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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

October 26, 2011

Date of Report (Date of earliest event reported)


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

1-16169	EXELON CORPORATION (a Pennsylvania corporation) 10 South Dearborn Street P.O. Box 805379 Chicago, Illinois 60680-5379 (312) 394-7398	23-2990190

333-85496	EXELON GENERATION COMPANY, LLC (a Pennsylvania limited liability company) 300 Exelon Way Kennett Square, Pennsylvania 19348-2473 (610) 765-5959	23-3064219

1-1839	COMMONWEALTH EDISON COMPANY (an Illinois corporation) 440 South LaSalle Street Chicago, Illinois 60605-1028 (312) 394-4321	36-0938600

000-16844	PECO ENERGY COMPANY (a Pennsylvania corporation) P.O. Box 8699 2301 Market Street Philadelphia, Pennsylvania 19101-8699 (215) 841-4000	23-0970240

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

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

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

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

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

Section 2 – Financial Information

Item 2.02. Results of Operations and Financial Condition.

Section 7 – Regulation FD

Item 7.01. Regulation FD Disclosure.

On October 26, 2011, Exelon Corporation (Exelon) announced via press release its results for the third quarter ended September 30, 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 third 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 October 26, 2011. The call-in number in the U.S. and Canada is 800-690-3108, and the international call-in number is 973-935-8753. If requested, the conference ID number is 15656530. 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 November 9. The U.S. and Canada call-in number for replays is 855-859-2056, and the international call-in number is 404-537-3406. The conference ID number is 15656530

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.

Cautionary Statements Regarding Forward-Looking Information

regulatory approvals required for the merger, or required regulatory approvals may delay the merger or result in the imposition of conditions that could have a material adverse effect on the combined company or cause the companies to abandon the merger; (3) conditions to the closing of the merger may not be satisfied; (4) an unsolicited offer of another company to acquire assets or capital stock of Exelon or Constellation could interfere with the merger; (5) problems may arise in successfully integrating the businesses of the companies, which may result in the combined company not operating as effectively and efficiently as expected; (6) the combined company may be unable to achieve cost-cutting synergies or it may take longer than expected to achieve those synergies; (7) the merger may involve unexpected costs, unexpected liabilities or unexpected delays, or the effects of purchase accounting may be different from the companies’ expectations; (8) the credit ratings of the combined company or its subsidiaries may be different from what the companies expect; (9) the businesses of the companies may suffer as a result of uncertainty surrounding the merger; (10) the companies may not realize the values expected to be obtained for properties expected or required to be divested; (11) the industry may be subject to future regulatory or legislative actions that could adversely affect the companies; and (12) the companies may be adversely affected by other economic, business, and/or competitive factors. Other unknown or unpredictable factors could also have material adverse effects on future results, performance or achievements of Exelon, Constellation or the combined company. Discussions of some of these other important factors and assumptions are contained in Exelon’s and Constellation’s respective filings with the Securities and Exchange Commission (SEC), and available at the SEC’s website at www.sec.gov, including: (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 Third Quarter 2011 Quarterly Report on Form 10-Q (to be filed on October 26, 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 13; (3) Constellation’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 12; and (4) Constellation’s Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2011 in (a) Part II, Other Information, ITEM 1A. Risk Factors and ITEM 5. Other Information, (b) Part I, 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: Notes to Consolidated Financial Statements, Commitments and Contingencies. These risks, as well as other risks associated with the proposed merger, are more fully discussed in the definitive joint proxy statement/prospectus included in the Registration Statement on Form S-4 that Exelon filed with the SEC and that the SEC declared effective on October 11, 2011 in connection with the proposed merger. In light of these risks, uncertainties, assumptions and factors, the forward-looking events discussed in this communication may not occur. Readers are cautioned not to place undue reliance on these forward-looking statements, which speak only as of the date of this communication. Neither Exelon nor Constellation undertake any obligation to publicly release any revision to its forward-looking statements to reflect events or circumstances after the date of this communication.

Additional Information and Where to Find it

In connection with the proposed merger between Exelon and Constellation, Exelon filed with the SEC a Registration Statement on Form S-4 that included the definitive joint proxy statement/prospectus. The Registration Statement was declared effective by the SEC on October 11, 2011. Exelon and Constellation mailed the definitive joint proxy statement/prospectus to their respective security holders on or about October 12, 2011. WE URGE INVESTORS AND SECURITY HOLDERS TO READ THE DEFINITIVE JOINT PROXY STATEMENT/PROSPECTUS AND ANY OTHER RELEVANT DOCUMENTS FILED WITH THE SEC, BECAUSE THEY CONTAIN IMPORTANT INFORMATION about Exelon, Constellation and the proposed merger. Investors and security holders may obtain copies of all documents filed with the SEC free of charge at the SEC’s website, www.sec.gov. In addition, a copy of the definitive joint proxy statement/prospectus may be obtained free of charge from Exelon Corporation, Investor Relations, 10 South Dearborn Street, P.O. Box 805398, Chicago, Illinois 60680-5398, or from

Constellation Energy Group, Inc., Investor Relations, 100 Constellation Way, Suite 600C, Baltimore, MD 21202.

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

October 26, 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 attachments

Exhibit 99.1

LOGO


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

	Kathleen Cantillon
	Corporate Communications
	312-394-7417

Exelon Announces Third Quarter 2011 Results;

Reaffirms Full Year Operating Earnings Guidance Range

CHICAGO (October 26, 2011) – Exelon Corporation (NYSE: EXC) announced third quarter 2011 consolidated earnings as follows:


	Third Quarter
	2011		2010
Adjusted (non-GAAP) Operating Results:
Net Income ($ millions)	$	743	$	739
Diluted Earnings per Share	$	1.12	$	1.11

GAAP Results:
Net Income ($ millions)	$	601	$	845
Diluted Earnings per Share	$	0.90	$	1.27

“We delivered strong quarterly earnings, which were just above our guidance range, despite intense summer storms in both the ComEd and PECO service territories,” said John W. Rowe, chairman and chief executive officer. “Exelon Generation’s performance was exceptional, producing a nuclear fleet capacity factor of 95.8 percent and above normal output from our Texas plants to meet much higher demand due to hot weather. Based on our results through September, we are able to reaffirm our full-year earnings guidance range for 2011 of $4.05 to 4.25 per share.”

Third Quarter Operating Results

As shown in the table above, Exelon’s adjusted (non-GAAP) operating earnings increased to $1.12 per share in the third quarter of 2011 from $1.11 per share in the third quarter of 2010. Earnings in 2011 primarily reflected the following favorable factors:

•

The effect at Exelon Generation Company, LLC (Generation) of higher energy margins due to the expiration of the power purchase agreement (PPA) with PECO and favorable market and portfolio conditions in the South; and

•

The effect of new distribution rates at PECO Energy Company (PECO) and Commonwealth Edison Company (ComEd) effective January 1, 2011 and June 1, 2011, respectively.

These factors were mostly offset by:

•

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

•

Increased storm-related costs in the ComEd and PECO service territories;

•

Higher operating and maintenance expenses at Generation, including the impact of increased scheduled nuclear refueling outage days;

•

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

•

Increased depreciation and amortization expense.

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


	(in millions)			(per diluted share)
Unrealized losses related to nuclear decommissioning trust (NDT) fund investments to the extent not offset by contractual accounting	$	(76	)	$	(0.12	)
Mark-to-market losses primarily from Generation’s economic hedging activities	$	(55	)	$	(0.08	)
Non-cash gain, net of costs, related to the acquisition of Wolf Hollow	$	23		$	0.03
Asset retirement obligation update	$	(16	)	$	(0.02	)
Certain costs associated with the proposed merger with Constellation Energy Group, Inc. (Constellation)	$	(11	)	$	(0.02	)
Certain costs associated with the acquisition of Antelope Valley Solar Ranch One (AVSR 1)	$	(5	)	$	(0.01	)
Financial impacts associated with the retirement of certain Generation fossil generating units	$	(2	)		—

Adjusted (non-GAAP) operating earnings for the third 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	$	99		$	0.14
Unrealized gains related to NDT fund investments to the extent not offset by contractual accounting	$	60		$	0.09
Impairment of certain emission allowances	$	(35	)	$	(0.05	)
Financial impacts associated with the retirement of certain Generation fossil generating units	$	(14	)	$	(0.02	)
Costs associated with the 2007 Illinois electric rate settlement agreement	$	(3	)		—
Certain costs related to the acquisition of Exelon Wind	$	(1	)		—

2011 Earnings Outlook

Exelon reaffimed its guidance range for 2011 adjusted (non-GAAP) operating earnings of $4.05 to $4.25 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 nuclear decommissioning trust fund investments to the extent not offset by contractual accounting as described in the notes to the consolidated financial statements

•

Significant impairments of assets, including goodwill

•

Changes in decommissioning obligation and asset retirement 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

•

One-time benefits reflecting ComEd’s 2011 distribution rate case order for the recovery of previously incurred costs related to the 2009 restructuring plan and for the passage of Federal health care legislation in 2010

•

Certain costs associated with Exelon’s acquisition of a wind portfolio (now known as Exelon Wind) and AVSR 1, and Exelon’s proposed merger with Constellation

•

Non-cash gain on purchase in connection with the acquisition of Wolf Hollow, net of acquisition costs

•

Non-cash charge remeasurement of income tax uncertainties

•

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

•

Costs associated with the 2007 electric rate settlement agreement

•

Impairment of certain emissions allowances

•

Other unusual items

•

Significant changes to GAAP

Third Quarter and Recent Highlights

•

Constellation Merger Update: Regulatory reviews related to the proposed merger with Constellation continue to move forward on schedule. On August 3, 2011, the proposed merger received regulatory approval from the Public Utility Commission of Texas. The closing of the merger is anticipated in early 2012, dependent upon the receipt of all required approvals, including approval of the shareholders of both companies. The shareholder meetings for both Exelon and Constellation are scheduled for November 17, 2011. In addition, on September 9, 2011, the senior executives were named who will be reporting directly to President and CEO Christopher M. Crane following completion of the Exelon-Constellation merger.

•

Nuclear Operations: Generation’s nuclear fleet, including its owned output from the Salem Generating Station, produced 36,045 gigawatt-hours (GWh) in the third quarter of 2011, compared with 35,751 GWh in the third quarter of 2010. The Exelon-operated nuclear plants achieved a 95.8 percent capacity factor for the third quarter of 2011 compared with 95.4 percent for the third quarter of 2010. The Exelon-operated nuclear plants began two scheduled

refueling outages in the third quarter of 2011, compared with beginning one scheduled refueling outage in the third quarter of 2010. The number of planned refueling outage days totaled 33 in the third quarter of 2011 versus 19 days in the third quarter of 2010. The number of non-refueling outage days at the Exelon-operated plants totaled 3 days in the third quarter of 2011 compared with 19 days in the third quarter of 2010.

•

Fossil and Hydro Operations: The equivalent demand forced outage rate for Generation’s fossil fleet (excluding Wolf Hollow acquisition) was 7.0 percent in the third quarter of 2011, compared with 1.8 percent in the third quarter of 2010. The increase was largely due to an outage at one of the Texas units early in the quarter. The output of Generation’s Texas fleet during the third quarter of 2011 was nearly twice the five-year average for that quarter (excluding Wolf Hollow acquisition). The equivalent availability factor for the hydroelectric facilities decreased to 93.9 percent in the third quarter of 2011, from 94.4 percent in the third quarter of 2010, primarily due to outages brought about by Hurricane Irene.

•

Acquisition of Solar Project: On September 30, 2011, Exelon announced its acquisition of AVSR 1, a 230-megawatt (MW) solar photovoltaic (PV) project under development in northern Los Angeles County, Calif., from First Solar, which developed and will build, operate, and maintain the project. Construction has started, with the first portion of the site expected to come online in late 2012 and full operation planned for late 2013. The project has a 25-year PPA, approved by the California Public Utilities Commission, with Pacific Gas & Electric for the entire output of the plant. Exelon expects to invest up to $713 million in equity in the project through 2013. The U.S. Department of Energy’s Loan Programs Office issued a guarantee for up to $646 million for a non-recourse loan from the Federal Financing Bank to support the financing of the construction of the AVSR 1 facility.

•

Acquisition of Wolf Hollow Power Plant: On August 24, 2011, Exelon completed its previously announced acquisition of Wolf Hollow, a combined-cycle natural gas-fired power plant, adding 720 MW of clean energy to Generation’s portfolio in the competitive Electric Reliability Council of Texas (ERCOT) power market. The purchase price for Wolf Hollow was $305 million, before adjustments for working capital.

•

Hedging Update: Exelon’s hedging program involves the hedging of commodity risk for Exelon’s expected generation, typically on a ratable basis over a three-year period. Expected generation represents the amount of energy estimated to be generated or purchased through owned or contracted-for capacity. The proportion of expected generation hedged as of September 30, 2011 is 97 to 100 percent for 2011, 85 to 88 percent for 2012 and 56 to 59 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.

•

Financing Activities: On September 7, 2011, ComEd issued a total of $600 million of its first mortgage bonds, consisting of $250 million of its First Mortgage 1.95% Bonds, Series 111, due September 1, 2016, and $350 million of its First Mortgage 3.40% Bonds, Series 112, due September 1, 2021. The proceeds of the Bonds will be used by ComEd to refinance three series of variable rate tax-exempt bonds and one series of maturing first mortgage

bonds, and to fund other general corporate purposes.

OPERATING COMPANY RESULTS

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

Third quarter 2011 net income was $386 million compared with $605 million in the third quarter of 2010. Third quarter 2011 net income included (all after tax) unrealized losses of $76 million related to NDT fund investments, mark-to-market losses of $55 million from economic hedging activities, a non-cash gain, net of costs, of $23 million related to the acquisition of Wolf Hollow, costs of $18 million primarily related to an increase in Generation’s decommissioning obligation for spent nuclear fuel at Zion, certain costs of $5 million associated with the acquisition of AVSR 1, certain costs of $3 million associated with the proposed merger with Constellation and net costs of $2 million associated with the retirement of certain fossil generating units. Third quarter 2010 net income included (all after tax) mark-to-market gains of $99 million from economic hedging activities, unrealized gains of $60 million related to NDT fund investments, a charge of $35 million associated with the impairment of certain emission allowances, costs of $14 million associated with the retirement of certain fossil generating units, a charge of $3 million for costs associated with the 2007 Illinois electric rate settlement and a charge of $1 million for certain costs associated with the acquisition of Exelon Wind.

Excluding the effects of these items, Generation’s net income in the third quarter of 2011 increased $23 million compared with the same quarter in 2010. This increase primarily reflected the effect of higher energy margins due to the expiration of the PPA with PECO and favorable market and portfolio conditions in the South, partially offset by:

•

The impact on energy margins of decreased capacity pricing related to RPM for the PJM market and higher nuclear fuel costs;

•

Higher operating and maintenance expenses, including the impact of increased scheduled nuclear refueling outage days;

•

Higher income taxes due to a reduced manufacturing deduction as a result of the transmission and distribution tax repairs deduction; and

•

Increased depreciation and amortization expense.

Generation’s average realized margin on all electric sales, including sales to affiliates and excluding trading activity, was $39.19 per MWh in the third quarter of 2011 compared with $35.11 per MWh in the third quarter of 2010.

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

ComEd recorded net income of $112 million in the third quarter of 2011, compared with net income of $121 million in the third quarter of 2010. Third quarter net income in 2011 included certain after-tax costs of $1 million associated with the proposed merger with Constellation. Excluding the effects of this item, ComEd’s net income in the third quarter of 2011 was down $8 million from the same quarter in 2010, primarily reflecting increased storm-related costs partially offset by the impact of new electric distribution rates effective June 1, 2011.

In the third quarter of 2011, cooling degree-days in the ComEd service territory were down 8.1 percent relative to the same period in 2010 and were 25.8 percent above normal. Total retail electric deliveries decreased 2.9 percent quarter over quarter.

Weather-normalized retail electric deliveries decreased 1.4 percent in the third quarter of 2011 relative to 2010, reflecting a decrease in deliveries to residential and small commercial and industrial customers. For ComEd, weather had an unfavorable after-tax effect of $6 million on third quarter 2011 earnings relative to 2010 and a favorable after-tax effect of $15 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 third quarter of 2011 was $105 million, down from $127 million in the third quarter of 2010. Third quarter net income in 2011 included an after-tax benefit of $2 million reflecting a decrease in PECO’s asset retirement obligations and certain after-tax costs of $1 million associated with the proposed merger with Constellation. Excluding the effects of these items, PECO’s net income in the third quarter of 2011 was down $23 million from the same quarter in 2010, primarily reflecting:

•

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

•

Increased storm-related costs, primarily associated with Hurricane Irene.

Partially offsetting these unfavorable items were:

•

The impact of new electric and gas distribution rates effective January 1, 2011; and

•

Lower income taxes associated with the electric transmission and distribution tax repairs deduction in accordance with newly elected IRS guidance.

In the third quarter of 2011, cooling degree-days in the PECO service territory were down 8.5 percent from 2010 and were 18.1 percent above normal. Total retail electric deliveries were down 2.0 percent from last year. On the retail gas side, deliveries in the third quarter of 2011 were up 4.0 percent from the third quarter of 2010.

Weather-normalized retail electric deliveries were about flat in the third quarter of 2011 relative to 2010, as a decline in both small and large commercial and industrial deliveries was mostly offset by increased deliveries to residential customers. Weather-normalized retail gas deliveries were up 7.2 percent in the third quarter of 2011. For PECO, weather had an unfavorable after-tax effect of $7 million on third quarter 2011 earnings relative to 2010 and a favorable after-tax effect of $12 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 pages 7 and 8, are posted on Exelon’s Web site: www.exeloncorp.com and have been furnished to the Securities and Exchange Commission on Form 8-K on October 26, 2011.

Conference call information: Exelon has scheduled a conference call for 11:00 AM ET (10:00 AM CT) on October 26, 2011. The call-in number in the U.S. and Canada is 800-690-3108, and the international call-in number is 973-935-8753. If requested, the conference ID number is 15656530. 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.)

Cautionary Statements Regarding Forward-Looking Information

Except for the historical information contained herein, certain of the matters discussed in this communication constitute “forward-looking statements” within the meaning of the Securities Act of 1933 and the Securities Exchange Act of 1934, both as amended by the Private Securities Litigation Reform Act of 1995. Words such as “may,” “will,” “anticipate,” “estimate,” “expect,” “project,” “intend,” “plan,” “believe,” “target,” “forecast,” and words and terms of similar substance used in connection with any discussion of future plans, actions, or events identify forward-looking statements. These forward-looking statements include, but are not limited to, statements regarding benefits of the proposed merger of Exelon Corporation (Exelon) and Constellation Energy Group, Inc. (Constellation), integration plans and expected synergies, the expected timing of completion of the transaction, anticipated future financial and operating performance and results, including estimates for growth. These statements are based on the current expectations of management of Exelon and Constellation, as applicable. There are a number of risks and uncertainties that could cause actual results to differ materially from the forward-looking statements included in this communication regarding the proposed merger. For example, (1) the companies may be unable to obtain shareholder approvals required for the merger; (2) the companies may be unable to obtain regulatory approvals required for the merger, or required regulatory approvals may delay the merger or result in the imposition of conditions that could have a material adverse effect on the combined company or cause the companies to abandon the merger; (3) conditions to the closing of the merger may not be satisfied; (4) an unsolicited offer of another company to acquire assets or capital stock of Exelon or Constellation could interfere with the merger; (5) problems may arise in successfully integrating the businesses of the companies, which may result in the combined company not operating as effectively and efficiently as expected; (6) the combined company may be unable to achieve cost-cutting synergies or it may take longer than expected to achieve those synergies; (7) the merger may involve unexpected costs, unexpected liabilities or unexpected delays, or the effects of purchase accounting may be different from the companies’ expectations; (8) the credit ratings of the combined company or its subsidiaries may be different from what the companies expect; (9) the businesses of the companies may suffer as a result of uncertainty surrounding the merger; (10) the companies may not realize the values expected to be obtained for properties expected or required to be divested; (11) the industry may be subject to future regulatory or legislative actions that could adversely affect the companies; and (12) the companies may be adversely affected by other

economic, business, and/or competitive factors. Other unknown or unpredictable factors could also have material adverse effects on future results, performance or achievements of Exelon, Constellation or the combined company. Discussions of some of these other important factors and assumptions are contained in Exelon’s and Constellation’s respective filings with the Securities and Exchange Commission (SEC), and available at the SEC’s website at www.sec.gov, including: (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 Quarterly Report on Form 10-Q for the quarterly period ended September 30, 2011 (to be filed on October 26, 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 13; (3) Constellation’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 12; and (4) Constellation’s Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2011 in (a) Part II, Other Information, ITEM 1A. Risk Factors and ITEM 5. Other Information, (b) Part I, 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: Notes to Consolidated Financial Statements, Commitments and Contingencies. These risks, as well as other risks associated with the proposed merger, are more fully discussed in the definitive joint proxy statement/prospectus included in the Registration Statement on Form S-4 that Exelon filed with the SEC and that the SEC declared effective on October 11, 2011 in connection with the proposed merger. In light of these risks, uncertainties, assumptions and factors, the forward-looking events discussed in this communication may not occur. Readers are cautioned not to place undue reliance on these forward-looking statements, which speak only as of the date of this communication. Neither Exelon nor Constellation undertake any obligation to publicly release any revision to its forward-looking statements to reflect events or circumstances after the date of this communication.

Additional Information and Where to Find it

###

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 September 30, 2011 and 2010			1

Consolidating Statements of Operations - Nine Months Ended September 30, 2011 and 2010			2

Business Segment Comparative Statements of Operations - Generation and ComEd - Three and Nine Months Ended September 30, 2011 and 2010			3

Business Segment Comparative Statements of Operations - PECO and Other - Three and Nine Months Ended September 30, 2011 and 2010			4

Consolidated Balance Sheets - September 30, 2011 and December 31, 2010			5

Consolidated Statements of Cash Flows - Nine Months Ended September 30, 2011 and 2010			6

Reconciliation of Adjusted (non-GAAP) Operating Earnings to GAAP Consolidated Statements of Operations - Exelon - Three Months Ended September 30, 2011 and 2010			7

Reconciliation of Adjusted (non-GAAP) Operating Earnings to GAAP Consolidated Statements of Operations - Exelon - Nine Months Ended September 30, 2011 and 2010			8

Reconciliation of Adjusted (non-GAAP) Operating Earnings to GAAP Earnings By Business Segment - Three Months Ended September 30, 2011 and 2010			9

Reconciliation of Adjusted (non-GAAP) Operating Earnings to GAAP Earnings By Business Segment - Nine Months Ended September 30, 2011 and 2010			10

Reconciliation of Adjusted (non-GAAP) Operating Earnings to GAAP Consolidated Statements of Operations - Generation - Three and Nine Months Ended September 30, 2011 and 2010			11

Reconciliation of Adjusted (non-GAAP) Operating Earnings to GAAP Consolidated Statements of Operations - ComEd - Three and Nine Months Ended September 30, 2011 and 2010			12

Reconciliation of Adjusted (non-GAAP) Operating Earnings to GAAP Consolidated Statements of Operations - PECO - Three and Nine Months Ended September 30, 2011 and 2010			13

Reconciliation of Adjusted (non-GAAP) Operating Earnings to GAAP Consolidated Statements of Operations - Other - Three and Nine Months Ended September 30, 2011 and 2010			14

Exelon Generation Statistics - Three Months Ended September 30, 2011, June 30, 2011, March 31, 2011, December 31, 2010 and September 30, 2010			15

Exelon Generation Statistics - Nine Months Ended September 30, 2011 and 2010			16

ComEd Statistics - Three and Nine Months Ended September 30, 2011 and 2010			17

PECO Statistics - Three and Nine Months Ended September 30, 2011 and 2010			18

EXELON CORPORATION

Consolidating Statements of Operations

(unaudited)

(in millions)


	Three Months Ended September 30, 2011
	Generation			ComEd			PECO			Other (b)			Exelon Consolidated
Operating revenues	$	2,862		$	1,784		$	946		$	(297	)	$	5,295

Operating expenses
Purchased power		680			932			445			(346	)		1,711
Fuel		432			—			19			—			451
Operating and maintenance		790			353			203			8			1,354
Operating and maintenance for regulatory required programs (a)		—			43			16			—			59
Depreciation and amortization		139			135			51			7			332
Taxes other than income		67			78			59			3			207

Total operating expenses		2,108			1,541			793			(328	)		4,114

Operating income (loss)		754			243			153			31			1,181

Other income and deductions
Interest expense		(37	)		(86	)		(34	)		(25	)		(182	)
Other, net		(164	)		16			3			2			(143	)

Total other income and deductions		(201	)		(70	)		(31	)		(23	)		(325	)

Income (loss) before income taxes		553			173			122			8			856
Income taxes		167			61			17			10			255

Net income (loss)	$	386		$	112		$	105		$	(2	)	$	601


	Three Months Ended September 30, 2010
	Generation			ComEd			PECO			Other (b)			Exelon Consolidated
Operating revenues	$	2,655		$	1,918		$	1,495		$	(777	)	$	5,291

Operating expenses
Purchased power		494			1,112			650			(775	)		1,481
Fuel		451			—			23			1			475
Operating and maintenance		649			298			176			(1	)		1,122
Operating and maintenance for regulatory required programs (a)		—			22			15			—			37
Depreciation and amortization		121			126			326			5			578
Taxes other than income		57			81			90			4			232

Total operating expenses		1,772			1,639			1,280			(766	)		3,925

Operating income (loss)		883			279			215			(11	)		1,366

Other income and deductions
Interest expense		(37	)		(82	)		(38	)		(18	)		(175	)
Other, net		192			3			3			8			206

Total other income and deductions		155			(79	)		(35	)		(10	)		31

Income (loss) before income taxes		1,038			200			180			(21	)		1,397
Income taxes		433			79			53			(13	)		552

Net income (loss)	$	605		$	121		$	127		$	(8	)	$	845

(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

Consolidating Statements of Operations

(unaudited)

(in millions)


	Nine Months Ended September 30, 2011
	Generation			ComEd			PECO			Other (b)			Exelon Consolidated
Operating revenues	$	8,147		$	4,694		$	2,942		$	(850	)	$	14,933

Operating expenses
Purchased power		1,801			2,436			1,265			(900	)		4,602
Fuel		1,222			—			241			(1	)		1,462
Operating and maintenance		2,306			846			543			30			3,725
Operating and maintenance for regulatory required programs (a)		—			84			54			—			138
Depreciation and amortization		416			405			150			16			987
Taxes other than income		199			226			165			12			602

Total operating expenses		5,944			3,997			2,418			(843	)		11,516

Operating income (loss)		2,203			697			524			(7	)		3,417

Other income and deductions
Interest expense		(128	)		(257	)		(102	)		(58	)		(545	)
Other, net		(12	)		24			11			28			51

Total other income and deductions		(140	)		(233	)		(91	)		(30	)		(494	)

Income (loss) before income taxes		2,063			464			433			(37	)		2,923
Income taxes		738			169			119			8			1,034

Net income (loss)	$	1,325		$	295		$	314		$	(45	)	$	1,889


	Nine Months Ended September 30, 2010
	Generation			ComEd			PECO			Other (b)			Exelon Consolidated
Operating revenues	$	7,428		$	4,832		$	4,220		$	(2,330	)	$	14,150

Operating expenses
Purchased power		1,251			2,636			1,709			(2,323	)		3,273
Fuel		1,191			—			278			—			1,469
Operating and maintenance		2,081			733			507			(23	)		3,298
Operating and maintenance for regulatory required programs (a)		—			62			36			—			98
Depreciation and amortization		344			386			859			22			1,611
Taxes other than income		175			188			240			12			615

Total operating expenses		5,042			4,005			3,629			(2,312	)		10,364

Operating income (loss)		2,386			827			591			(18	)		3,786

Other income and deductions
Interest expense		(109	)		(300	)		(160	)		(65	)		(634	)
Other, net		138			14			6			20			178

Total other income and deductions		29			(286	)		(154	)		(45	)		(456	)

Income (loss) before income taxes		2,415			541			437			(63	)		3,330
Income taxes		867			295			134			(5	)		1,291

Net income (loss)	$	1,548		$	246		$	303		$	(58	)	$	2,039

(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

Business Segment Comparative Statements of Operations

(unaudited)

(in millions)


	Generation
	Three Months Ended September 30,									Nine Months Ended September 30,
	2011			2010			Variance			2011			2010			Variance
Operating revenues	$	2,862		$	2,655		$	207		$	8,147		$	7,428		$	719

Operating expenses
Purchased power		680			494			186			1,801			1,251			550
Fuel		432			451			(19	)		1,222			1,191			31
Operating and maintenance		790			649			141			2,306			2,081			225
Depreciation and amortization		139			121			18			416			344			72
Taxes other than income		67			57			10			199			175			24

Total operating expenses		2,108			1,772			336			5,944			5,042			902

Operating income		754			883			(129	)		2,203			2,386			(183	)


Other income and deductions
Interest expense		(37	)		(37	)		—			(128	)		(109	)		(19	)
Other, net		(164	)		192			(356	)		(12	)		138			(150	)

Total other income and deductions		(201	)		155			(356	)		(140	)		29			(169	)

Income before income taxes		553			1,038			(485	)		2,063			2,415			(352	)
Income taxes		167			433			(266	)		738			867			(129	)

Net income	$	386		$	605		$	(219	)	$	1,325		$	1,548		$	(223	)


	ComEd
	Three Months Ended September 30,									Nine Months Ended September 30,
	2011			2010			Variance			2011			2010			Variance
Operating revenues	$	1,784		$	1,918		$	(134	)	$	4,694		$	4,832		$	(138	)

Operating expenses
Purchased power		932			1,112			(180	)		2,436			2,636			(200	)
Operating and maintenance		353			298			55			846			733			113
Operating and maintenance for regulatory required programs (a)		43			22			21			84			62			22
Depreciation and amortization		135			126			9			405			386			19
Taxes other than income		78			81			(3	)		226			188			38

Total operating expenses		1,541			1,639			(98	)		3,997			4,005			(8	)

Operating income		243			279			(36	)		697			827			(130	)


Other income and deductions
Interest expense		(86	)		(82	)		(4	)		(257	)		(300	)		43
Other, net		16			3			13			24			14			10

Total other income and deductions		(70	)		(79	)		9			(233	)		(286	)		53

Income before income taxes		173			200			(27	)		464			541			(77	)
Income taxes		61			79			(18	)		169			295			(126	)

Net income	$	112		$	121		$	(9	)	$	295		$	246		$	49

(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 September 30,									Nine Months Ended September 30,
	2011			2010			Variance			2011			2010			Variance
Operating revenues	$	946		$	1,495		$	(549	)	$	2,942		$	4,220		$	(1,278	)

Operating expenses
Purchased power		445			650			(205	)		1,265			1,709			(444	)
Fuel		19			23			(4	)		241			278			(37	)
Operating and maintenance		203			176			27			543			507			36
Operating and maintenance for regulatory required programs (a)		16			15			1			54			36			18
Depreciation and amortization		51			326			(275	)		150			859			(709	)
Taxes other than income		59			90			(31	)		165			240			(75	)

Total operating expenses		793			1,280			(487	)		2,418			3,629			(1,211	)

Operating income		153			215			(62	)		524			591			(67	)

Other income and deductions
Interest expense		(34	)		(38	)		4			(102	)		(160	)		58
Other, net		3			3			—			11			6			5

Total other income and deductions		(31	)		(35	)		4			(91	)		(154	)		63

Income before income taxes		122			180			(58	)		433			437			(4	)
Income taxes		17			53			(36	)		119			134			(15	)

Net income	$	105		$	127		$	(22	)	$	314		$	303		$	11


	Other (b)
	Three Months Ended September 30,									Nine Months Ended September 30,
	2011			2010			Variance			2011			2010			Variance
Operating revenues	$	(297	)	$	(777	)	$	480		$	(850	)	$	(2,330	)	$	1,480
Operating expenses
Purchased power		(346	)		(775	)		429			(900	)		(2,323	)		1,423
Fuel		—			1			(1	)		(1	)		—			(1	)
Operating and maintenance		8			(1	)		9			30			(23	)		53
Depreciation and amortization		7			5			2			16			22			(6	)
Taxes other than income		3			4			(1	)		12			12			—

Total operating expenses		(328	)		(766	)		438			(843	)		(2,312	)		1,469

Operating loss		31			(11	)		42			(7	)		(18	)		11

Other income and deductions
Interest expense		(25	)		(18	)		(7	)		(58	)		(65	)		7
Other, net		2			8			(6	)		28			20			8

Total other income and deductions		(23	)		(10	)		(13	)		(30	)		(45	)		15

Loss before income taxes		8			(21	)		29			(37	)		(63	)		26
Income taxes		10			(13	)		23			8			(5	)		13

Net loss	$	(2	)	$	(8	)	$	6		$	(45	)	$	(58	)	$	13

(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)


	September 30, 2011			December 31, 2010
ASSETS

Current assets
Cash and cash equivalents	$	1,071		$	1,612
Restricted cash and investments		565			30
Accounts receivable, net
Customer		1,685			1,932
Other		930			1,196
Mark-to-market derivative assets		478			487
Inventories, net
Fossil fuel		203			216
Materials and supplies		648			590
Deferred income taxes		183			—
Regulatory assets		31			10
Other		493			325

Total current assets		6,287			6,398

Property, plant and equipment, net		31,882			29,941

Deferred debits and other assets
Regulatory assets		4,381			4,140
Nuclear decommissioning trust (NDT) funds		6,226			6,408
Investments		754			732
Goodwill		2,625			2,625
Mark-to-market derivative assets		300			409
Pledged assets for Zion Station decommissioning		763			824
Other		938			763

Total deferred debits and other assets		15,987			15,901

Total assets	$	54,156		$	52,240

Liabilities and shareholders’ equity

Current liabilities
Short-term borrowings	$	462		$	—
Short-term notes payable - accounts receivable agreement		225			225
Long-term debt due within one year		1,239			599
Accounts payable		1,388			1,373
Accrued expenses		1,053			1,040
Deferred income taxes		—			85
Regulatory liabilities		60			44
Mark-to-market derivative liabilities		52			38
Other		498			836

Total current liabilities		4,977			4,240

Long-term debt		12,175			11,614
Long-term debt to financing trusts		390			390

Deferred credits and other liabilities
Deferred income taxes and unamortized investment tax credits		7,958			6,621
Asset retirement obligations		3,808			3,494
Pension obligations		1,475			3,658
Non-pension postretirement benefit obligations		2,371			2,218
Spent nuclear fuel obligation		1,019			1,018
Regulatory liabilities		3,601			3,555
Mark-to-market derivative liabilities		79			21
Payable for Zion Station decommissioning		604			659
Other		1,253			1,102

Total deferred credits and other liabilities		22,168			22,346

Total liabilities		39,710			38,590

Preferred securities of subsidiary		87			87
Shareholders’ equity
Common stock		9,077			9,006
Treasury stock, at cost		(2,327	)		(2,327	)
Retained earnings		10,146			9,304
Accumulated other comprehensive loss, net		(2,540	)		(2,423	)

Total shareholders’ equity		14,356			13,560
Noncontrolling interest		3			3

Total equity		14,359			13,563

Total liabilities and shareholders’ equity	$	54,156		$	52,240

EXELON CORPORATION

Consolidated Statements of Cash Flows

(unaudited)

(in millions)


	Nine Months Ended September 30,
	2011			2010
Cash flows from operating activities
Net income	$	1,889		$	2,039
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation, amortization and accretion, including nuclear fuel amortization		1,702			2,255
Deferred income taxes and amortization of investment tax credits		1,008			240
Net fair value changes related to derivatives		360			(281	)
Net realized and unrealized losses (gains) on NDT fund investments		90			(49	)
Other non-cash operating activities		703			468
Changes in assets and liabilities:
Accounts receivable		3			(172	)
Inventories		(44	)		(52	)
Accounts payable, accrued expenses and other current liabilities		(400	)		(53	)
Option premiums received (paid), net		59			(101	)
Counterparty collateral received (posted), net		(807	)		289
Income taxes		532			310
Pension and non-pension postretirement benefit contributions		(2,089	)		(740	)
Other assets and liabilities		(89	)		(41	)

Net cash flows provided by operating activities		2,917			4,112

Cash flows from investing activities
Capital expenditures		(2,972	)		(2,382	)
Proceeds from nuclear decommissioning trust fund sales		3,120			2,756
Investment in nuclear decommissioning trust funds		(3,293	)		(2,864	)
Acquisitions		(380	)		—
Change in restricted cash		(532	)		427
Other investing activities		26			26

Net cash flows used in investing activities		(4,031	)		(2,037	)

Cash flows from financing activities
Changes in short-term debt		462			(90	)
Issuance of long-term debt		1,199			1,398
Retirement of long-term debt		(3	)		(827	)
Retirement of long-term debt of variable interest entity		—			(806	)
Dividends paid on common stock		(1,044	)		(1,042	)
Proceeds from employee stock plans		26			34
Other financing activities		(67	)		(17	)

Net cash flows provided by (used in) financing activities		573			(1,350	)

Decrease (increase) in cash and cash equivalents		(541	)		725
Cash and cash equivalents at beginning of period		1,612			2,010

Cash and cash equivalents at end of period	$	1,071		$	2,735

EXELON CORPORATION

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

(unaudited)

(in millions, except per share data)


	Three Months Ended September 30, 2011									Three Months Ended September 30, 2010
	GAAP (a)			Adjustments			Adjusted Non-GAAP			GAAP (a)			Adjustments			Adjusted Non-GAAP
Operating revenues	$	5,295		$	(33	)(c),(d)	$	5,262		$	5,291		$	5	(j)	$	5,296

Operating expenses
Purchased power		1,711			(71	)(e)		1,640			1,481			107	(e)		1,588
Fuel		451			(22	)(c),(e)		429			475			(1	)(e),(k)		474
Operating and maintenance		1,354			(65	(c),(d),(f), )(g),(h)		1,289			1,122			(2	)(c),(g)		1,120
Operating and maintenance for regulatory required programs (b)		59			—			59			37			—			37
Depreciation and amortization		332			(19	)(c)		313			578			(22	)(c)		556
Taxes other than income		207			—			207			232			—			232

Total operating expenses		4,114			(177	)		3,937			3,925			82			4,007

Operating income		1,181			144			1,325			1,366			(77	)		1,289

Other income and deductions
Interest expense		(182	)		—			(182	)		(175	)		—			(175	)
Other, net		(143	)		181	(d),(i)		38			206			(173	)(i)		33

Total other income and deductions		(325	)		181			(144	)		31			(173	)		(142	)

Income before income taxes		856			325			1,181			1,397			(250	)		1,147

						(c),(d),(e),									(c),(e),(g),
Income taxes		255			183	(f),(g),(h),(i)		438			552			(144	)(i),(j),(k)		408

Net income	$	601		$	142		$	743		$	845		$	(106	)	$	739

Effective tax rate		29.8	%					37.1	%		39.5	%					35.6	%

Earnings per average common share
Basic	$	0.91		$	0.21		$	1.12		$	1.28		$	(0.16	)	$	1.12
Diluted	$	0.90		$	0.22		$	1.12		$	1.27		$	(0.16	)	$	1.11

Average common shares outstanding
Basic		663						663			662						662
Diluted		665						665			663						663

Effect of adjustments on earnings per average diluted common share recorded in accordance with GAAP:

Retirement of fossil generating units (c)				$	—								$	0.02
Wolf Hollow acquisition (d)					(0.03	)								—
Mark-to-market impact of economic hedging activities (e)					0.08									(0.14	)
Constellation acquisition costs (f)					0.02									—
Acquisition costs (g)					0.01									—
Asset retirement obligation (h)					0.02									—
Unrealized (gains) losses related to NDT fund investments (i)					0.12									(0.09	)
2007 Illinois electric rate settlement (j)					—									—
Impairment of certain emission allowances (k)					—									0.05

Total adjustments				$	0.22								$	(0.16	)

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

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

(c)	Adjustment to exclude costs associated with the planned retirement of fossil generating units and the impacts of the FERC approved reliability-must-run rate schedule.

(d)	Adjustment to exclude the non-cash bargain purchase gain (negative goodwill) associated with the acquisition of Wolf Hollow, net of acquisition costs.

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

(f)	Adjustment to exclude certain costs associated with Exelon’s proposed acquisition of Constellation Energy Group, Inc. (Constellation).

(g)	Adjustment to exclude certain costs associated with Exelon’s acquisition of Exelon Wind in 2010, and Exelon’s acquisition of Antelope Valley Solar Ranch One (AVSR 1) in 2011.

(h)	Adjustment to exclude the increase in Generation’s decommissioning obligation for spent nuclear fuel at Zion and the decrease in PECO’s asset retirement obligation.

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

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

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

EXELON CORPORATION

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

(unaudited)

(in millions, except per share data)


	Nine Months Ended September 30, 2011									Nine Months Ended September 30, 2010
	GAAP (a)			Adjustments			Adjusted Non-GAAP			GAAP (a)			Adjustments			Adjusted Non-GAAP
Operating revenues	$	14,933		$	(42	)(c),(d)	$	14,891		$	14,150		$	18	(l),(m)	$	14,168

Operating expenses
Purchased power		4,602			(260	)(e)		4,342			3,273			142	(e)		3,415
Fuel		1,462			(106	)(c),(e)		1,356			1,469			74	(e),(n)		1,543
						(c),(d),(f),
Operating and maintenance		3,725			(82	)(g),(h),(i)		3,643			3,298			(1	)(c),(h),(o)		3,297
Operating and maintenance for regulatory required programs (b)		138			—			138			98			—			98
Depreciation and amortization		987			(65	)(c)		922			1,611			(57	)(c)		1,554
Taxes other than income		602			—			602			615			—			615

Total operating expenses		11,516			(513	)		11,003			10,364			158			10,522

Operating income		3,417			471			3,888			3,786			(140	)		3,646


Other income and deductions
Interest expense		(545	)		—			(545	)		(634	)		103	(p)		(531	)
Other, net		51			94	(d),(j)		145			178			(72	)(j),(p)		106

Total other income and deductions		(494	)		94			(400	)		(456	)		31			(425	)

Income before income taxes		2,923			565			3,488			3,330			(109	)		3,221

						(c),(d),(e), (f),(g),(h),									(c),(e),(h), (j),(l),(m),
Income taxes		1,034			235	(i),(j),(k)		1,269			1,291			(127	)(n),(o),(p)		1,164

Net income	$	1,889		$	330		$	2,219		$	2,039		$	18		$	2,057

Effective tax rate		35.4	%					36.4	%		38.8	%					36.1	%

Earnings per average common share
Basic	$	2.85		$	0.50		$	3.35		$	3.08		$	0.02		$	3.10
Diluted	$	2.84		$	0.50		$	3.34		$	3.08		$	0.02		$	3.10

Average common shares outstanding
Basic		663						663			661						661
Diluted		664						664			662						662

Effect of adjustments on earnings per average diluted common share recorded in accordance with GAAP:

Retirement of fossil generating units (c)				$	0.04								$	0.05
Wolf Hollow acquisition (d)					(0.03	)								—
Mark-to-market impact of economic hedging activities (e)					0.34									(0.25	)
Asset retirement obligation (f)					0.02									—
Constellation acquisition costs (g)					0.04									—
Acquisition costs (h)					0.01									—
Recovery of costs pursuant to distribution rate case order (i)					(0.03	)								—
Unrealized (gains) losses related to NDT fund investments (j)					0.07									(0.04	)
Charge resulting from Illinois tax rate change legislation (k)					0.04									—
2007 Illinois electric rate settlement (l)					—									0.01
City of Chicago settlement (m)					—									—
Impairment of certain emission allowances (n)					—									0.05
Charge resulting from health care legislation (o)					—									0.10
Non-cash income tax matters (p)					—									0.10

Total adjustments				$	0.50								$	0.02

(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 costs associated with the planned retirement of fossil generating units and the impacts of the FERC approved reliability-must-run rate schedule.

(d)	Adjustment to exclude the non-cash bargain purchase gain (negative goodwill) associated with the acquisition of Wolf Hollow, net of acquisition costs.

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

(f)	Adjustment to exclude the increase in Generation’s decommissioning obligation for spent nuclear fuel at Zion and the decrease in PECO’s asset retirement obligation.

(g)	Adjustment to exclude certain costs associated with Exelon’s proposed acquisition of Constellation.

(h)	Adjustment to exclude certain costs associated with Exelon’s acquisition of Exelon Wind in 2010 and Exelon’s acquisition of AVSR 1 in 2011.

(i)	Adjustment to exclude one-time benefits for the recovery of previously incurred costs related to the 2009 restructuring plan and for the passage of Federal health care legislation in 2010.

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

(k)	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.

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

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

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

(o)	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.

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

EXELON CORPORATION

Reconciliation of Adjusted (non-GAAP) Operating

Earnings to GAAP Earnings (in millions)

Three Months Ended September 30, 2011 and 2010


	Exelon Earnings per Diluted Share			Generation			ComEd			PECO			Other (a)			Exelon
2010 GAAP Earnings (Loss)	$	1.27		$	605		$	121		$	127		$	(8	)	$	845

2010 Adjusted (non-GAAP) Operating Earnings (Loss) Adjustments:
Mark-to-Market Impact of Economic Hedging Activities		(0.14	)		(99	)		—			—			—			(99	)
Unrealized Gains Related to NDT Fund Investments (1)		(0.09	)		(60	)		—			—			—			(60	)
Impairment of Certain Emission Allowances (2)		0.05			35			—			—			—			35
Retirement of Fossil Generating Units (3)		0.02			14			—			—			—			14
2007 Illinois Electric Rate Settlement		—			3			—			—			—			3
Acquisition Costs (4)		—			1			—			—			—			1

2010 Adjusted (non-GAAP) Operating Earnings (Loss)		1.11			499			121			127			(8	)		739

Year Over Year Effects on Earnings:
Generation Energy Margins, Excluding Mark-to-Market:
Nuclear Volume (5)		0.01			9			—			—			—			9
Nuclear Fuel Costs (6)		(0.02	)		(15	)		—			—			—			(15	)
Capacity Pricing		(0.14	)		(91	)		—			—			—			(91	)
Market and Portfolio Conditions (7)		0.37			249			—			—			—			249
Transmission Upgrades (8)		—			(30	)		—			—			30			—
ComEd and PECO Margins:
Weather		(0.02	)		—			(6	)		(7	)		—			(13	)
Load		—			—			(5	)		1			—			(4	)
Other Energy Delivery (9)		0.07			—			34			13			—			47
2010 Competitive Transition Charge (CTC), Net (10)		(0.08	)		—			—			(51	)		—			(51	)
Operating and Maintenance Expense:
Labor, Contracting and Materials (11)		(0.04	)		(19	)		(6	)		(4	)		—			(29	)
Planned Nuclear Refueling Outages (12)		(0.02	)		(14	)		—			—			—			(14	)
Other Operating and Maintenance (13)		(0.11	)		(19	)		(37	)		(17	)		—			(73	)
Depreciation and Amortization Expense (14)		(0.04	)		(13	)		(6	)		(5	)		—			(24	)
Income Taxes (15)		(0.01	)		(29	)		8			21			(11	)		(11	)
Interest Expense, Net		—			1			5			3			(8	)		1
Other (16)		0.04			(6	)		5			23			1			23

2011 Adjusted (non-GAAP) Operating Earnings (Loss)		1.12			522			113			104			4			743

2011 Adjusted (non-GAAP) Operating Earnings (Loss) Adjustments:
Mark-to-Market Impact of Economic Hedging Activities		(0.08	)		(55	)		—			—			—			(55	)
Unrealized Losses Related to NDT Fund Investments (1)		(0.12	)		(76	)		—			—			—			(76	)
Asset Retirement Obligation (17)		(0.02	)		(18	)		—			2			—			(16	)
Retirement of Fossil Generating Units (3)		—			(2	)		—			—			—			(2	)
Constellation Acquisition Costs (18)		(0.02	)		(3	)		(1	)		(1	)		(6	)		(11	)
Acquisition Costs (4)		(0.01	)		(5	)		—			—			—			(5	)
Wolf Hollow Acquisition (19)		0.03			23			—			—			—			23

2011 GAAP Earnings (Loss)	$	0.90		$	386		$	112		$	105		$	(2	)	$	601

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

(1)	Reflects the impact of unrealized gains in 2010 and unrealized losses in 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 the impairment of certain SO2 emission allowances as a result of declining market prices following the release of the EPA’s proposed Transport Rule in the third quarter of 2010.

(3)

Primarily reflects accelerated depreciation expense associated with the planned retirement of four generating units, two of which retired on May 31, 2011. In 2011, reflects the net loss attributable to the remaining two units, which includes compensation for operating the units past their planned May 31, 2011 retirement date under a FERC-approved reliability-must-run rate schedule.

(4)	For 2010, reflects certain costs incurred associated with the acquisition of Exelon Wind and in 2011 reflects certain costs incurred associated with the acquisition of AVSR 1.

(5)	Primarily reflects the impact of decreased unplanned nuclear outage days in 2011.

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

(7)

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), energy margins at Exelon Wind, which was acquired in December 2010, and other favorable market and portfolio conditions in the South and West region.

(8)	Reflects intercompany expense at Generation for upgrades in transmission assets owned by ComEd, which are reflected as assets at Exelon Corporate.

(9)

For ComEd, primarily reflects increased distribution revenue pursuant to the 2011 electric distribution rate case order, effective June 1, 2011. For PECO, primarily reflects increased distribution revenue pursuant to the 2010 Pennsylvania electric and natural gas distribution rate case settlements effective January 1, 2011.

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

(11)	Primarily reflects the impacts of increased wages and other benefits and increased contracting expenses, including Exelon Wind, which was acquired in December 2010 (exclusive of planned nuclear refueling outages and incremental storm costs as disclosed in numbers 12 and 13 below).

(12)	Primarily reflects the impact of increased planned nuclear refueling outage days in 2011, excluding Salem.

(13)	Primarily reflects increased storm costs in the ComEd and PECO service territories. For Generation, primarily reflects additional environmental remediation costs.

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

(15)

Primarily reflects a reduction in Generation’s manufacturing deduction benefits (given reduced taxable income as a result of bonus depreciation and the transmission and distribution property repairs deduction), 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, production tax credits at Exelon Wind, and the transmission and distribution property repairs deduction.

(16)	For PECO, primarily reflects decreased gross receipts tax (completely offset by decreased PECO margins above).

(17)	Primarily reflects an increase in 2011 in Generation’s decommissioning obligation for spent nuclear fuel at Zion.

(18)	Reflects certain costs incurred associated with Exelon’s proposed acquisition of Constellation.

(19)	Primarily reflects a non-cash bargain purchase gain (negative goodwill) in connection with the acquisition of Wolf Hollow, net of acquisition costs.

EXELON CORPORATION

Reconciliation of Adjusted (non-GAAP) Operating

Earnings to GAAP Earnings (in millions)

Nine Months Ended September 30, 2011 and 2010


	Exelon Earnings per Diluted Share			Generation			ComEd			PECO			Other (a)			Exelon
2010 GAAP Earnings (Loss)	$	3.08		$	1,548		$	246		$	303		$	(58	)	$	2,039
2010 Adjusted (non-GAAP) Operating Earnings (Loss) Adjustments:
Mark-to-Market Impact of Economic Hedging Activities		(0.25	)		(166	)		—			—			—			(166	)
Unrealized Gains Related to NDT Fund Investments (1)		(0.04	)		(28	)		—			—			—			(28	)
Non-Cash Charge Resulting From Health Care Legislation (2)		0.10			26			12			10			17			65
Non-Cash Remeasurement of Income Tax Uncertainties (3)		0.10			(70	)		106			22			7			65
Retirement of Fossil Generating Units (4)		0.05			34			—			—			—			34
Impairment of Certain Emission Allowances (5)		0.05			35			—			—			—			35
2007 Illinois Electric Rate Settlement		0.01			9			1			—			—			10
City of Chicago Settlement with ComEd		—			—			2			—			—			2
Acquisition Costs (6)		—			1			—			—			—			1

2010 Adjusted (non-GAAP) Operating Earnings (Loss)		3.10			1,389			367			335			(34	)		2,057

Year Over Year Effects on Earnings:
Generation Energy Margins, Excluding Mark-to-Market:
Nuclear Volume (7)		0.01			4			—			—			—			4
Nuclear Fuel Costs (8)		(0.06	)		(38	)		—			—			—			(38	)
Capacity Pricing		(0.09	)		(62	)		—			—			—			(62	)
Market and Portfolio Conditions (9)		0.82			543			—			—			—			543
Transmission Upgrades (10)		—			(34	)		—			—			34			—
ComEd and PECO Margins:
Weather		(0.02	)		—			(6	)		(8	)		—			(14	)
Load		(0.01	)		—			(8	)		(2	)		—			(10	)
Other Energy Delivery (11)		0.16			—			36			71			—			107
2010 CTC, Net (12)		(0.18	)		—			—			(122	)		—			(122	)
Discrete Impacts of Distribution Rate Case Order (13)		0.03			—			23			—			—			23
Operating and Maintenance Expense:
Labor, Contracting and Materials (14)		(0.15	)		(56	)		(25	)		(19	)		—			(100	)
Planned Nuclear Refueling Outages (15)		(0.03	)		(21	)		—			—			—			(21	)
Pension and Non-Pension Postretirement Benefits (16)		0.02			9			(1	)		5			1			14
2010 Recovery of Bad Debt Expense at ComEd (17)		(0.06	)		—			(36	)		—			—			(36	)
Other Operating and Maintenance (18)		(0.15	)		(31	)		(42	)		(12	)		(8	)		(93	)
Depreciation and Amortization Expense (19)		(0.09	)		(40	)		(12	)		(11	)		4			(59	)
Nuclear Decommissioning Trust Fund Special Transfer Tax Deduction (20)		0.07			46			—			—			—			46
Income Taxes (21)		(0.03	)		(23	)		12			9			(17	)		(19	)
Interest Expense, Net (22)		(0.01	)		(17	)		(4	)		14			—			(7	)
Other (23)		0.01			(26	)		(21	)		53			—			6

2011 Adjusted (non-GAAP) Operating Earnings (Loss)		3.34			1,643			283			313			(20	)		2,219

2011 Adjusted (non-GAAP) Operating Earnings (Loss) Adjustments:
Mark-to-Market Impact of Economic Hedging Activities		(0.34	)		(219	)		—			—			—			(219	)
Unrealized Losses Related to NDT Fund Investments (1)		(0.07	)		(46	)		—			—			—			(46	)
Retirement of Fossil Generating Units (4)		(0.04	)		(29	)		—			—			—			(29	)
Asset Retirement Obligation (24)		(0.02	)		(18	)		—			2			—			(16	)
Constellation Acquisition Costs (25)		(0.04	)		(3	)		(1	)		(1	)		(21	)		(26	)
Acquisition Costs (6)		(0.01	)		(5	)		—			—			—			(5	)
Non-Cash Charge Resulting From Illinois Tax Rate Change Legislation (26)		(0.04	)		(21	)		(4	)		—			(4	)		(29	)
Wolf Hollow Acquisition (27)		0.03			23			—			—			—			23
Recovery of Costs Pursuant to Distribution Rate Case Order (28)		0.03			—			17			—			—			17

2011 GAAP Earnings (Loss)	$	2.84		$	1,325		$	295		$	314		$	(45	)	$	1,889

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

(1)	Reflects the impact of unrealized gains in 2010 and unrealized losses in 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)	Reflects the impact of a remeasurement of income tax uncertainties related to ComEd’s 1999 sale of fossil generating assets and CTCs received by PECO.

(4)

Primarily reflects accelerated depreciation expense associated with the planned retirement of four generating units, two of which retired on May 31, 2011. Beginning June 1, 2011, reflects the net loss attributable to the remaining two units, which includes compensation for operating the units past their planned May 31, 2011 retirement date under a FERC-approved reliability-must-run rate schedule.

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

(6)	For 2010, reflects certain costs incurred associated with the acquisition of Exelon Wind and in 2011 reflects certain costs incurred associated with the acquisition of AVSR 1.

(7)	Primarily reflects the impact of decreased planned nuclear outage days in the Mid-Atlantic region in 2011 where energy prices are typically higher, partially offset by increased planned nuclear outage days in the Midwest region in 2011.

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

(9)	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 PPA, energy margins at Exelon Wind, which was acquired in December 2010, and other favorable market and portfolio conditions in the South and West region.

(10)	Reflects intercompany expense at Generation for upgrades in transmission assets owned by ComEd, which are reflected as assets at Exelon Corporate.

(11)

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

(13)	Primarily reflects one-time net benefits pursuant to the 2011 ComEd electric distribution rate case order to reestablish previously expensed plant balances and to recognize the estimated recovery of funds for working capital related to the procurement of energy.

(14)	Primarily reflects the impacts of increased wages and other benefits and increased contracting expenses, including Exelon Wind (exclusive of planned nuclear refueling outages and incremental storm costs as disclosed in numbers 15 and 18 below).

(15)	Primarily reflects the impact of increased planned nuclear refueling outage days in 2011, excluding Salem.

(16)	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.

(17)	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.

(18)	Primarily reflects increased storm costs in the ComEd and PECO service territories. For Generation, primarily reflects additional environmental remediation costs.

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

(20)

Reflects one-time interest and tax benefits associated with a change in the timing of the deduction for the transfer of cash or investments from nonqualified nuclear decommissioning trust funds to qualified decommissioning trust funds pursuant to the Energy Policy Act of 2005 and recently issued Treasury Regulations.

(21)

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

(23)

Primarily reflects decreased gross receipts tax at PECO (completely offset by decreased PECO margins above), partially offset by increased gross receipts tax at Generation (completely offset by increased Generation margins above) and Illinois electric distribution tax refunds recorded in 2010 at ComEd.

(24)	Primarily reflects an increase in 2011 in Generation’s decommissioning obligation for spent nuclear fuel at Zion.

(25)	Reflects certain costs incurred associated with Exelon’s proposed acquisition of Constellation.

(26)	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.

(27)	Primarily reflects a non-cash bargain purchase gain (negative goodwill) in connection with the acquisition of Wolf Hollow, net of acquisition costs.

(28)	Reflects one-time benefits pursuant to the ComEd 2011 electric distribution rate case order for the recovery of previously incurred costs related to the 2009 restructuring plan and for the passage of Federal health care legislation in 2010.

EXELON CORPORATION

Reconciliation of Adjusted (non-GAAP) Operating Earnings to

GAAP Consolidated Statements of Operations

(unaudited)

(in millions)


	Generation
	Three Months Ended September 30, 2011									Three Months Ended September 30, 2010
	GAAP (a)			Adjustments			Adjusted Non- GAAP			GAAP (a)			Adjustments			Adjusted Non- GAAP
Operating revenues	$	2,862		$	(33	)(b),(c)	$	2,829		$	2,655		$	5	(i)	$	2,660

Operating expenses
Purchased power		680			(71	)(d)		609			494			107	(d)		601
Fuel		432			(22	)(b),(d)		410			451			(1	)(d),(j)		450
						(b),(c),(e),
Operating and maintenance		790			(55	)(f),(g)		735			649			(2	)(b),(g)		647
Depreciation and amortization		139			(19	)(b)		120			121			(22	)(b)		99
Taxes other than income		67			—			67			57			—			57

Total operating expenses		2,108			(167	)		1,941			1,772			82			1,854

Operating income		754			134			888			883			(77	)		806

Other income and deductions
Interest expense		(37	)		—			(37	)		(37	)		—			(37	)
Other, net		(164	)		181	(c),(h)		17			192			(173	)(h)		19

Total other income and deductions		(201	)		181			(20	)		155			(173	)		(18	)

Income before income taxes		553			315			868			1,038			(250	)		788

						(b),(c),(d),									(b),(d),(g),
Income taxes		167			179	(e),(f),(g),(h)		346			433			(144	)(h),(i),(j)		289

Net income	$	386		$	136		$	522		$	605		$	(106	)	$	499


	Nine Months Ended September 30, 2011									Nine Months Ended September 30, 2010
	GAAP (a)			Adjustments			Adjusted Non- GAAP			GAAP (a)			Adjustments			Adjusted Non- GAAP
Operating revenues	$	8,147		$	(42	)(b),(c)	$	8,105		$	7,428		$	14	(i)	$	7,442

Operating expenses
Purchased power		1,801			(260	)(d)		1,541			1,251			142	(d)		1,393
Fuel		1,222			(106	)(b),(d)		1,116			1,191			74	(d),(j)		1,265
						(b),(c),(e),
Operating and maintenance		2,306			(61	)(f),(g)		2,245			2,081			(4	)(b),(g),(l)		2,077
Depreciation and amortization		416			(65	)(b)		351			344			(57	)(b)		287
Taxes other than income		199			—			199			175			—			175

Total operating expenses		5,944			(492	)		5,452			5,042			155			5,197

Operating income		2,203			450			2,653			2,386			(141	)		2,245

Other income and deductions
Interest expense		(128	)		—			(128	)		(109	)		—			(109	)
Other, net		(12	)		94	(c),(h)		82			138			(74	)(h)		64

Total other income and deductions		(140	)		94			(46	)		29			(74	)		(45	)

Income before income taxes		2,063			544			2,607			2,415			(215	)		2,200

						(b),(c),(d), (e),(f),(g),									(b),(d),(g),(h),
Income taxes		738			226	(h),(k)		964			867			(56	)(i),(j),(l),(m)		811

Net income	$	1,325		$	318		$	1,643		$	1,548		$	(159	)	$	1,389

(a)	Results reported in accordance with GAAP.

(b)	Adjustment to exclude costs associated with the planned retirement of fossil generating units and the impacts of the FERC approved reliability-must-run rate schedule.

(c)	Adjustment to exclude the non-cash bargain purchase gain (negative goodwill) associated with the acquisition of Wolf Hollow, net of acquisition costs.

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

(e)	Adjustment to exclude the increase in Generation’s decommissioning obligation for spent nuclear fuel at Zion.

(f)	Adjustment to exclude certain costs associated with Exelon’s proposed acquisition of Constellation.

(g)	Adjustment to exclude certain costs associated with Exelon’s acquisition of Exelon Wind in 2010 and Exelon’s acquisition of AVSR 1 in 2011.

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

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

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

(k)	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.

(l)	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.

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

EXELON CORPORATION

Reconciliation of Adjusted (non-GAAP) Operating Earnings to

GAAP Consolidated Statements of Operations

(unaudited)

(in millions)


	ComEd
	Three Months Ended September 30, 2011									Three Months Ended September 30, 2010
	GAAP (a)			Adjustments			Adjusted Non- GAAP			GAAP (a)			Adjustments			Adjusted Non- GAAP
Operating revenues	$	1,784		$	—		$	1,784		$	1,918		$	—		$	1,918

Operating expenses
Purchased power		932			—			932			1,112			—			1,112
Operating and maintenance		353			(1	)(c)		352			298			—			298
Operating and maintenance for regulatory required programs (b)		43			—			43			22			—			22
Depreciation and amortization		135			—			135			126			—			126
Taxes other than income		78			—			78			81			—			81

Total operating expenses		1,541			(1	)		1,540			1,639			—			1,639

Operating income		243			1			244			279			—			279

Other income and deductions
Interest expense		(86	)		—			(86	)		(82	)		—			(82	)
Other, net		16			—			16			3			—			3

Total other income and deductions		(70	)		—			(70	)		(79	)		—			(79	)

Income before income taxes		173			1			174			200			—			200

Income taxes		61			—	(c)		61			79			—			79

Net income	$	112		$	1		$	113		$	121		$	—		$	121


	Nine Months Ended September 30, 2011									Nine Months Ended September 30, 2010
	GAAP (a)			Adjustments			Adjusted Non- GAAP			GAAP (a)			Adjustments			Adjusted Non- GAAP
Operating revenues	$	4,694		$	—		$	4,694		$	4,832		$	4	(f),(g)	$	4,836

Operating expenses
Purchased power		2,436			—			2,436			2,636			—			2,636
Operating and maintenance		846			12	(c),(d)		858			733			(3	)(h)		730
Operating and maintenance for regulatory required programs (b)		84			—			84			62			—			62
Depreciation and amortization		405			—			405			386			—			386
Taxes other than income		226			—			226			188			—			188

Total operating expenses		3,997			12			4,009			4,005			(3	)		4,002

Operating income		697			(12	)		685			827			7			834

Other income and deductions
Interest expense		(257	)		—			(257	)		(300	)		59	(i)		(241	)
Other, net		24			—			24			14			—			14

Total other income and deductions		(233	)		—			(233	)		(286	)		59			(227	)

Income before income taxes		464			(12	)		452			541			66			607

															(f),(g),(h),
Income taxes		169			—	(c),(d),(e)		169			295			(55	)(i)		240

Net income	$	295		$	(12	)	$	283		$	246		$	121		$	367

(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 certain costs associated with Exelon’s proposed acquisition of Constellation.

(d)	Adjustment to exclude one-time benefits for the recovery of previously incurred costs related to the 2009 restructuring plan and for the passage of Federal health care legislation in 2010.

(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 the costs associated with ComEd’s 2007 settlement agreement with the City of Chicago.

(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.

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

EXELON CORPORATION

Reconciliation of Adjusted (non-GAAP) Operating Earnings to

GAAP Consolidated Statements of Operations

(unaudited)

(in millions)


	PECO
	Three Months Ended September 30, 2011									Three Months Ended September 30, 2010
	GAAP (a)			Adjustments			Adjusted Non- GAAP			GAAP (a)			Adjustments		Adjusted Non- GAAP
Operating revenues	$	946		$	—		$	946		$	1,495		$	—	$	1,495

Operating expenses
Purchased power		445			—			445			650			—		650
Fuel		19			—			19			23			—		23
Operating and maintenance		203			2	(c),(d)		205			176			—		176
Operating and maintenance for regulatory required programs (b)		16			—			16			15			—		15
Depreciation and amortization		51			—			51			326			—		326
Taxes other than income		59			—			59			90			—		90

Total operating expenses		793			2			795			1,280			—		1,280

Operating income		153			(2	)		151			215			—		215

Other income and deductions
Interest expense		(34	)		—			(34	)		(38	)		—		(38	)
Other, net		3			—			3			3			—		3

Total other income and deductions		(31	)		—			(31	)		(35	)		—		(35	)

Income before income taxes		122			(2	)		120			180			—		180

Income taxes		17			(1	)(c),(d)		16			53			—		53

Net income	$	105		$	(1	)	$	104		$	127		$	—	$	127


	Nine Months Ended September 30, 2011									Nine Months Ended September 30, 2010
	GAAP (a)			Adjustments			Adjusted Non- GAAP			GAAP (a)			Adjustments			Adjusted Non- GAAP
Operating revenues	$	2,942		$	—		$	2,942		$	4,220		$	—		$	4,220

Operating expenses
Purchased power		1,265			—			1,265			1,709			—			1,709
Fuel		241			—			241			278			—			278
Operating and maintenance		543			2	(c),(d)		545			507			(2	)(e)		505
Operating and maintenance for regulatory required programs (b)		54			—			54			36			—			36
Depreciation and amortization		150			—			150			859			—			859
Taxes other than income		165			—			165			240			—			240

Total operating expenses		2,418			2			2,420			3,629			(2	)		3,627

Operating income		524			(2	)		522			591			2			593

Other income and deductions
Interest expense		(102	)		—			(102	)		(160	)		36	(f)		(124	)
Other, net		11			—			11			6			2	(f)		8

Total other income and deductions		(91	)		—			(91	)		(154	)		38			(116	)

Income before income taxes		433			(2	)		431			437			40			477

Income taxes		119			(1	)(c),(d)		118			134			8	(e),(f)		142

Net income	$	314		$	(1	)	$	313		$	303		$	32		$	335

(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 certain costs associated with Exelon’s proposed acquisition of Constellation.

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

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

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

EXELON CORPORATION

Reconciliation of Adjusted (non-GAAP) Operating Earnings to

GAAP Consolidated Statements of Operations

(unaudited)

(in millions)


	Other (a)
	Three Months Ended September 30, 2011									Three Months Ended September 30, 2010
	GAAP (b)			Adjustments			Adjusted Non- GAAP			GAAP (b)			Adjustments			Adjusted Non-GAAP
Operating revenues	$	(297	)	$	—		$	(297	)	$	(777	)	$	—		$	(777	)

Operating expenses
Purchased power		(346	)		—			(346	)		(775	)		—			(775	)
Fuel		—			—			—			1			—			1
Operating and maintenance		8			(11	)(c)		(3	)		(1	)		—			(1	)
Depreciation and amortization		7			—			7			5			—			5
Taxes other than income		3			—			3			4			—			4

Total operating expenses		(328	)		(11	)		(339	)		(766	)		—			(766	)

Operating income (loss)		31			11			42			(11	)		—			(11	)

Other income and deductions
Interest expense		(25	)		—			(25	)		(18	)		—			(18	)
Other, net		2			—			2			8			—			8

Total other income and deductions		(23	)		—			(23	)		(10	)		—			(10	)

Income (loss) before income taxes		8			11			19			(21	)		—			(21	)
Income taxes		10			4	(c)		14			(13	)		—			(13	)

Net income (loss)	$	(2	)	$	7		$	5		$	(8	)	$	—		$	(8	)


	Nine Months Ended September 30, 2011									Nine Months Ended September 30, 2010
	GAAP (b)			Adjustments			Adjusted Non- GAAP			GAAP (b)			Adjustments			Adjusted Non- GAAP
Operating revenues	$	(850	)	$	—		$	(850	)	$	(2,330	)	$	—		$	(2,330	)

Operating expenses
Purchased power		(900	)		—			(900	)		(2,323	)		—			(2,323	)
Fuel		(1	)		—			(1	)		—			—			—
Operating and maintenance		30			(35	)(c)		(5	)		(23	)		8	(e)		(15	)
Depreciation and amortization		16			—			16			22			—			22
Taxes other than income		12			—			12			12			—			12

Total operating expenses		(843	)		(35	)		(878	)		(2,312	)		8			(2,304	)

Operating income (loss)		(7	)		35			28			(18	)		(8	)		(26	)

Other income and deductions
Interest expense		(58	)		—			(58	)		(65	)		8	(f)		(57	)
Other, net		28			—			28			20			—			20

Total other income and deductions		(30	)		—			(30	)		(45	)		8			(37	)

Loss before income taxes		(37	)		35			(2	)		(63	)		—			(63	)
Income taxes		8			10	(c),(d)		18			(5	)		(24	)(e),(f)		(29	)

Net loss	$	(45	)	$	25		$	(20	)	$	(58	)	$	24		$	(34	)

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

(b)	Results reported in accordance with GAAP.

(c)	Adjustment to exclude certain costs associated with Exelon’s proposed acquisition of Constellation.

(d)	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.

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

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

EXELON CORPORATION

Exelon Generation Statistics


	Three Months Ended
	Sept. 30, 2011		Jun. 30, 2011			Mar. 31, 2011			Dec. 31, 2010			Sept. 30, 2010
Supply (in GWhs)
Nuclear Generation (a)
Mid-Atlantic		12,158		11,172			12,370			11,974			12,076
Midwest		23,887		21,995			22,822			23,141			23,675

Total Nuclear Generation		36,045		33,167			35,192			35,115			35,751
Fossil and Renewables
Mid-Atlantic (a) (b)		1,724		2,054			2,166			2,115			2,582
Midwest (c)		88		163			157			45			16
South and West (c)		1,463		638			509			93			691

Total Fossil and Renewables		3,275		2,855			2,832			2,253			3,289
Purchased Power
Mid-Atlantic		702		707			750			442			599
Midwest		1,756		1,659			1,412			1,776			1,774
South and West		3,815		2,411			2,181			2,632			4,084

Total Purchased Power		6,273		4,777			4,343			4,850			6,457
Total Supply by Region
Mid-Atlantic		14,584		13,933			15,286			14,531			15,257
Midwest		25,731		23,817			24,391			24,962			25,465
South and West		5,278		3,049			2,690			2,725			4,775

		45,593		40,799			42,367			42,218			45,497


	Three Months Ended
	Sept. 30, 2011		Jun. 30, 2011			Mar. 31, 2011			Dec. 31, 2010			Sept. 30, 2010
Electric Sales (in GWhs)
PECO (d)		—		—			—			9,756			11,976
Market and Retail (d)		45,593		40,799			42,367			32,462			33,521

Total Electric Sales (d) (e)		45,593		40,799			42,367			42,218			45,497

Average Margin ($/MWh) (f)(g)(h)
Mid-Atlantic	$	57.32	$	58.92		$	59.92		$	51.75		$	36.97
Midwest		33.15		37.28			39.60			41.14			41.00
South and West		18.57		(3.61	)		(1.49	)		(10.64	)		(2.30	)
Average Margin - Overall Portfolio	$	39.19	$	41.59		$	44.30		$	41.45		$	35.11
Around-the-clock Market Prices ($/MWh) (i)
PJM West Hub	$	46.17	$	47.27		$	45.82		$	43.65		$	52.25
NiHub		37.30		34.94			34.10			27.26			38.32
ERCOT North Spark Spread		36.70		6.73			8.00			(0.69	)		8.25

(a)	Includes Generation’s proportionate share of the output of its jointly owned generating plants.

(b)	Includes New England generation.

(c)	Includes generation from Exelon Wind, acquired in December, 2010, of 76 GWh, 154 GWh, 155 GWh and 41GWh in the Midwest and 249 GWh, 431 GWh, 358 GWh, and 84 GWh in the South and West for the three months ended September 30, 2011, June 30, 2011, March 31, 2011, and December 31, 2010 respectively.

(d)	PECO line item represents sales under the PECO PPA. Settlements of the ComEd swap, sales under the Request for Proposal (RFP) and sales to PECO through the competitive procurement process are included within Market and Retail sales.

(e)	Total sales do not include physical trading volume of 1,679 GWhs, 1,496 GWhs, 1,333 GWhs, 740 GWhs and 1,077 GWhs for the three months ended September 30, 2011, June 30, 2011, March 31, 2011, December 31, 2010 and September 30, 2010, respectively.

(f)

Excludes retail gas activity, trading portfolio activity, the $57 million lower of cost or market impairment of certain SO2 allowances recorded in the three months ended September 30, 2010, amounts paid related to the Illinois Settlement Legislation and compensation under the reliability-must-run rate schedule.

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

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

(i)	Represents the average for the quarter.

EXELON CORPORATION

Exelon Generation Statistics

Nine Months Ended September 30, 2011 and 2010


	September 30, 2011		September 30, 2010
Supply (in GWhs)
Nuclear Generation (a)
Mid-Atlantic		35,700		35,544
Midwest		68,704		69,352

Total Nuclear Generation		104,404		104,896
Fossil and Renewables
Mid-Atlantic (a) (b)		5,943		7,321
Midwest (c)		408		23
South and West (c)		2,610		1,120

Total Fossil and Renewables		8,961		8,464
Purchased Power
Mid-Atlantic		2,159		1,476
Midwest		4,827		5,256
South and West		8,408		9,480

Total Purchased Power		15,394		16,212
Total Supply by Region
Mid-Atlantic		43,802		44,341
Midwest		73,939		74,631
South and West		11,018		10,600

		128,759		129,572


	September 30, 2011		September 30, 2010
Electric Sales (in GWhs)
ComEd (d)		—		5,323
PECO (d)		—		32,247
Market and Retail (d)		128,759		92,002

Total Electric Sales (e)		128,759		129,572

Average Margin ($/MWh) (f)(g)(h)
Mid-Atlantic	$	58.74	$	39.69
Midwest		36.57		40.92
South and West		7.62		(9.62	)
Average Margin - Overall Portfolio	$	41.64	$	36.37
Around-the-clock Market Prices ($/MWh) (i)
PJM West Hub	$	46.42	$	46.70
NiHub		35.46		35.06
ERCOT North Spark Spread		15.48		4.58

(a)	Includes Generation’s proportionate share of the output of its jointly owned generating plants.

(b)	Includes New England generation.

(c)	Includes generation from Exelon Wind, acquired in December, 2010, of 385 GWh and 1,038 GWh in the Midwest and South, respectively.

(d)	ComEd and PECO line items represent sales under the 2006 ComEd Auction and PECO PPA. Settlements of the ComEd swap, sales under the RFP and sales to PECO through the competitive procurement process are included within Market and Retail sales.

(e)	Total sales do not include physical trading volume of 4,508 GWhs and 2,885 GWhs for the nine months ended September 30, 2011 and 2010, respectively.

(f)	Excludes retail gas activity, trading portfolio activity, the $57 million lower of cost or market impairment of certain S02 allowances, amounts paid related to the Illinois Settlement Legislation and compensation under the reliability-must-run rate schedule.

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

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

(i)	Represents the average for the nine months ended September 30, 2011 and 2010, respectively.

EXELON CORPORATION

ComEd Statistics


	Three Months Ended September 30, 2011 and 2010

	Electric Deliveries (in GWhs)										Revenue (in millions)
								Weather- Normal
	2011		2010		% Change			% Change			2011			2010		% Change
Retail Deliveries and Sales (a)
Residential		8,877		9,361		(5.2	)%		(2.4	)%	$	1,112		$	1,181		(5.8	)%
Small Commercial & Industrial		8,811		9,110		(3.3	)%		(2.2	)%		410			471		(13.0	)%
Large Commercial & Industrial		7,494		7,503		(0.1	)%		0.1	%		102			109		(6.4	)%
Public Authorities & Electric Railroads		303		283		7.1	%		10.5	%		12			14		(14.3	)%

Total Retail		25,485		26,257		(2.9	)%		(1.4	)%		1,636			1,775		(7.8	)%

Other Revenue (b)												148			143		3.5	%

Total Electric Revenue											$	1,784		$	1,918		(7.0	)%

Purchased Power											$	932		$	1,112		(16.2	)%


								% Change
Heating and Cooling Degree-Days	2011		2010		Normal			From 2010			From Normal
Heating Degree-Days		147		70		110			110.0	%		33.6	%
Cooling Degree-Days		785		854		624			(8.1	)%		25.8	%

	Nine Months Ended September 30, 2011 and 2010

	Electric Deliveries (in GWhs)										Revenue (in millions)
								Weather- Normal
	2011		2010		% Change			% Change			2011			2010		% Change
Retail Deliveries and Sales (a)
Residential		22,108		22,778		(2.9	)%		(2.0	)%	$	2,746		$	2,788		(1.5	)%
Small Commercial & Industrial		24,648		24,975		(1.3	)%		(0.7	)%		1,177			1,273		(7.5	)%
Large Commercial & Industrial		21,011		20,991		0.1	%		0.2	%		288			306		(5.9	)%
Public Authorities & Electric Railroads		919		927		(0.9	)%		(0.5	)%		38			48		(20.8	)%

Total Retail		68,686		69,671		(1.4	)%		(0.8	)%		4,249			4,415		(3.8	)%

Other Revenue (b)												445			417		6.7	%

Total Electric Revenue											$	4,694		$	4,832		(2.9	)%

Purchased Power											$	2,436		$	2,636		(7.6	)%


								% Change
Heating and Cooling Degree-Days	2011		2010		Normal			From 2010			From Normal
Heating Degree-Days		4,302		3,699		4,084			16.3	%		5.3	%
Cooling Degree-Days		1,022		1,166		848			(12.3	)%		20.5	%

Number of Electric Customers	2011		2010
Residential		3,439,704		3,422,824
Small Commercial & Industrial		364,917		361,424
Large Commercial & Industrial		2,041		2,014
Public Authorities & Electric Railroads		4,801		5,090

Total		3,811,463		3,791,352

(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 September 30, 2011 and 2010

	Electric and Gas Deliveries										Revenue (in millions)
								Weather- Normal
	2011		2010		% Change			% Change			2011			2010		% Change
Electric (in GWhs)

Retail Deliveries and Sales (a)
Residential		4,085		4,144		(1.4	)%		2.1	%	$	598		$	663		(9.8	)%
Small Commercial & Industrial		2,272		2,368		(4.1	)%		(3.2	)%		138			308		(55.2	)%
Large Commercial & Industrial		4,370		4,447		(1.7	)%		(0.6	)%		84			374		(77.5	)%
Public Authorities & Electric Railroads		239		228		4.8	%		6.4	%		9			20		(55.0	)%

Total Retail		10,966		11,187		(2.0	)%		(0.1	)%		829			1,365		(39.3	)%

Other Revenue (b)												62			74		(16.2	)%

Total Electric Revenue												891			1,439		(38.1	)%

Gas (in mmcfs)

Retail Deliveries and Sales (c)
Retail Sales		3,687		3,546		4.0	%		7.2	%		50			52		(3.8	)%
Transportation and Other		6,190		8,501		(27.2	)%		(29.1	)%		5			4		25.0	%

Total Gas		9,877		12,047		(18.0	)%		(18.5	)%		55			56		(1.8	)%

Total Electric and Gas Revenues											$	946		$	1,495		(36.7	)%

Purchased Power											$	445		$	650		(31.5	)%
Fuel												19			23		(17.4	)%

Total Purchased Power and Fuel											$	464		$	673		(31.1	)%


								% Change
Heating and Cooling Degree-Days	2011		2010		Normal			From 2010			From Normal
Heating Degree-Days		18		-		36			n/a			(50.0	)%
Cooling Degree-Days		1,109		1,212		939			(8.5	)%		18.1	%

	Nine Months Ended September 30, 2011 and 2010

	Electric and Gas Deliveries										Revenue (in millions)
								Weather- Normal
	2011		2010		% Change			% Change			2011			2010		% Change
Electric (in GWhs)

Retail Deliveries and Sales (a)
Residential		10,750		10,789		(0.4	)%		1.9	%	$	1,542		$	1,625		(5.1	)%
Small Commercial & Industrial		6,437		6,545		(1.7	)%		(1.0	)%		471			827		(43.0	)%
Large Commercial & Industrial		12,012		12,397		(3.1	)%		(2.2	)%		259			1,035		(75.0	)%
Public Authorities & Electric Railroads		710		699		1.6	%		3.3	%		29			67		(56.7	)%

Total Retail		29,909		30,430		(1.7	)%		(0.4	)%		2,301			3,554		(35.3	)%

Other Revenue (b)												186			194		(4.1	)%

Total Electric Revenue												2,487			3,748		(33.6	)%

Gas (in mmcfs)
Retail Deliveries and Sales (c)
Retail Sales		38,982		37,103		5.1	%		0.9	%		428			451		(5.1	)%
Transportation and Other		21,428		23,658		(9.4	)%		(8.4	)%		27			21		28.6	%

Total Gas		60,410		60,761		(0.6	)%		(2.5	)%		455			472		(3.6	)%

Total Electric and Gas Revenues											$	2,942		$	4,220		(30.3	)%

Purchased Power											$	1,265		$	1,709		(26.0	)%
Fuel												241			278		(13.3	)%

Total Purchased Power and Fuel											$	1,506		$	1,987		(24.2	)%


								% Change
Heating and Cooling Degree-Days	2011		2010		Normal			From 2010			From Normal
Heating Degree-Days		2,855		2,710		3,004			5.4	%		(5.0	)%
Cooling Degree-Days		1,603		1,798		1,271			(10.8	%)		26.1	%


Number of Electric Customers	2011		2010		Number of Gas Customers	2011		2010
Residential		1,412,070		1,408,239	Residential		448,763		446,348
Small Commercial & Industrial		156,769		156,502	Commercial & Industrial		40,883		40,863

Large Commercial & Industrial		3,116		3,092	Total Retail		489,646		487,211
Public Authorities & Electric Railroads		1,123		984	Transportation		868		834

Total		1,573,078		1,568,817	Total		490,514		488,045

(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 as all customers are assessed distribution charges. For customers purchasing electricity from PECO, revenue also reflects the cost of energy and transmission.

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

(c)

Reflects delivery volumes and revenues from customers purchasing natural gas directly from PECO and customers purchasing natural gas directly from a competitive natural gas supplier as all customers are assessed distribution charges. The cost of natural gas is charged to customers purchasing natural gas from PECO.

Earnings conference call presentation slides

Earnings Conference Call

Quarter 2011

October 26, 2011

Exhibit 99.2

Cautionary Statements Regarding

Forward-Looking Information

Except for the historical information contained herein, certain of the matters discussed in this communication constitute “forward-looking

statements” within the meaning of the Securities Act of 1933 and the Securities Exchange Act of 1934, both as amended by the Private

Securities Litigation Reform Act of 1995. Words such as “may,” “will,” “anticipate,” “estimate,” “expect,” “project,” “intend,” “plan,”

“believe,” “target,” “forecast,” and words and terms of similar substance used in connection with any discussion of future plans, actions,

or events identify forward-looking statements. These forward-looking statements include, but are not limited to, statements regarding

benefits of the proposed merger of Exelon Corporation (Exelon) and Constellation Energy Group, Inc. (Constellation), integration plans

and expected synergies, the expected timing of completion of the transaction, anticipated future financial and operating performance

and results, including estimates for growth. These statements are based on the current expectations of management of Exelon and

Constellation, as applicable. There are a number of risks and uncertainties that could cause actual results to differ materially from the

forward-looking statements included in this communication regarding the proposed merger. For example, (1) the companies may be

unable to obtain shareholder approvals required for the merger; (2) the companies may be unable to obtain regulatory approvals

required for the merger, or required regulatory approvals may delay the merger or result in the imposition of conditions that could have

a material adverse effect on the combined company or cause the companies to abandon the merger; (3) conditions to the closing of the

merger may not be satisfied; (4) an unsolicited offer of another company to acquire assets or capital stock of Exelon or Constellation

could interfere with the merger; (5) problems may arise in successfully integrating the businesses of the companies, which may result in

the combined company not operating as effectively and efficiently as expected; (6) the combined company may be unable to achieve

cost-cutting synergies or it may take longer than expected to achieve those synergies; (7) the merger may involve unexpected costs,

unexpected liabilities or unexpected delays, or the effects of purchase accounting may be different from the companies’ expectations;

(8) the credit ratings of the combined company or its subsidiaries may be different from what the companies expect; (9) the businesses

of the companies may suffer as a result of uncertainty surrounding the merger; (10) the companies may not realize the values expected

to be obtained for properties expected or required to be divested; (11) the industry may be subject to future regulatory or legislative

actions that could adversely affect the companies; and (12) the companies may be adversely affected by other economic, business,

and/or competitive factors. Other unknown or unpredictable factors could also have material adverse effects on future results,

performance or achievements of Exelon, Constellation or the combined company.

Cautionary Statements Regarding

Forward-Looking Information (Continued)

Discussions of some of these other important factors and assumptions are contained in Exelon’s and Constellation’s respective

filings with the Securities and Exchange Commission (SEC), and available at the SEC’s website at www.sec.gov, including:

(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

Quarterly Report on Form 10-Q for the quarterly period ended September 30, 2011 (to be filed on October 26, 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 13;

(3) Constellation’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 12;

and (4) Constellation’s Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2011 in (a) Part II, Other Information,

ITEM 1A. Risk Factors and ITEM 5. Other Information, (b) Part I, 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: Notes

to Consolidated Financial Statements, Commitments and Contingencies. These risks, as well as other risks associated with the

proposed merger, are more fully discussed in the definitive joint proxy statement/prospectus included in the Registration Statement

on Form S-4 that Exelon filed with the SEC and that the SEC declared effective on October 11, 2011 in connection with the proposed

merger. In light of these risks, uncertainties, assumptions and factors, the forward-looking events discussed in this communication

may not occur. Readers are cautioned not to place undue reliance on these forward-looking statements, which speak only as of the

date of this communication. Neither Exelon nor Constellation undertake any obligation to publicly release any revision to its forward-

looking statements to reflect events or circumstances after the date of this communication.

In connection with the proposed merger between Exelon and Constellation, Exelon filed with the SEC a Registration Statement on

Form S-4 that included the definitive joint proxy statement/prospectus. The Registration Statement was declared effective by the

SEC on October 11, 2011. Exelon and Constellation mailed the definitive joint proxy statement/prospectus to their respective security

holders on or about October 12, 2011. WE URGE INVESTORS AND SECURITY HOLDERS TO READ THE DEFINITIVE JOINT

PROXY STATEMENT/PROSPECTUS AND ANY OTHER RELEVANT DOCUMENTS FILED WITH THE SEC, BECAUSE THEY

CONTAIN IMPORTANT INFORMATION about Exelon, Constellation and the proposed merger. Investors and security holders may

obtain copies of all documents filed with the SEC free of charge at the SEC's website, www.sec.gov. In addition, a copy of the

definitive joint proxy statement/prospectus may be obtained free of charge from Exelon Corporation, Investor Relations, 10 South

Dearborn Street, P.O. Box 805398, Chicago, Illinois 60680-5398, or from Constellation Energy Group, Inc., Investor Relations, 100

Constellation Way, Suite 600C, Baltimore, MD 21202.

Additional Information and Where to Find it

2011 Operating Earnings Guidance

3Q 2011 operating earnings of

$1.12 per share

•

Exceeded guidance range of $1.00 -

$1.10 per share for the quarter

•

Continued operational excellence at

Exelon Nuclear with a 95.8%

capacity factor

•

Texas contributed $0.10 per share to

third quarter earnings

•

$(0.08) per share of incremental

storm costs at ComEd and PECO

compared to 3Q 2010

Reaffirming

operating

earnings

guidance

for

2011

$4.05

$4.25/share

(1)

$4.05 -

$4.25

$2.95 -

$3.10

$0.55 -

$0.65

$0.50 -

$0.60

$1.12

$0.79

$0.16

$0.17

$1.05

$0.79

$0.13

$0.15

$1.17

$0.90

$0.19

$0.11

HoldCo

ExGen

PECO

ComEd

Actual

2011

Guidance

(1)

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

(2)

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

Exelon Texas Performance in Q3

(1)

Includes ERCOT generation from LaPorte, Wolf Hollow, Frontier, Handley and Mountain Creek. PPAs or tolls sold by Exelon are excluded from both generation and capacity.

Intermediate

2,210

Peaking

1,262

ERCOT fossil capacity ~ 3,472 MW

Our Texas generation assets are well positioned from a location and dispatch standpoint to take

advantage of price volatility

Exelon’s portfolio management approach in Texas utilized a mix of forward and spot sales based on

its market views to capture value

2,000

2,600

2,500

2,400

2,300

2,200

2,100

Q3 2011

$107

2,403

Q3 2010

$49

ERCOT North Real Time On Peak Average ($/MWh)

Exelon ERCOT Total Generation

Exelon’s exceptional financial performance in Texas is a result of increased

generation and our ability to capture value through the hedging program

ERCOT Generation and On Peak Power Prices

2011

vs.

2010

(1)

ERCOT Fossil Generation Capacity

by Type (MW)

(1)

1,998

+20%

On Track for Merger Close in Early 2012

New York PSC

FERC

January 5, 2012

Statutory deadline

Shareholder vote

November 17, 2011

Maryland PSC

SEC

NRC

Texas PUC

Secured approval from Texas PUC on August 3, 2011

DOJ

Approvals

Record Date

October 7, 2011

Joint proxy statement declared effective

October 11, 2011

Rebuttal testimony filed

October 12, 2011

Evidentiary hearings begin

October 31, 2011

FERC order expected by

November 16, 2011

Filed merger approval application related filings on

May 20, 2011. Settlement agreement filed with PJM

Market Monitor on October 11, 2011

Filed for indirect transfer of Constellation Energy licenses on May 12, 2011

Submitted HSR filing on May 31, 2011 for review under U.S. antitrust laws and certified

compliance with second request

2012

2011

Regulatory proceedings are progressing as planned and we are on

track to

close in early 2012

Expect decision in Q4 2011

Note : On September 26

2011, the Department of Public Utilities in Massachusetts concluded that it does not have

jurisdiction over the proposed transaction between Exelon and Constellation.

-400

-300

-200

-100

100

200

300

400

2015E

2014E

2013E

2012E

2011E

Antelope Valley Solar Ranch One (AVSR 1)

(1) Based on alternating current (AC).

Net Equity Cash Flows

($ millions)

Equity Payback

Cumulative Equity Cash Flows

Annual Equity Cash Flows

230-MW

(1)

solar

photovoltaic

(PV) facility

in Los Angeles County

First portion of plant to come on line in

October 2012; fully operational in 2013

25-year PPA with Pacific Gas & Electric

ensures certainty in cash flows

Summary

Financials

This investment diversifies ExGen’s portfolio by expanding to a new market,

securing

stable

cash

flows

and

increasing

renewable

energy

under

our

control

All-in cost of up to $1.36B; up to $646M of a non-recourse loan guaranteed by U.S. Department of

Energy’s Loan Programs Office

Exelon

invest

$713M

through

2013

–

funded

with

cash

and

short-term

debt

Free cash flow accretive beginning in 2013; EBITDA run-rate of ~$75M per year once fully operational

Expect to recover investment by 2015, largely driven by investment tax credits and other lax benefits

EPA Regulations Will Move Forward Despite

Delay Attempts

Proposed Rule issued in March 2011

•

Rule provides regulatory certainty to

industry

•

Stakeholder comments provided to EPA in

August 2011

Final Rule expected in December 2011

Compliance starting in late 2014/early 2015

Final Rule issued in July 2011

•

Rule provides template for future NOx

and SO2 reductions

Modest changes proposed in October 2011

•

Some state emission budgets modified

•

Assurance provision moved to 2014

Compliance start remains January 2012

Impact in PJM

~10 GW

Coal Retirements

Announced to date

~15 GW

EXC Estimate of

Coal Retirements

Cost of environmental upgrades and higher net

ACRs influenced supplier bidding behavior in the

PY 2014-2015 auction

~1,800 MW reduction in offered coal capacity vs.

prior year auction

~7,000 MW reduction in cleared coal capacity vs.

prior year auction

(2)

(1) Includes retirements announced by Duke, that will be part of

PJM starting in 2012.

(2) Expected coal retirements through 2015.

(1)

Air Toxics Rule

Cross-State Air Pollution Rule

PJM May 2011 RPM Auction

PJM Retirements

EPA and the industry are moving forward with implementation of forthcoming

environmental regulations

(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.

Note: PPA = Power Purchase Agreement; T&D = Transmission and Distribution

$2.10

$0.75

$2.47

$0.79

YTD

2011

2010

Outage Days

(2)

3Q10

3Q11

Refueling

Non-refueling

Higher margins due to expiration of the

PECO PPA: $0.27

Favorable market/portfolio conditions in the

South: $0.10

Unfavorable capacity pricing: $(0.14)

Higher O&M costs, including planned

nuclear refueling outages: $(0.08)

Higher income tax due to reduced

manufacturing deduction as a result of T&D

repairs: $(0.04)

Higher nuclear fuel costs: $(0.02)

Higher depreciation expense: $(0.02)

Key Drivers –

3Q11 vs. 3Q10

(1)

Exelon Generation

Operating EPS Contribution

Exelon Generation Hedging Program

Exelon

continued

make

sales

during

capture

higher

power

prices

driven

by expanding heat rates and environmental rules

$50.00

$49.00

$48.00

$47.00

$46.00

$45.00

$37.00

$36.00

$32.00

$34.00

$33.00

$35.00

$31.00

$30.00

9/18

8/28

8/7

7/17

6/26

6/5

5/15

4/24

4/1

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%

2013

2012

2011

NI Hub ATC 2013

NI Hub ATC 2012

West Hub ATC 2013

West Hub ATC 2012

Underlying

Options

Ratable

98%

86%

57%

Physical Hedge %

PJM West Hub & NI Hub ATC Prices

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.

3Q10

Actual

Normal

Heating Degree-Days 70 147 110

Cooling Degree-Days 854 785 624

3Q11

Increased storm costs: $(0.06)

Electric distribution rates: $0.04

Key Drivers –

3Q11 vs. 3Q10

(1)

YTD

2011

2010

$0.55

$0.18

$0.43

$0.17

(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.

Note: CTC = Competitive Transition Charge; T&D = Transmission and Distribution

$0.51

$0.19

$0.47

$0.16

YTD

2010

2011

3Q10

Actual Actual Normal

Heating Degree-Days 0 18 36

Cooling Degree-Days 1,212 1,109 939

3Q11

2010 CTC collections, net of amortization

expense: $(0.08)

Increased storm costs: $(0.02)

Electric and gas distribution rates: $0.03

Lower income tax due to T&D tax repairs

deduction: $0.04

PECO Operating EPS Contribution

Key Drivers –

3Q11 vs. 3Q10

(1)

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 $375 million in Nuclear Uprates, $250 million for Exelon Wind spend and $200 million for Solar / Antelope Valley Solar Ranch One.

(5)

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

(6)

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 August 31, 2012.

(7)

“Other”

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

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

($ millions)

Exelon

(8)

Beginning Cash Balance

(1)

$800

Cash Flow from Operations

(2)

800

725

3,450

4,850

CapEx (excluding Nuclear Fuel, Nuclear Uprates, Exelon

Wind, Utility Growth CapEx and Solar CapEx)

(750)

(350)

(850)

(2,000)

Nuclear Fuel

n/a

(1,050)

Dividend

(3)

(1,400)

Nuclear Uprates, Exelon Wind and Solar

(4)

n/a

(825)

Wolf Hollow Acquisition

n/a

(300)

Antelope Valley Solar Ranch One Acquisition

n/a

(75)

Utility Growth CapEx

(5)

(275)

(125)

n/a

(400)

Net Financing (excluding Dividend):

Debt Issuances

(6)

1,200

Federal Financing Bank Loan

n/a

125

Planned Debt Retirements

(550)

(250)

(800)

Other

(7)

(75)

150

275

Ending Cash Balance

(1)

$400

Investment strategy achieved positive 2011 YTD

returns in a very challenging market environment due

to effectiveness of asset allocations and hedging

strategy :

•

Diversified asset allocation

•

Liability hedge

•

Pension plans are 83% funded as of September 30,

2011

•

Anticipate no substantial changes to contribution plan

S&P 500

Exelon

Pension

Fund Assets

-8.7%

5.3%

Pension Funds Performance

2011 YTD Returns at 9/30/2011

o

Decreased equity investments and

increased investment in fixed income

securities and alternative investments

o

The liability hedge has offset more than

50% of the pension liability increase caused

by lower interest rates

Exelon’s pension investment strategy has effectively dampened the volatility

of plan assets and plan funded status

Exelon Generation Hedging Disclosures

(as of September 30, 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 September 30, 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.

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

own

•

Heat rate options

•

Fuel products

•

Capacity

•

Renewable credits

Portfolio Management Objective

Align Hedging Activities with Financial Commitments

% 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)

$5,600

$5,150

$5,900

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)

$4.11

$33.61

$45.07

$11.58

$4.24

$33.69

$45.46

$4.32

$4.80

$36.49

$48.45

$4.69

Exelon Generation Open Gross Margin and

Reference Prices

(1)

Based on September 30, 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)

166,300

169,600

166,100

Midwest

98,500

98,300

96,100

Mid-Atlantic

56,500

56,800

56,100

South & West

11,300

14,500

13,900

Percentage of Expected Generation Hedged

(2)

97-100%

85-88%

56-59%

Midwest

97-100

85-88

56-59

Mid-Atlantic

96-99

88-91

57-60

South & West

94-97

68-71

49-52

Effective Realized Energy Price

($/MWh)

(3)

Midwest

$43.00

$41.00

$40.00

Mid-Atlantic

$56.50

$50.00

$50.50

South & West

$6.00

$1.00

$0.00

Generation Profile

(1)

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

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

Expected generation assumes 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 93.1%, 93.5% and 93.3% in 2011, 2012 and 2013 at Exelon-operated nuclear plants. These estimates of expected generation in 2012 and 2013 do

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

(2)

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

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

(3)

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

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

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

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

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)

+/-

$10

2012

$65

$(30)

$70

$(50)

$40

$(35)

+/-

$45

2013

$305

$(265)

$210

$(205)

$145

$(140)

+/-

$50

Exelon Generation Gross Margin Sensitivities

(with Existing Hedges)

(1)

Based on September 30, 2011 market conditions and hedged position. Gas price sensitivities are based on an assumed gas-power relationship derived from an

internal model that is updated periodically.

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

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

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

$5,700

$6,200

$3,000

$4,000

$5,000

$6,000

$7,000

$8,000

$9,000

2011

2012

2013

$5,500

$6,900

Exelon Generation Gross Margin Upside / Risk

(with Existing Hedges)

95% case

5% case

$7,150

$7,050

(1)

Represents an approximate range of expected gross margin, taking into account hedges in place, between the 5th and 95th percent confidence levels assuming all unhedged

supply is sold into the spot market. Approximate gross margin ranges are based upon an internal simulation model and are subject to change based upon market inputs, future

transactions and potential modeling changes. These ranges of approximate gross margin in 2012 and 2013 do not represent earnings guidance or a forecast of future results as

Exelon has not completed its planning or optimization processes for those years. The price distributions that generate this range are calibrated to market quotes for power, fuel,

load following products, and options as of September 30, 2011.

Midwest

Mid-Atlantic

South & West

Step 1

Start

with

fleetwide

open

gross

margin

$5.60 billion

Step 2

Determine

the

mark-to-market

value

energy hedges

98,500GWh * 98% *

($43.00/MWh-$33.61MWh)

= $0.91 billion

56,500GWh * 97% *

($56.50/MWh-$45.07MWh)

= $0.63 billion

11,300GWh * 95% *

($6.00/MWh-$11.58MWh)

= $(0.06) billion

Step 3

Estimate

hedged

gross

margin

adding open gross margin to mark-to-

market value of energy hedges

Open gross margin:

MTM value of energy hedges:

Estimated hedged gross margin:

$5.60 billion

$0.91billion

$0.63billion

$(0.06)

billion

$7.08 billion

Illustrative Example

of Modeling Exelon Generation 2011 Gross Margin

(with Existing Hedges)

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

$4.07

2013 $4.62

Rolling

months,

October

2011.

Source:

OTC

quotes

and

electronic

trading

system.

Quotes

are

daily.

Forward NYMEX Coal

2012

$74.25

2013

$77.25

2012 Ni-Hub $39.86

2013 Ni-Hub

$41.73

2013 PJM-West $53.74

2012 PJM-West

$51.14

2012 Ni-Hub

$26.79

2013 Ni-Hub

$28.24

2013 PJM-West

$40.19

2012 PJM-West

$38.43

4.0

4.5

5.0

5.5

6.0

6.5

7.0

10/10

11/10

12/10

1/11

2/11

3/11

4/11

5/11

6/11

7/11

8/11

9/11

10/11

10/10

11/10

12/10

1/11

2/11

3/11

4/11

5/11

6/11

7/11

8/11

9/11

10/11

10/10

11/10

12/10

1/11

2/11

3/11

4/11

5/11

6/11

7/11

8/11

9/11

10/11

10/10

11/10

12/10

1/11

2/11

3/11

4/11

5/11

6/11

7/11

8/11

9/11

10/11

4.5

5.5

6.5

7.5

8.5

9.5

10.5

11.5

12.5

13.5

10/10

11/10

12/10

1/11

2/11

3/11

4/11

5/11

6/11

7/11

8/11

9/11

10/11

8.2

8.4

8.6

8.8

9.0

9.2

9.4

9.6

9.8

10.0

10.2

10.4

10.6

10.8

11.0

10/10

11/10

12/10

1/11

2/11

3/11

4/11

5/11

6/11

7/11

8/11

9/11

10/11

10/10

11/10

12/10

1/11

2/11

3/11

4/11

5/11

6/11

7/11

8/11

9/11

10/11

3.5

4.0

4.5

5.0

5.5

6.0

6.5

7.0

10/10

11/10

12/10

1/11

2/11

3/11

4/11

5/11

6/11

7/11

8/11

9/11

10/11

Market Price Snapshot

2013

10.64

2012

10.89

2012

$43.23

2013

$48.04

2012

$3.97

2013

$4.51

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

$12.07

2013

$12.96

ERCOT North On Peak Spark Spread

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

Rolling

months,

October

2011.

Source:

OTC

quotes

and

electronic

trading

system.

Quotes

are

daily.

Appendix

Maryland PSC Review Schedule

(Case No. 9271)

Significant Events

Date of Event

Filing of Application

May 25, 2011

Intervention Deadline

June 24, 2011

Prehearing Conference

June 28, 2011

Filing of Staff, Office of People Counsel and Intervenor Testimony

September 16, 2011*

Filing of Rebuttal Testimony

October 12, 2011*

Filing of Surrebuttal Testimony

October 26, 2011

Status Conference

October 28, 2011

Evidentiary Hearings

October 31, 2011 -

November 18, 2011

Public Comment Hearings

November 29, December 1 &

December 5, 2011

Filing of Initial Briefs

December 1, 2011

Filing of Reply Briefs

December 15, 2011

Decision Deadline

January 5, 2012

* Initial

intervenor

testimony

with

respect

market

power

was

due

September

for

all

parties except for the

Independent Market

Monitor

and

rebuttal

testimony

with

respect

market

power

was

due

October

ComEd Load Trends

Weather-Normalized Load Year-over-Year

4Q11

3Q11

2Q11

1Q11

4Q10

3Q10

2Q10

1Q10

Gross Metro Product

Residential

Large C&I

All Customer Classes

Chicago

U.S.

Unemployment rate

(1)

2011 annualized growth in

gross

domestic/metro

product

(2)

Note: C&I = Commercial & Industrial

Key Economic Indicators

Weather-Normalized Load

2010

3Q11 2011E

Average Customer Growth

0.2%

0.5%

Average Use-Per-Customer

(1.4)%

(2.9)%

(1.7)%

Total Residential

(1.2)%

(2.4)% (1.2)%

Small C&I

(0.6)%

(2.2)%

(0.8)%

Large C&I

2.6%

0.1%

All Customer Classes

0.2%

(1.4)%

(0.6)%

(1)

Source: U.S. Dept. of Labor (September 2011) and Illinois

Department of Employment Security (September 2011)

(2) Source: Global Insight (August 2011)

-6%

-4%

-2%

9.1%

1.6%

10.5%

1.0%

PECO Load Trends

Weather-Normalized Load

Note: C&I = Commercial & Industrial

4Q11

3Q11

2Q11

1Q11

4Q10

3Q10

2Q10

1Q10

Gross Metro Product

Residential

Large C&I

All Customer Classes

Philadelphia

U.S.

Unemployment rate

(1)

9.0%

9.1%

2011 annualized growth in

gross domestic/metro product

(2)

0.7% 1.6%

2010

3Q11 2011E

Average Customer Growth

0.3%

Average Use-Per-Customer

0.3%

1.8%

1.9%

Total Residential

0.5%

2.1%

2.3%

Small C&I

(1.9)%

(3.2)%

(1.0)%

Large C&I

0.8%

(0.6)%

(2.7)%

All Customer Classes

0.1%

(0.1)%

(0.5)%

(1)

Source:

U.S.

Dept.

Labor

data

(September

2011)

–

U.S.

Dept.

Labor

prelim.

data

(August

2011)

–

Philadelphia

(2) Source: Global Insight (August 2011)

Weather-Normalized Load Year-over-Year

Key Economic Indicators

-6%

-4%

-2%

Sufficient Liquidity

($ millions)

Exelon

(3)

Aggregate Bank Commitments

(1)

$1,000

$600

$5,600

$7,700

Outstanding Facility Draws

Outstanding Letters of Credit

(1)

(122)

(131)

Available Capacity Under Facilities

(2)

999

599

5,478

7,569

Outstanding Commercial Paper

(28)

(356)

Available Capacity Less Outstanding

Commercial Paper

$999

$599

$5,450

$7,213

Available Capacity Under Bank Facilities as of October 21, 2011

Exelon bank facilities are largely untapped

(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 Exelon Corp’s $500M credit facility, letters of credit and commercial paper outstanding.

Key Credit Metrics

(1)

See slide 32 for reconciliations to GAAP.

(2)

Current senior unsecured ratings for Exelon and Exelon Generation and senior secured ratings for

ComEd and PECO as of October 14, 2011.

(3)

Moody’s placed Exelon and Generation under review for a possible downgrade after the proposed

merger with Constellation Energy was announced. S&P and Fitch affirmed ratings of Exelon and

subsidiaries after the proposed merger was announced.

(4)

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

Exelon Corp. Range represents FFO/Debt to maintain current ratings at current business risk.

Moody’s Credit

Ratings

(2) (3)

S&P Credit

Ratings

(2) (3)

Fitch Credit

Ratings

(2) (3)

FFO / Debt

Target

Range

Exelon:

Baa1

BBB-

BBB+

ComEd:

Baa1

A-

BBB+

15-18%

PECO:

A-

15-18%

Generation:

BBB

BBB+

30-35%

(4)

Exelon

PECO

ComEd

2011E

2010A

2009A

Exelon

PECO

ComEd

2011E

2010A

2009A

Exelon

PECO

ComEd

2011E

2010A

2009A

FFO/Debt

(1)

Interest Coverage

(1)

Debt to Cap

(1)

40%

50%

60%

70%

80%

10X

12X

10%

20%

30%

40%

50%

ExGen/

Corp

ExGen/

Corp

ExGen/

Corp

Exelon Consolidated Metric Calculations and Ratios

(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

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

295

Commitments

and

Contingencies

(7)

+ Pension/OPEB Imputed Debt

3,825

268

Post-retirement

benefits

(8)

+ Operating Lease Imputed Debt

428

299

Commitments

and

Contingencies

(9)

+ Asset Retirement Obligation

261-267

Asset

Retirement

Obligations

(10)

+/-

Other Minor Debt Equivalents

(11)

= Adjusted Debt (b)

18,845

Interest Calculation

Net Interest Expense

817

158

Statement

Operations

PECO Transition Bond Interest Expense

(22)

182

Significant

Accounting

Policies

+ Interest on Present Value (PV) of Operating Leases

299

Commitments

and

Contingencies

(12)

+ Interest on PV of Purchased Power Agreements (PPAs)

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

3Q GAAP EPS Reconciliation

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

Three Months Ended September 30, 2010

ExGen

ComEd

PECO

Other

Exelon

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

$0.75

$0.18

$0.19

$(0.01)

$1.11

2007 Illinois electric rate settlement

0.00

Mark-to-market impact of economic hedging activities

0.14

Unrealized gains related to nuclear decommissioning trust funds

0.09

Retirement of fossil generating units

(0.02)

Emission allowances impairment

(0.05)

3Q 2010 GAAP Earnings (Loss) Per Share

$0.91

$0. 18

$0.19

$(0.01)

$1.27

Three Months Ended September 30, 2011

ExGen

ComEd

PECO

Other

Exelon

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

$0.79

$0.17

$0.16

$0.01

$1.12

Mark-to-market impact of economic hedging activities

(0.08)

Unrealized losses related to nuclear decommissioning trust funds

(0.12)

Asset retirement obligation

(0.03)

0.00

(0.02)

Retirement of fossil generating units

(0.00)

Constellation acquisition costs

(0.00)

(0.01)

(0.02)

AVSR 1 acquisition costs

(0.01)

Wolf Hollow acquisition

0.03

3Q 2011 GAAP Earnings (Loss) Per Share

$0.58

$0.17

$0.16

$(0.00)

$0.90

YTD GAAP EPS Reconciliation

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

Nine Months Ended September 30, 2010

ExGen

ComEd

PECO

Other

Exelon

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

$2.10

$0.55

$0.51

$(0.06)

$3.10

2007 Illinois electric rate settlement

(0.01)

Mark-to-market impact of economic hedging activities

0.25

Unrealized gains related to nuclear decommissioning trust funds

0.04

Non-cash charge resulting from health care legislation

(0.04)

(0.02)

(0.10)

Non-cash remeasurement of income tax uncertainties

0.10

(0.16)

(0.03)

(0.01)

(0.10)

Retirement of fossil generating units

(0.05)

Emission allowances impairment

(0.05)

YTD 2010 GAAP Earnings (Loss) Per Share

$2.34

$0.37

$0.46

$(0.09)

$3.08

Nine Months Ended September 30, 2011

ExGen

ComEd

PECO

Other

Exelon

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

$2.47

$0.43

$0.47

$(0.03)

$3.34

Mark-to-market impact of economic hedging activities

(0.34)

Unrealized losses related to nuclear decommissioning trust funds

(0.07)

Retirement of fossil generating units

(0.04)

Asset retirement obligation

(0.03)

0.00

(0.02)

Constellation acquisition costs

(0.00)

(0.03)

(0.04)

AVSR 1 acquisition costs

(0.01)

Non-cash charge resulting from Illinois tax rate change legislation

(0.03)

(0.01)

(0.00)

(0.04)

Wolf Hollow acquisition

0.03

Recovery of costs pursuant to distribution rate case order

0.03

YTD 2011 GAAP Earnings (Loss) Per Share

$1.99

$0.44

$0.47

$(0.07)

$2.84

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

•

Changes in decommissioning obligation and asset retirement 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

•

One-time benefits reflecting ComEd’s 2011 distribution rate case order for the recovery of

previously

incurred

costs

the

2009

restructuring

plan

and

for

the

passage

Federal

health care legislation in 2010

•

Certain costs associated with Exelon’s acquisition of a wind portfolio (now known as Exelon

Wind) and AVSR 1, and Exelon’s proposed merger with Constellation

•

Non-cash

gain

purchase

connection

with

the

acquisition

Wolf

Hollow,

net

acquisition

costs

•

Non-cash charge remeasurement of income tax uncertainties

•

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

•

Costs associated with the 2007 electric rate settlement agreement

•

Impairment of certain emission allowances

•

Other unusual items

•

Significant changes to GAAP

Operating

earnings

guidance

assumes

normal

weather

for

remainder

the

year