			(2	)		(3	)		—			(5	)
Other Energy Delivery (7)		0.06			—			2			36			—			38
2010 Competitive Transition Charge (CTC), net (8)		(0.05	)		—			—			(32	)		—			(32	)
Operating and Maintenance Expense:
Labor, Contracting and Materials (9)		(0.07	)		(25	)		(10	)		(10	)		—			(45	)
Planned Nuclear Refueling Outages (10)		0.03			19			—			—			—			19
Pension and Non-Pension Postretirement Benefits (11)		0.01			2			(1	)		1			2			4
2010 Recovery of Bad Debt Expense at ComEd (12)		(0.06	)		—			(36	)		—			—			(36	)
Other Operating and Maintenance		(0.01	)		2			(2	)		4			(8	)		(4	)
Depreciation and Amortization Expense (13)		(0.02	)		(13	)		(2	)		(2	)		3			(14	)
Income Taxes (14)		—			6			2			(3	)		(7	)		(2	)
Interest Expense (15)		0.01			(6	)		(1	)		7			6			6
Other (16)		(0.03	)		(19	)		(9	)		13			(2	)		(17	)

2011 Adjusted (non-GAAP) Operating Earnings (Loss)		1.17			597			73			126			(18	)		778
2011 Adjusted (non-GAAP) Operating Earnings (Loss) Adjustments:
Mark-to-Market Impact of Economic Hedging Activities		(0.14	)		(89	)		—			—			—			(89	)
Unrealized Gains Related to NDT Fund Investments (1)		0.04			24			—			—			—			24
Retirement of Fossil Generating Units (3)		(0.02	)		(16	)		—			—			—			(16	)
Non-Cash Charge Resulting From Illinois Tax Rate Change Legislation (17)		(0.04	)		(21	)		(4	)		—			(4	)		(29	)

2011 GAAP Earnings (Loss)	$	1.01		$	495		$	69		$	126		$	(22	)	$	668

(1)	Reflects the impact of unrealized gains in 2010 and 2011 on NDT fund investments to the extent not offset by contractual accounting as described in the notes to the consolidated financial statements.

(2)	Reflects a 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.

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

(4)	Primarily reflects the impact of decreased planned nuclear outage days in 2011, including Salem.

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

(6)	Primarily reflects the impact of increased realized market prices for the sale of energy in the Mid-Atlantic region due to the end of the PECO Power Purchase Agreement (PPA) and energy margins at Exelon Wind, which was acquired in December 2010.

(7)	Primarily reflects increased distribution revenue at PECO resulting from the 2010 Pennsylvania electric and gas distribution rate cases.

(8)	Reflects the impact of 2010 CTC recoveries, net of amortization expense, associated with PECO’s transition period, which ended on December 31, 2010.

(9)	Primarily reflects the impacts of increased wages and other benefits and increased contracting expenses.

(10)	Primarily reflects the impact of decreased planned nuclear outage days in 2011, excluding Salem.

(11)	Primarily reflects the impact of the $2.1 billion pension contribution made in January 2011, partially offset by the lower assumed discount rate and expected return on plan assets used in 2011 as compared to 2010 to calculate the pension and other postretirement benefit obligations and costs.

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

(13)	Primarily reflects increased depreciation expense across the operating companies, including the impacts of Exelon Wind, due to ongoing capital expenditures.

(14)

Primarily reflects a reduction in Generation’s manufacturing deduction benefits (given reduced taxable income as a result of bonus depreciation), higher corporate tax rates pursuant to the Illinois tax rate change legislation and increased Pennsylvania state tax expense resulting from the expiration of the CTCs and associated tax planning benefits, partially offset by benefits associated with Pennsylvania bonus depreciation and production tax credits at Exelon Wind.

(15)	Reflects lower interest expense at PECO resulting from the retirement of the PECO Energy Transition Trust (PETT) transition bonds on September 1, 2010 and lower outstanding debt at Corporate, partially offset by higher interest expense at Generation and ComEd due to higher outstanding debt.

(16)	Primarily reflects a reduction in realized gains associated with NDT funds at Generation and Illinois electric distribution tax refunds received in 2010 at ComEd, partially offset by decreased gross receipts tax at PECO (completely offset by decreased PECO margins above).

(17)	Reflects the impact of a one-time, non-cash charge to remeasure deferred taxes at higher corporate tax rates pursuant to the Illinois tax rate change legislation.

EXELON CORPORATION

Reconciliation of Adjusted (non-GAAP) Operating Earnings to

GAAP Consolidated Statements of Operations

(unaudited)

(in millions)


	Generation
	Three Months Ended March 31, 2011									Three Months Ended March 31, 2010
	GAAP (a)			Adjustments			Adjusted Non-GAAP			GAAP (a)			Adjustments			Adjusted Non-GAAP
Operating revenues	$	2,739		$	—		$	2,739		$	2,421		$	2	(f)	$	2,423
Operating expenses
Purchased power		549			(95	)(b)		454			208			185	(b)		393
Fuel		430			(52	)(b)		378			391			48	(b)		439
Operating and maintenance		754			(2	)(c)		752			740			(1	)(c),(g)		739
Depreciation and amortization		139			(24	)(c)		115			109			(15	)(c)		94
Taxes other than income		66			—			66			57			—			57

Total operating expenses		1,938			(173	)		1,765			1,505			217			1,722

Operating income		801			173			974			916			(215	)		701

Other income and deductions
Interest expense		(45	)		—			(45	)		(35	)		—			(35	)
Other, net		75			(63	)(d)		12			79			(58	)(d)		21

Total other income and deductions		30			(63	)		(33	)		44			(58	)		(14	)

Income before income taxes		831			110			941			960			(273	)		687
Income taxes		336			8	(b),(c),(d),(e)		344			399			(146	)(b),(c),(d),(f),(g)		253

Net income	$	495		$	102		$	597		$	561		$	(127	)	$	434

(a)	Results reported in accordance with GAAP.

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

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

(d)	Adjustment to exclude the unrealized gains in 2011 and 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.

(e)	Adjustment to exclude a one-time, non-cash charge to remeasure deferred taxes at higher corporate tax rates pursuant to the Illinois tax rate change legislation.

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

(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.

EXELON CORPORATION

Reconciliation of Adjusted (non-GAAP) Operating Earnings to

GAAP Consolidated Statements of Operations

(unaudited)

(in millions)


	ComEd
	Three Months Ended March 31, 2011									Three Months Ended March 31, 2010
	GAAP (a)			Adjustments			Adjusted Non - GAAP			GAAP (a)			Adjustments			Adjusted Non- GAAP
Operating revenues	$	1,466		$	—		$	1,466		$	1,415		$	1	(d)	$	1,416
Operating expenses
Purchased power		789			—			789			753			—			753
Operating and maintenance		248			—			248			159			(3	)(e)		156
Operating and maintenance for regulatory required programs (b)		18			—			18			19			—			19
Depreciation and amortization		134			—			134			130			—			130
Taxes other than income		77			—			77			63			—			63

Total operating expenses		1,266			—			1,266			1,124			(3	)		1,121

Operating income		200			—			200			291			4			295

Other income and deductions
Interest expense		(85	)		—			(85	)		(84	)		—			(84	)
Other, net		4			—			4			3			—			3

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

Income before income taxes		119			—			119			210			4			214
Income taxes		50			(4	)(c)		46			94			(9	)(d),(e)		85

Net income	$	69		$	4		$	73		$	116		$	13		$	129

(a)	Results reported in accordance with GAAP.

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

(c)	Adjustment to exclude a one-time, non-cash charge to remeasure deferred taxes at higher corporate tax rates pursuant to the Illinois tax rate change legislation.

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

(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.

EXELON CORPORATION

Reconciliation of Adjusted (non-GAAP) Operating Earnings to

GAAP Consolidated Statements of Operations

(unaudited)

(in millions)


	PECO
	Three Months Ended March 31, 2011								Three Months Ended March 31, 2010
	GAAP (a)			Adjustments		Adjusted Non- GAAP			GAAP (a)			Adjustments			Adjusted Non- GAAP
Operating revenues	$	1,153		$	—	$	1,153		$	1,455		$	—		$	1,455
Operating expenses
Purchased power		451			—		451			524			—			524
Fuel		182			—		182			211			—			211
Operating and maintenance		186			—		186			181			(2	)(c)		179
Operating and maintenance for regulatory required programs (b)		20			—		20			8			—			8
Depreciation and amortization		48			—		48			265			—			265
Taxes other than income		56			—		56			72			—			72

Total operating expenses		943			—		943			1,261			(2	)		1,259

Operating income		210			—		210			194			2			196

Other income and deductions
Interest expense		(34	)		—		(34	)		(45	)		—			(45	)
Other, net		6			—		6			4			—			4

Total other income and deductions		(28	)		—		(28	)		(41	)		—			(41	)

Income before income taxes		182			—		182			153			2			155
Income taxes		56			—		56			52			(8	)(c)		44

Net income	$	126		$	—	$	126		$	101		$	10		$	111

(a)	Results reported in accordance with GAAP.

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

(c)	Adjustment to exclude a 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, 2011									Three Months Ended March 31, 2010
	GAAP (a)			Adjustments			Adjusted Non- GAAP			GAAP (a)			Adjustments			Adjusted Non- GAAP
Operating revenues	$	(306	)	$	—		$	(306	)	$	(830	)	$	—		$	(830	)
Operating expenses
Purchased power		(304	)		—			(304	)		(827	)		—			(827	)
Fuel		—			—			—			(1	)		—			(1	)
Operating and maintenance		(3	)		—			(3	)		(18	)		8	(c)		(10	)
Depreciation and amortization		6			—			6			10			—			10
Taxes other than income		4			—			4			5			—			5

Total operating expenses		(297	)		—			(297	)		(831	)		8			(823	)

Operating income (loss)		(9	)		—			(9	)		1			(8	)		(7	)

Other income and deductions
Interest expense		(17	)		—			(17	)		(19	)		—			(19	)
Other, net		8			—			8			7			—			7

Total other income and deductions		(9	)		—			(9	)		(12	)		—			(12	)

Loss before income taxes		(18	)		—			(18	)		(11	)		(8	)		(19	)
Income taxes		4			(4	)(b)		—			18			(25	)(c)		(7	)

Net loss	$	(22	)	$	4		$	(18	)	$	(29	)	$	17		$	(12	)

(a)	Results reported in accordance with GAAP.

(b)	Adjustment to exclude a one-time, non-cash charge to remeasure deferred taxes at higher corporate tax rates pursuant to the Illinois tax rate change legislation.

(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

Exelon Generation Statistics


	Three Months Ended
	Mar. 31, 2011			Dec. 31, 2010			Sept. 30, 2010			Jun. 30, 2010			Mar. 31, 2010
Supply (in GWhs)
Nuclear Generation
Mid-Atlantic (a)		12,370			11,974			12,076			11,691			11,776
Midwest		22,822			23,141			23,675			23,344			22,333

Total Nuclear Generation		35,192			35,115			35,751			35,035			34,109
Fossil and Renewables
Mid-Atlantic (b)		2,166			2,115			2,582			2,175			2,564
Midwest		157			45			16			7			—
South and West		509			93			691			310			119

Total Fossil and Renewables		2,832			2,253			3,289			2,492			2,683
Purchased Power
Mid-Atlantic		750			442			599			414			463
Midwest		1,412			1,776			1,774			1,568			1,914
South and West		2,181			2,632			4,084			2,695			2,701

Total Purchased Power		4,343			4,850			6,457			4,677			5,078
Total Supply by Region
Mid-Atlantic		15,286			14,531			15,257			14,280			14,803
Midwest		24,391			24,962			25,465			24,919			24,247
South and West		2,690			2,725			4,775			3,005			2,820

		42,367			42,218			45,497			42,204			41,870


	Three Months Ended
	Mar. 31, 2011			Dec. 31, 2010			Sept. 30, 2010			Jun. 30, 2010			Mar. 31, 2010
Electric Sales (in GWhs)
ComEd (c)		—			—			—			1,895			3,428
PECO		—			9,756			11,976			10,044			10,228
Market and Retail (c)		42,367			32,462			33,521			30,265			28,214

Total Electric Sales (d)		42,367			42,218			45,497			42,204			41,870

Average Margin ($/MWh) (e)(f)(g)
Mid-Atlantic	$	59.92		$	51.75		$	36.97		$	40.83		$	41.41
Midwest		39.60			41.14			41.00			40.78			41.00
South and West		(1.49	)		(10.64	)		(2.30	)		(14.31	)		(16.67	)
Average Margin - Overall Portfolio	$	44.30		$	41.45		$	35.11		$	36.87		$	37.26
Around-the-clock Market Prices ($/MWh) (h)
PJM West Hub	$	45.82		$	43.65		$	52.25		$	43.21		$	44.54
NiHub		34.10			27.26			38.32			32.35			34.47
ERCOT North Spark Spread		8.00			(0.69	)		8.25			1.52			(0.02	)

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

(b)	Includes New England generation.

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

(d)	Total sales do not include trading volume of 1,333 GWhs, 740 GWhs, 1,077 GWhs, 889 GWhs and 920 GWhs for the three months ended March 31, 2011, December 31, 2010, September 30, 2010, June 30, 2010 and March 31, 2010, respectively.

(e)	Excludes retail gas activity, trading portfolio, the $57 million lower of cost or market impairment of certain SO2 allowances and amounts paid related to the Illinois Settlement Legislation.

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

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

(h)	Represents the average for the quarter. Henry Hub prices denominated in $/mmbtu.

EXELON CORPORATION

ComEd Statistics

Three Months Ended March 31, 2011 and 2010


	Electric Deliveries (in GWhs)										Revenue (in millions)
	2011		2010		% Change			Weather- Normal % Change			2011			2010		% Change
Retail Deliveries and Sales (a)
Residential		6,953		6,943		0.1	%		(1.8	)%	$	834		$	778		7.2	%
Small Commercial & Industrial		8,074		7,930		1.8	%		0.6	%		382			387		(1.3	)%
Large Commercial & Industrial		6,819		6,663		2.3	%		1.4	%		90			97		(7.2	)%
Public Authorities & Electric Railroads		330		367		(10.1	)%		(11.5	)%		14			18		(22.2	)%

Total Retail		22,176		21,903		1.2	%		(0.1	)%		1,320			1,280		3.1	%

Other Revenue (b)												146			135		8.1	%

Total Electric Revenue											$	1,466		$	1,415		3.6	%

Purchased Power											$	789		$	753		4.8	%


								% Change
Heating and Cooling Degree-Days	2011		2010		Normal			From 2010			From Normal
Heating Degree-Days		3,332		3,110		3,208			7.1	%		3.9	%

Number of Electric Customers	2011		2010
Residential		3,454,410		3,441,055
Small Commercial & Industrial		364,585		361,370
Large Commercial & Industrial		1,994		1,967
Public Authorities & Electric Railroads		5,004		4,986

Total		3,825,993		3,809,378

(a)

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

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

EXELON CORPORATION

PECO Statistics

Three Months Ended March 31, 2011 and 2010


	Electric and Gas Deliveries									Revenue (in millions)
	2011		2010		% Change			Weather- Normal % Change		2011		2010		% Change
Electric (in GWhs)
Retail Deliveries and Sales (a)
Residential		3,590		3,527		1.8	%		0.5%	$	493	$	473		4.2%
Small Commercial & Industrial		2,139		2,150		(0.5	)%		(1.1)%		169		248		(31.9)%
Large Commercial & Industrial		3,688		3,794		(2.8	)%		(2.7)%		108		324		(66.7)%
Public Authorities & Electric Railroads		242		246		(1.6	)%		(1.6)%		11		23		(52.2)%

Total Retail		9,659		9,717		(0.6	)%		(1.1)%		781		1,068		(26.9)%

Other Revenue (b)											63		61		3.3%

Total Electric Revenue											844		1,129		(25.2)%

Gas (in mmcfs)
Retail Sales		28,734		27,584		4.2	%		0.7%		296		318		(6.9)%
Transportation and Other		8,960		8,617		4.0	%		4.1%		13		8		62.5%

Total Gas		37,694		36,201		4.1	%		1.5%		309		326		(5.2)%

Total Electric and Gas Revenues										$	1,153	$	1,455		(20.8)%

Purchased Power										$	451	$	524		(13.9)%
Fuel										$	182	$	211		(13.7)%

Total Purchased Power and Fuel										$	633	$	735		(13.9)%


							% Change
Heating and Cooling Degree-Davs	2011		2010		Normal		From 2010			From Normal
Heating Degree-Days		2,506		2,411		2,510		3.9	%		(0.2	)%


Number of Electric Customers	2011		2010		Number of Gas Customers	2011		2010
Residential		1,414,103		1,406,614	Residential		449,398		446,440
Small Commercial & Industrial		156,759		156,374	Commercial & Industrial		41,254		41,286

Large Commercial & Industrial		3,096		3,091	Total Retail		490,652		487,726
Public Authorities & Electric Railroads		1,081		1,084	Transportation		857		795

Total		1,575,039		1,567,163	Total		491,509		488,521

(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 distribution. For customers purchasing electricity from PECO, revenue also reflects the cost of energy and transmission.

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

Earnings conference call presentation slides

Earnings Conference Call

Quarter 2011

April 27, 2011

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 2010 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 2011 Quarterly Report on Form 10-Q (to be filed on April 27, 2011) in (a) Part II, Other

Information, ITEM 1A. Risk Factors, (b) Part 1, Financial Information, ITEM 2. Management’s

Discussion

and

Analysis

Financial

Condition

and

Results

Operations

and

(c)

Part

Financial

Information,

ITEM

Financial

Statements:

Note

and

(3)

other

factors

discussed

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

GAAP

earnings.

Please

refer

the

footnotes

the

following

slides

for

reconciliation

non-GAAP cash flows to GAAP cash flows.

2011 Operating Earnings Guidance

2011 Guidance

(2)

ComEd

PECO

Exelon

Generation

Holdco

Exelon

$3.90 -

$4.20

(1)

$0.55 -

$0.65

$0.50 -

$0.60

$2.85 -

$3.05

(1)

Refer

Earnings

Release

Attachments

for

additional

details

and

the

Appendix

for

reconciliation

adjusted

(non-GAAP)

operating

EPS

GAAP

EPS.

(2)

Earnings

guidance

for

OpCos

may

not

add

consolidated

EPS

guidance.

Strong operating and financial

results in first quarter

•

Higher than expected operating EPS of

$1.17 mainly driven by higher

Generation gross margin and PA bonus

depreciation

•

Nuclear capacity factor of 94.8%

Reaffirming 2011 operating earnings

guidance of $3.90 -

$4.20/share

(1)

Key Messages

EPA’s proposed Air Toxics and 316(b) rules largely as

expected

•

Expect final rules to be implemented on time

•

Impact to the industry is manageable

FERC ruling on PJM MOPR defends competitive markets

Exelon’s nuclear plants are safe

•

Continuing to work with NRC and other stakeholders to evaluate

lessons learned and respond to Fukushima event

Pursuing projects to increase value

•

Transmission projects near Clinton and Quad Cities will reduce

congestion

Key Financial Messages

1Q 2011 operating earnings of $1.17/share

(1)

•

Quarter results $0.17/share better than prior year

•

Quarter earnings exceeded guidance as a result of:

Favorable market conditions in the South region driven by weather

Pennsylvania bonus depreciation

Lower O&M cost than expected, primarily timing

Expect to generate $4.3 billion cash from operations in 2011

Expect 2Q 2011 operating earnings of $0.90 -

$1.00/share

(1)

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

Exelon Generation

Operating EPS Contribution

2010

2011

(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.

Outage Days

(2)

1Q10

1Q11

Refueling

101

Non-refueling

$0.66

$0.90

Note: PPA = Power Purchase Agreement

Key Drivers –

1Q11 vs. 1Q10

(1)

Higher margins due to expiration of

the PECO PPA: $0.19

Favorable capacity pricing: $0.06

Nuclear volume: $0.04

Increased depreciation expense:

$(0.02)

Higher nuclear fuel costs: $(0.01)

Higher interest expense: $(0.01)

Power Fundamentals & Hedging Update

Key Drivers –

1Q11 vs. 1Q10

(1)

2010 uncollectible expense rider: $(0.06)

Appellate Court ruling: $(0.01)

ComEd Operating EPS Contribution

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

2010

2011

$0.19

1Q11

Actual

Normal

% Change

Heating Degree-Days 3,332 3,208 3.9%

$0.11

ComEd Load Trends

PECO Operating EPS Contribution

Key Drivers –

1Q11 vs. 1Q10

(1)

Electric and gas distribution rates: $0.05

2010 CTC collections, net of

amortization expense: $(0.05)

Lower interest expense: $0.01

2010

2011

(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

1Q11

$0.19

Actual

Normal

% Change

Heating Degree-Days 2,506 2,510 (0.2)%

Note: CTC = Competitive Transition Charge

PECO Load Trends

2011 Projected Sources and Uses of Cash

(1)

Excludes counterparty collateral activity.

(2)

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

(3)

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

(4)

Includes $450 million in Nuclear Uprates and $225 million for Exelon Wind spend.

(5)

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

(6)

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

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

(7)

“Other”

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

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

Exelon Generation Hedging Disclosures

(as of March 31, 2011)

Important Information

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

Exelon Generation and to serve as an aid for the purposes of modeling Exelon Generation’s gross

margin (operating revenues less purchased power and fuel expense). The information on the following

slides is not intended to represent earnings guidance or a forecast of future events. In fact, many of the

factors that ultimately will determine Exelon Generation’s actual gross margin are based upon highly

variable market factors outside of our control. The information on the following slides is as of March 31,

2011. We update this information on a quarterly basis.

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

assumptions regarding future market conditions, including power and commodity prices, heat rates, and

demand conditions, in addition to operating performance and dispatch characteristics of our generating

fleet. Our simulation model and the assumptions therein are subject to change. For example, actual

market conditions and the dispatch profile of our generation fleet in future periods will likely differ – and

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

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

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

conditions.

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

2011

2012

2013

Estimated Open Gross Margin ($ millions)

(1)(2)

$5,250

$4,900

$5,500

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)

$4.47

$31.32

$44.23

$4.42

$5.06

$31.32

$46.19

$1.88

$5.41

$32.83

$48.10

$2.06

Exelon Generation Open Gross Margin and

Reference Prices

(1)

Based on March 31, 2011 market conditions.

(2)

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

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

assumes

there

hedging

place

other

than

fixed

assumptions

for

capacity

cleared

the

RPM

auctions

and

uranium

costs

for

nuclear

power

plants.

Open

gross

margin

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

2011

2012

2013

Expected Generation

(GWh)

(1)

165,800

165,400

162,800

Midwest

99,000

97,800

96,100

Mid-Atlantic

56,300

57,200

56,400

South & West

10,500

10,400

10,300

Percentage of Expected Generation Hedged

(2)

93-96%

73-76%

38-41%

Midwest

93-96

75-78

35-38

Mid-Atlantic

94-97

72-75

42-45

South & West

76-79

59-62

40-43

Effective Realized Energy Price

($/MWh)

(3)

Midwest

$43.00

$41.00

Mid-Atlantic

$56.50

$50.50

South & West

$4.50

$0.00

($3.00)

Generation Profile

(1)

Expected generation represents the amount of energy estimated to

be generated or purchased through owned or contracted for capacity. Expected generation is based upon a

simulated

dispatch

model

that

makes

assumptions

regarding

future

market

conditions,

which

are

calibrated

market

quotes

for

power,

fuel,

load

following

products,

and

options.

Expected generation assumes 12 refueling outages in 2011 and 10 refueling outages in 2012 and 2013 at Exelon-operated nuclear plants and Salem. Expected generation assumes

capacity factors of 93.0%, 93.6% and 93.1% in 2011, 2012 and 2013 at Exelon-operated nuclear plants. These estimates of expected generation in 2012 and 2013 do not represent

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

(2)

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

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

(3)

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

revenues

and

costs

associated

with

our

hedges

and

considering

the

fossil

fuel

that

has

been

purchased

lock

margin.

excludes

uranium

costs

and

RPM

capacity

revenue,

but

includes

the

mark-to-market

value

capacity

contracted

prices

other

than

RPM

clearing

prices

including

our

load

obligations.

can

compared

with

the

reference

prices

used

calculate open gross margin 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%

2011

$(5)

$15

$(10)

$10

$(10)

+/-

$30

2012

$145

$(65)

$145

$(125)

$90

$(90)

+/-

$45

2013

$425

$(380)

$315

$(310)

$180

$(175)

+/-

$45

Exelon Generation Gross Margin Sensitivities

(with Existing Hedges)

(1)

Based on March 31, 2011 market conditions and hedged position. Gas price sensitivities are based on an assumed gas-power relationship derived from an internal

model

that

updated

periodically.

Power

prices

sensitivities

are

derived

adjusting

the

power

price

assumption

while

keeping

all

other

prices

inputs

constant.

Due

correlation

the

various

assumptions,

the

hedged

gross

margin

impact

calculated

aggregating

individual

sensitivities

may

not

equal

the

hedged

gross margin

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

95% case

5% case

$5,500

$7,100

$6,800

$6,200

Exelon Generation Gross Margin Upside / Risk

(with Existing Hedges)

$3,000

$4,000

$5,000

$6,000

$7,000

$8,000

$9,000

2011

2012

2013

(1)

Represents

approximate

range

expected

gross

margin,

taking

into

account

hedges

place,

between

the

5th

and

95th

percent

confidence

levels

assuming

all

unhedged

supply

sold

into

the

spot

market.

Approximate

gross

margin

ranges

are

based

upon

internal

simulation

model

and

are

subject

change

based

upon

market

inputs,

future

transactions

and

potential

modeling

changes.

These

ranges

approximate

gross

margin

2012

and

2013

not

represent

earnings

guidance

forecast

future

results

Exelon

has

not

completed

its

planning

optimization

processes

for

those

years.

The

price

distributions

that

generate

this

range

are

calibrated

market

quotes

for

power,

fuel,

load

following

products

and

options

March

31,

2011.

$6,900

$4,900

Midwest

Mid-Atlantic

South & West

Step 1

Start with fleetwide open gross margin

$5.25 billion

Step 2

Determine the mark-to-market

value

of energy hedges

99,000GWh * 94% *

($43.00/MWh-$31.32MWh)

= $1.09 billion

56,300GWh * 95% *

($56.50/MWh-$44.23MWh)

= $0.66 billion

10,500GWh * 77% *

($4.50/MWh-$4.42/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: $5.25 billion

MTM value of energy hedges: $1.09billion + $0.66billion + $0.00 billion

Estimated hedged gross margin: $7.00 billion

Illustrative Example

of Modeling Exelon Generation 2011 Gross Margin

(with Existing Hedges)

4/10

5/10

6/10

7/10

8/10

9/10

10/10

11/10

12/10

1/11

2/11

3/11

4/11

4.0

4.5

5.0

5.5

6.0

6.5

7.0

7.5

8.0

4/10

5/10

6/10

7/10

8/10

9/10

10/10

11/10

12/10

1/11

2/11

3/11

4/11

4/10

5/10

6/10

7/10

8/10

9/10

10/10

11/10

12/10

1/11

2/11

3/11

4/11

4/10

5/10

6/10

7/10

8/10

9/10

10/10

11/10

12/10

1/11

2/11

3/11

4/11

Market Price Snapshot

Forward NYMEX Natural Gas

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

PJM-West and Ni-Hub Wrap Forward Prices

2012

$5.26

2013 $5.54

Rolling 12 months, as of April 15th

2011. Source: OTC quotes and electronic trading system. Quotes

are daily.

Forward NYMEX Coal

2012

$77.69

2013

$81.53

2012 Ni-Hub $40.67

2013 Ni-Hub

$42.74

2013 PJM-West $54.38

2012 PJM-West

$52.35

2012 Ni-Hub

$25.20

2013 Ni-Hub

$27.30

2013 PJM-West

$40.85

2012 PJM-West

$38.94

4.5

5.5

6.5

7.5

8.5

9.5

10.5

11.5

12.5

13.5

4/10

5/10

6/10

7/10

8/10

9/10

10/10

11/10

12/10

1/11

2/11

3/11

4/11

8.0

8.2

8.4

8.6

8.8

9.0

9.2

9.4

9.6

9.8

10.0

4/10

5/10

6/10

7/10

8/10

9/10

10/10

11/10

12/10

1/11

2/11

3/11

4/11

4/10

5/10

6/10

7/10

8/10

9/10

10/10

11/10

12/10

1/11

2/11

3/11

4/11

3.5

4.0

4.5

5.0

5.5

6.0

6.5

7.0

7.5

8.0

4/10

5/10

6/10

7/10

8/10

9/10

10/10

11/10

12/10

1/11

2/11

3/11

4/11

Market Price Snapshot

2013

9.35

2012

9.21

2012

$47.30

2013

$50.61

2012

$5.14

2013

$5.42

Houston Ship Channel Natural Gas

Forward Prices

ERCOT North On-Peak Forward Prices

ERCOT North On-Peak v. Houston Ship Channel

Implied Heat Rate

2012

$7.70

2013

$9.02

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 15th

2011. Source: OTC quotes and electronic trading system. Quotes

are daily.

Appendix

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

2011 Events of Interest

RPM Auction results

(5/13)

Illinois Power Agency

RFP (5/16)

ALJ Proposed Order

–

DST Rate Case

(4/1)

Procurement RFP

(bids due 5/2; results

by 5/17)

DST Rate Case Final

Order (by 5/31)

EPA Final Toxics

Rule (November)

Retirement of Cromby

1 & Eddystone 1 units

(5/31)

Proposed Toxics Rule

(3/16)

Procurement RFP

(bids due 9/19;

results by 10/19)

Retirement of

Cromby 2 unit

(12/31)

Proposed 316(b) EPA

Regulation (3/28)

For

definition

the

EPA

regulations

referred

this

slide,

please

see

the

EPA’s

Terms

Environment

(http://www.epa.gov/OCEPAterms/).

EPA Final Transport

Rule (June)

Exelon View on Proposed CWA Sec. 316(b) Rule

EPA Regulations Will Move Forward in 2011

2010

2011

2012

2013

2014

2015

2016

2017

2018

PJM RPM Auction

14/15

15/16

16/17

17/18

Hazardous Air

Pollutants

Criteria

Pollutants

Greenhouse

Gases

Coal

Combustion

By-Products

Cooling Water

Effluents

Develop Toxics Rule

Develop ICI

MACT

Pre Compliance Period

Compliance With Toxics Rule

Pre Compliance Period

Compliance With ICI MACT

Develop

Transport Rule

Compliance With Transport Rule

Interim CAIR

Develop O3

Transport

Rule (TR 2)

Estimated Compliance

Develop Criteria

NSPS revision

Compliance with Revised Criteria NSPS

Develop Revised

NAAQS

SIP provisions developed in response to revised NAAQS

(e.g., Ozone, PM2.5, SO2, NO2, NOx/SOx, CO)

Compliance with Federal GHG Reporting Rule

PSD/BACT and Title V Apply to GHG Emissions (PSD only for new and modified sources)

Develop GHG NSPS

Pre Compliance Period

Compliance With GHG NSPS

Develop Coal Combustion

By-Products Rule

Pre Compliance Period

Compliance With Federal CCB Regulations

Develop 316(b) Regulations

Pre Compliance Period

Phase In Of Compliance

Develop Effluent Regulations

Pre Compliance Period

Phase In Of

Compliance

Notes: RPM auctions take place annually in May.

For

definition

the

EPA

regulations

referred

this

slide,

please

see

the

EPA’s

Terms

Environment

(http://www.epa.gov/OCEPAterms/).

Factors Influencing PJM RPM Capacity Auction

(Comparison of PY 14/15 and PY 13/14 Price Drivers)

Exelon

Price Impact

Cost

Environmental

Upgrades

(1)

Higher Net CONE

(2)

Higher

Net

ACRs

for

Coal

Units

(3)

Import Transmission Limits and Objectives

(muted impact on portfolio revenues due to regional diversification)

NJ CCGT Proposal / PJM Minimum Offer Price Rules

Peak Load

(4)

Demand Response Growth

2014/15 PJM Capacity Auction: Expected

Changes Since Planning Year 2013/14

(1) We expect generators to reflect cost of capital expenditures into their cost based offers at the upcoming auction.

(2) Cost of new entry (CONE) increased by 7.6% (for RTO) and 5.3% to 6.5% (within Locational Deliverability Areas (LDAs)).

(3) Replacing 2007 net revenues with significantly lower 2010 revenues in the Net ACR (avoidable cost rate) calculations for coal generators may increase offer caps for certain

coal

generators

the

auction.

However,

some

coal

units

may

not

affected

due

high

net

revenues

compared

avoidable

costs.

(4) Peak load reduced by approx. 1% in RTO (excluding the impact from Duke Ohio integration).

Note:

RPM

Reliability

Pricing

Model;

CCGT

combined

cycle

gas

turbine

Expect overall results to be similar to last year’s auction

N/A

Exelon’s Nuclear Plants Are Designed to

Withstand Extreme Environmental Hazards

None of Exelon’s plants are in major earthquake zones

Designed

withstand

highest

level

seismic

activity

for

that

location,

with

additional margin

Regular seismic analyses are performed and the NRC reviews new

information on earthquake sources and ground motion models to

determine if changes are necessary

Emergency core cooling systems are protected from water incursion,

including water tight doors, elevation of equipment above potential flood

levels and/or special engineered flood barriers (on a site-specific basis)

Fuel tanks are buried underground or enclosed in buildings

Switchgear for emergency operations are elevated above flood levels

All but one of Exelon’s plants are in Illinois and Pennsylvania

Oyster

Creek

(in

NJ)

than

miles

inland,

behind

barrier

islands

•

Tsunamis are extremely rare in the mid-Atlantic

•

Oyster Creek is 23 feet above sea level, while the maximum recorded

high tide on the Barnegat Bay beachfront 5 miles away is 7 feet above

sea level

The NRC requires all nuclear plants in the US to be able to withstand the most

severe natural phenomena historically reported for each plant’s surrounding

area, with a significant margin for uncertainty

Tsunami

Flood

Earthquake

Exelon Nuclear Fleet Overview -

Plant

Location

Type/

Containment

Water Body

License Extension

Status / License

Expiration

(1)

Ownership

Spent Fuel Storage/

Date to lose full

core discharge

capacity

(2)

Braidwood, IL

(Units 1 and 2)

PWR

Concrete/Steel

Lined

Kankakee

River

Expect to file

application in 2013/

2026, 2027

100%

Dry Cask (Summer

2011)

Byron, IL

(Units 1 and 2)

PWR

Concrete/Steel

Lined

Rock River

Expect to file

application in 2013/

2024, 2026

100%

Dry Cask

Clinton, IL

(Unit 1)

BWR

Concrete/Steel

Lined

Clinton Lake

2026

100%

2018

Dresden, IL

(Units 2 and 3)

BWR

Steel Vessel

Kankakee

River

Renewed / 2029,

2031

100%

Dry cask

LaSalle, IL

(Units 1 and 2)

BWR

Concrete/Steel

Lined

Illinois River

2022, 2023

100%

Dry Cask

Quad Cities, IL

(Units 1 and 2)

BWR

Steel Vessel

Mississippi

River

Renewed / 2032

75% Exelon, 25%

Mid-American

Holdings

Dry cask

(1)

Operating license renewal process takes approximately 4-5 years from commencement until completion of NRC review.

(2)

The date for loss of full core reserve identifies when the on-site storage pool will no longer have sufficient space to receive a full complement of fuel from the

reactor core. Dry cask storage will be in operation at those sites prior to losing full core discharge capacity in their on-site storage pools.

Exelon

pursues

license

extensions

well

advance

expiration

ensure

adequate

time

for review by the NRC

Exelon Nuclear Fleet Overview –

PA and NJ

Plant, Location

Type,

Containment

Water Body

License

Extension Status /

License

Expiration

(1)

Ownership

Spent Fuel Storage/

Date to lose full

core discharge

capacity

(2)

Limerick, PA

(Units 1 and 2)

BWR

Concrete/Steel

Lined

Schuylkill

River

Expect to file

application in 2011/

2024, 2029

100%

Dry cask

Oyster Creek, NJ

(Unit 1)

BWR

Steel Vessel

Barnegat Bay

Renewed / 2029

(3)

100%

Dry cask

Peach Bottom, PA

(Units 2 and 3)

BWR

Steel Vessel

Susquehanna

River

Renewed / 2033,

2034

50% Exelon,

50% PSEG

Dry cask

TMI, PA (Unit 1)

PWR

Concrete/Steel

Lined

Susquehanna

River

Renewed / 2034

100%

2023

Salem, NJ (Units 1

and 2)

PWR

Concrete/Steel

Lined

Delaware

River

In process

(decision in 2011-

2012) / 2016, 2020

42.6% Exelon,

57.4% PSEG

Dry Cask

(1)

Operating license renewal process takes approximately 4-5 years from commencement until completion of NRC review.

(2)

The date for loss of full core reserve identifies when the on-site storage pool will no longer have sufficient space to receive a full complement of fuel from the

reactor core. Dry cask storage will be in operation at those sites prior to losing full core discharge capacity in their on-site storage pools.

(3)

On December 8, 2010, Exelon announced that Generation will permanently cease generation operations at Oyster Creek by December 31, 2019. The current

NRC license for Oyster Creek expires in 2029.

Exelon

pursues

license

extensions

well

advance

expiration

ensure

adequate

time

for review by the NRC

ComEd 2010 Rate Case Update

ComEd Reply Brief (2/23/11)

$343M increase requested

11.50% ROE / 47.28% equity ratio

Rate base $7,349M

2009 test year with pro forma plant additions through 6/30/11

ICC Staff Reply Brief Position (2/23/11)

$113M increase proposed

10.00% ROE / 47.11% equity ratio

Rate base $6,480M

Pro forma plant additions and depreciation reserve through 12/31/10

ALJ Proposed Order (4/1/11)

$152M increase proposed (after correcting ~$14M calculation error)

10.50% ROE / 47.28% equity ratio

Rate base $6,629M

Pro forma plant additions and depreciation reserve through 12/31/10 with very limited exceptions

(ICC Docket No. 10-0467)

Illinois Commerce Commission Final Order will be issued by May 31

ComEd –

Proposed Infrastructure

Investment and Modernization Legislation

Proposed Grid Modernization

Legislation Key Concepts

Incremental investment of $2.6B of capital

over 10 years

•

$1.5B smart grid/smart meter

•

$1.1B infrastructure improvements

Incorporates an annual formula rate

proceeding, similar to FERC Transmission

rate

•

Protocols clarify treatment of several

significant items, including pension costs

and pension asset

•

ROE formula based on average 30-year

Treasury yield

Reduces proceeding timeframe from 11

months to less than 9 months

ComEd is driving innovative regulatory and legislative strategy to benefit customers,

improve the transparency of the ratemaking process and enable economic development

PECO Procurement Plan

(1)

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

(2)

For Large C&I customers who previously opted to participate in the 2011 fixed-priced full requirements product.

(3)

Large C&I tranches which were not fully subscribed in the fall 2010 procurement

Customer Class

Products

Residential

75% full requirements

20% block energy

5% energy only spot

Small Commercial

(peak demand <100 kW)

90% full requirements

10% full requirements spot

Medium Commercial

(peak demand >100 kW but

<= 500 kW)

85% full requirements

15% full requirements spot

Large Commercial &

Industrial (peak demand

>500 kW)

Fixed-Priced Full

requirements

(2)

Hourly Full requirements

PECO Procurement Plan

(1)

Residential

80 MW of baseload (24x7) block energy product (for Jan-Dec 2012)

70 MW of Jun-Aug 2011 summer on-peak block energy product

40 MW of Dec 2011-Feb 2012 winter on-peak block energy product

Large

Commercial

and

Industrial

Hourly

36%

Hourly

Full

requirements

product

(Jun

2011-May

2012)

(3)

May 2, 2011 RFP -

Fifth in a series

of nine procurements for the PUC-

approved Default Service Plan

Spring 2011 RFP to be held on May 2, 2011, with results public 15 days thereafter

ComEd Customer Usage Breakdown

PECO Customer Usage Breakdown

Sufficient Liquidity

(1) Excludes 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.

Key Credit Metrics

0.0x

2.0x

4.0x

6.0x

8.0x

10.0x

12.0x

2009A

2010A

2011E

ExGen/Corp

ComEd

PECO

Exelon

10%

15%

20%

25%

30%

35%

40%

45%

50%

2009A

2010A

2011E

ExGen/Corp

ComEd

PECO

Exelon

FFO / Debt

(1)

See slide 40 for reconciliations to GAAP.

(2)

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

(3)

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

Moody’s

Credit

Ratings

(2)

S&P

Credit

Ratings

(2)

Fitch

Credit

Ratings

(2)

FFO / Debt

Target

Range

(2)

Exelon:

Baa1

BBB-

BBB+

ComEd:

Baa1

A-

BBB+

15-18%

PECO:

A-

15-18%

Generation:

BBB

BBB+

30-35%

(3)

Interest Coverage

(1)

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%

2009A

2010A

2011E

ExGen/Corp

ComEd

PECO

Exelon

Debt / Cap

(1)

Exelon Consolidated Metric Calculations and Ratios

Exelon 2010 YE Adjustments

FFO Calculation

2010 YE

Source - 2010 Form 10-K (.pdf version)

Net Cash Flows provided by Operating Activities

5,244

Pg 159 - Stmt. of Cash Flows

+/- Change in Working Capital

644

Pg 159 - Stmt. of Cash Flows

(1)

- PECO Transition Bond Principal Paydown

(392)

Pg 174 - Stmt. of Cash Flows

(2)

+ PPA Depreciation Adjustment

207

Pg 295 - Commitments and Contingencies

(3)

+/- Pension/OPEB Contribution Normalization

448

Pg 268-269 - Post-retirement Benefits

(4)

+ Operating Lease Depreciation Adjustment

Pg 299 - Commitments and Contingencies

(5)

+/- Decommissioning activity

(143)

Pg 159- Stmt. of Cash Flows

+/- Other Minor FFO Adjustments

(6)

(54)

= FFO (a)

5,989

Debt Calculation

Long-term Debt (incl. Current Maturities and A/R agreement)

12,828

Pg 161 - Balance Sheet

Short-term debt (incl. Notes Payable / Commercial Paper)

Pg 161 - Balance Sheet

- PECO Transition Bond Principal Paydown

N/A - no debt outstanding at year-end

+ PPA Imputed Debt

1,680

Pg 295 - Commitments and Contingencies

(7)

+ Pension/OPEB Imputed Debt

3,825

Pg 268 - Post-retirement benefits

(8)

+ Operating Lease Imputed Debt

428

Pg 299 - Commitments and Contingencies

(9)

+ Asset Retirement Obligation

Pg 261-267 - Asset Retirement Obligations

(10)

+/- Other Minor Debt Equivalents

(11)

= Adjusted Debt (b)

18,845

Interest Calculation

Net Interest Expense

817

Pg 158 - Statement of Operations

- PECO Transition Bond Interest Expense

(22)

Pg 182 - Significant Accounting Policies

+ Interest on Present Value (PV) of Operating Leases

Pg 299 - Commitments and Contingencies

(12)

+ Interest on PV of Purchased Power Agreements (PPAs)

Pg 295 - Commitments and Contingencies

(13)

+/- Other Minor Interest Adjustments

(14)

= Adjusted Interest (c)

960

Equity Calculation

Total Equity

13,563

Pg 161 - Balance Sheet

+ Preferred Securities of Subsidaries

Pg 161 - Balance Sheet

+/- Other Minor Equity Equivalents

(15)

111

= Adjusted Equity (d)

13,761

(1)

Includes changes in A/R, Inventories, A/P and other accrued expenses, option premiums,

counterparty collateral and income taxes. Impact to FFO is opposite of impact to cash flow

(2)

Reflects retirement of variable interest entity + change in restricted cash

(3)

Reflects

net

capacity

payment

–

interest

PPAs

(using

weighted

average

cost

debt)

(4)

Reflects

employer

contributions

–

(service

costs

interest

costs

expected

return

assets),

net

taxes at 35%

(5)

Reflects

operating

lease

payments

–

interest

future

operating

lease

payments

(using

weighted average cost of debt)

(6)

Includes AFUDC / capitalized interest

(7)

Reflects PV of net capacity purchases (using weighted average cost of debt)

$ in millions

(8)

Reflects unfunded status, net of taxes at 35%

(9)

Reflects PV of minimum future operating lease payments (using weighted average cost of debt)

(10)

Nuclear decommissioning trust fund balance > asset retirement obligation. No debt imputed

(11)

Includes accrued interest less securities qualifying for hybrid treatment (50% debt / 50% equity)

(12)

Reflects interest on PV of minimum future operating lease payments (using weighted average cost

of debt)

(13)

Reflects interest on PV of PPAs (using weighted average cost of debt)

(14)

Includes

AFUDC

capitalized

interest

and

interest

securities

qualifying

for

hybrid

treatment

(50%

debt / 50% equity)

(15)

Includes interest on securities qualifying for hybrid treatment (50% debt / 50% equity)

FFO / Debt Coverage =

FFO (a)

Adjusted Debt (b)

FFO Interest Coverage =

FFO (a) + Adjusted Interest (c)

Adjusted Interest (c)

Adjusted Capitalization (e) =

Adjusted Debt (b) + Adjusted Equity (d)

32,606

Rating Agency Debt Ratio =

Adjusted Debt (b)

Adjusted Capitalization (e)

32%

7.2x

58%

2010A Credit Metrics

1Q GAAP EPS Reconciliation

Three Months Ended March 31, 2011

ExGen

ComEd

PECO

Other

Exelon

2011 Adjusted (non-GAAP) Operating Earnings (Loss) Per Share

$0.90

$0.11

$0.19

$(0.03)

$1.17

Mark-to-market impact of economic hedging activities

(0.14)

Unrealized gains related to nuclear decommissioning trust funds

0.04

Retirement of fossil generating units

(0.02)

Non-cash charge resulting from Illinois tax rate change legislation

(0.03)

(0.01)

(0.04)

1Q 2011 GAAP Earnings (Loss) Per Share

$0.75

$0.10

$0.19

$(0.03)

$1.01

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

Three Months Ended March 31, 2010

ExGen

ComEd

PECO

Other

Exelon

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

$0.66

$0.19

$0.17

$(0.02)

$1.00

Mark-to-market impact of economic hedging activities

0.21

Unrealized gains related to nuclear decommissioning trust funds

0.03

Retirement of fossil generating units

(0.01)

Non-cash charge resulting from health care legislation

(0.04)

(0.02)

(0.10)

1Q 2010 GAAP Earnings (Loss) Per Share

$0.85

$0.17

$0.15

$(0.04)

$1.13

GAAP to Operating Adjustments

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

earnings effects of the following:

•

Mark-to-market adjustments from economic hedging activities

•

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

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

statements

•

Significant impairments of assets, including goodwill

•

Any changes in decommissioning obligation estimates

•

Non-cash charge to remeasure deferred taxes at higher Illinois corporate tax rates

•

Financial impacts associated with the planned retirement of fossil generating units

•

Other unusual items

•

Significant changes to GAAP

Operating

earnings

guidance

assumes

normal

weather

for

remainder

the

year