8-K

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, DC 20549

FORM 8-K

CURRENT REPORT

Pursuant to Section 13 or 15(d) of the

Securities Exchange Act of 1934

January 25, 2012

Date of Report (Date of earliest event reported)

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

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

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

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

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

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

Section 2 – Financial Information

Item 2.02. Results of Operations and Financial Condition.

Section 7 – Regulation FD

Item 7.01. Regulation FD Disclosure.

On January 25, 2012, Exelon Corporation (Exelon) announced via press release its results for the fourth quarter ended December 31, 2011. A copy of the press release and related attachments is attached hereto as Exhibit 99.1. Also attached as Exhibit 99.2 to this Current Report on Form 8-K are the presentation slides to be used at the fourth 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 January 25, 2012. 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 40223937. Media representatives are invited to participate on a listen-only basis. The call will be web-cast and archived on Exelon’s Web site: www.exeloncorp.com. (Please select the Investors page.)

Telephone replays will be available until February 8^th. 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 40223937.

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

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 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; (2) conditions to the closing of the merger may not be satisfied; (3) an unsolicited offer of another company to acquire assets or capital stock of Exelon or Constellation could interfere with the merger; (4) 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; (5) the combined company may be unable to achieve cost-cutting synergies or it may take longer than expected to achieve those synergies; (6) the merger may involve unexpected costs, unexpected liabilities or unexpected delays, or the effects of purchase accounting may be different from the companies’ expectations; (7) the credit ratings of the combined company or its subsidiaries may be different from what the companies expect; (8) the businesses of the companies may suffer as a result of uncertainty surrounding the merger; (9) the companies may not realize the values expected to be obtained for properties expected or required to be divested; (10) the industry may be subject to future regulatory or legislative actions that could adversely affect the companies; and (11) 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 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 September 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

January 25, 2012

EXHIBIT INDEX

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

EX-99.1

Exhibit 99.1

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

Exelon Announces Fourth Quarter and Full Year 2011 Results

CHICAGO (January 25, 2012) – Exelon Corporation (NYSE: EXC) announced fourth quarter and full year 2011 consolidated earnings as follows:

	Exelon Consolidated Earnings (unaudited)
	Full Year				Fourth Quarter
	2011		2010		2011		2010
Adjusted (non-GAAP) Operating Results:
Net Income ($ millions)	$	2,763	$	2,689	$	544	$	631
Diluted Earnings per Share	$	4.16	$	4.06	$	0.82	$	0.96
GAAP Results:
Net Income ($ millions)	$	2,495	$	2,563	$	606	$	524
Diluted Earnings per Share	$	3.75	$	3.87	$	0.91	$	0.79

“Our full year 2011 operating earnings were within our guidance range, as well as above our original expectations for the year,” said John W. Rowe, Exelon’s chairman and CEO. “Despite the impact of adverse economic, market and weather conditions, we achieved our financial commitments and operational excellence across the company.”

Rowe added, “Our significant accomplishments in 2011 included making considerable progress towards completion of our strategic merger with Constellation Energy and continuing to improve our industry-leading environmental position with additions of clean generation assets.”

Fourth Quarter Operating Results

As shown in the table above, Exelon’s adjusted (non-GAAP) operating earnings declined to $0.82 per share in the fourth quarter of 2011 from $0.96 per share in the fourth quarter of 2010. Earnings in 2011 primarily reflected the following adverse factors:

• The effect on energy margins at Exelon Generation Company, LLC (Generation) of decreased capacity pricing related to the Reliability Pricing Model (RPM) for the PJM Interconnection, LLC (PJM) market and higher nuclear fuel costs;

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

• The effect of unfavorable weather in the PECO Energy Company (PECO) and Commonwealth Edison Company (ComEd) service territories; and

• Increased depreciation and amortization expense.

These factors were partially offset by:

• The net favorable effect on Generation’s energy margins primarily reflecting market and portfolio conditions in the Mid-Atlantic and Midwest regions;

• The effect of new distribution rates at PECO and ComEd effective January 1, 2011 and June 1, 2011, respectively;

• The effect of 2010 competitive transition charge (CTC) amortization expense, net of collections, at PECO associated with its transition period, which ended on December 31, 2010; and

• Increased distribution revenues at ComEd as a result of the annual reconciliation in the performance-based distribution formula rate tariff and a net reduction in operating and maintenance expenses at ComEd for the allowed recovery of certain 2011 storm costs, both pursuant to the Energy Infrastructure Modernization Act, which became effective in the fourth quarter of 2011.

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

	(in millions)			(per diluted share)
Unrealized gains related to nuclear decommissioning trust (NDT) fund investments to the extent not offset by contractual accounting	$	46		$	0.07
Mark-to-market gains primarily from Generation’s economic hedging activities	$	45		$	0.07
Certain costs associated with the proposed merger with Constellation Energy Group, Inc. (Constellation)	$	(21	)	$	(0.03	)
Financial impacts associated with the retirement of certain Generation fossil generating units	$	(4	)	$	(0.01	)
Non-cash annual remeasurement of state deferred income taxes	$	(4	)	$	(0.01	)

Adjusted (non-GAAP) operating earnings for the fourth 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 losses primarily from Generation’s economic hedging activities	$	(113	)	$	(0.17	)
Unrealized gains related to NDT fund investments to the extent not offset by contractual accounting	$	26		$	0.04
Financial impacts associated with the retirement of certain Generation fossil generating units	$	(17	)	$	(0.03	)
Decrease in costs related to adjustments to asset retirement obligations of ComEd and PECO	$	7		$	0.01
Certain costs related to the acquisition of Exelon Wind	$	(6	)	$	(0.01	)
Costs associated with the 2007 Illinois electric rate settlement agreement	$	(4	)	$	(0.01	)

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Fourth Quarter and Recent Highlights

• Constellation Merger Update: Exelon and Constellation continue to move forward with the regulatory reviews needed to complete their proposed merger. On December 21, 2011, the U.S. Department of Justice (DOJ) cleared the way for the merger in connection with its review of the transaction under the Hart-Scott-Rodino Act. The DOJ’s Antitrust Division filed court papers seeking approval by the U.S. District Court for the District of Columbia with regard to the merger. These papers detail the conditions for the merger agreed to by the DOJ, Exelon and Constellation.

The merger has been approved by the New York Public Service Commission, the Public Utility Commission of Texas and shareholders of Exelon and Constellation. It also requires regulatory approvals by the Federal Energy Regulatory Commission, the Nuclear Regulatory Commission and the Maryland Public Service Commission. In a merger settlement with the State of Maryland, the Maryland Energy Administration (MEA), the City of Baltimore and the Baltimore Building and Construction Trades Council announced December 15, 2011, Exelon, Constellation and Baltimore Gas and Electric Company agreed to provide a package of benefits totaling more than $1 billion and expected to create more than 6,000 jobs in Maryland. Exelon and Constellation continue to expect that the merger will be finalized in early 2012.

• U.S. Environmental Protection Agency (EPA) Mercury and Air Toxics Rule: On December 16, 2011, the EPA signed a final Mercury and Air Toxics Standards (MATS) rule under the Clean Air Act, which will require existing and new coal-fired electricity generating plants to reduce emissions of mercury and other hazardous air pollutants. The MATS rule is largely in line with Exelon’s expectations and requires plants to meet the new standards three years after the rule takes effect, with specific guidelines for an additional one or two years in limited cases. The rule is effective 60 days after it is published in the Federal Register in early 2012.

• Nuclear Operations: Generation’s nuclear fleet, including its owned output from the Salem Generating Station, produced 34,893 gigawatt-hours (GWh) in the fourth quarter of 2011, compared with 35,115 GWh in the fourth quarter of 2010. The Exelon-operated nuclear plants achieved a 93.0 percent capacity factor for the fourth quarter of 2011 compared with 93.1 percent for the fourth quarter of 2010. The Exelon-operated nuclear plants completed five scheduled refueling outages in the fourth quarter of 2011, compared with completing four scheduled refueling outages in the fourth quarter of 2010. The number of planned refueling outage days totaled 103 in the fourth quarter of 2011 versus 97 days in the fourth quarter of 2010. The number of non-refueling outage days at the Exelon-operated plants totaled 11 days in the fourth quarter of 2011 compared with 18 days in the fourth quarter of 2010.

For the full year 2011, the Exelon-operated nuclear plants achieved an average capacity factor of 93.3 percent, as compared with 93.9 percent for 2010. The average annual capacity factor for the Exelon-operated nuclear fleet has exceeded 93 percent for nine consecutive years.

• Fossil and Hydro Operations: The equivalent demand forced outage rate for Generation’s fossil fleet (excluding the Wolf Hollow acquisition) was 1.6 percent in the fourth quarter of

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2011, compared with 2.9 percent in the fourth quarter of 2010. The change was largely due to a series of minor forced outages that took place at the Mid-Atlantic peaking units in 2010. The equivalent availability factor for the hydroelectric facilities was 95.9 percent in the fourth quarter of 2011, compared with 99.8 percent in the fourth quarter of 2010. The change was primarily due to a planned inspection outage in December 2011 that was rescheduled from the third quarter.

• Exelon Wind Project Completion: On December 30, 2011, Exelon Wind’s Michigan Wind 2 Project, located in Minden City, Michigan, was completed. The 50-turbine, 90-megawatt (MW) wind project is the first commercial wind project developed by Exelon Wind. Consumers Energy, based in Jackson, Michigan, is purchasing the output from the project through a 20-year renewable energy purchase agreement. The completion of Michigan Wind 2 brings Exelon Wind’s total generation in Michigan to 212 MW. In early 2012, Exelon Wind will begin construction on Harvest II Wind, a 59.4-MW project also located in Michigan.

• Shooting Star Wind Project Acquisition: On December 7, 2011, Exelon Wind and Infinity Wind Holdings, LLC entered into a purchase agreement by which Exelon Wind purchased all of the membership interests in Shooting Star Wind Project, LLC, a 104-MW wind power generation project in Kiowa County, Kansas. The acquisition includes a 20-year power purchase agreement with Mid-Kansas Electric Company for 100 percent of the project’s output. Construction of Shooting Star began in November 2011, and the project is expected to begin full commercial operation in the fourth quarter of 2012.

• Hedging Update: Exelon’s hedging program involves the hedging of commodity risk for Exelon’s expected generation, typically on a ratable basis over a three-year period. Expected generation represents the amount of energy estimated to be generated or purchased through owned or contracted-for capacity. The proportion of expected generation hedged as of December 31, 2011 is 88 to 91 percent for 2012, 61 to 64 percent for 2013 and 32 to 35 percent for 2014. The primary objectives of Exelon’s hedging program are to manage market risks and protect the value of its generation and its investment grade balance sheet while preserving its ability to participate in improving long-term market fundamentals.

• ComEd Infrastructure Investment, Performance Metrics and Formula Rate Filings: On January 6, 2012, ComEd filed its 10-year, $2.6 billion Infrastructure Investment Plan with the Illinois Commerce Commission (ICC). The filing supports the Energy Infrastructure Modernization Act (EIMA), which was enacted late last year. EIMA includes a policy-based approach that will provide a more predictable ratemaking system and enable utilities to modernize the electric grid and set the stage for fostering economic development while creating and retaining jobs. EIMA also includes a process for determining distribution formula rates that will provide for the recovery of actual costs of service that are prudent and reasonable. ComEd will invest $1.3 billion to strengthen the electric system and another $1.3 billion to add new, digital smart grid and advanced meter technology. ComEd’s plan for 2012 outlines $139 million in capital investments that will be dedicated to improving system reliability and $94 million in smart grid investments.

On December 8, 2011, ComEd made a filing under EIMA to request ICC approval of its proposed multi-year performance metrics plan. The metrics are designed to achieve improvement over baseline values in several performance categories over a 10-year period. The final ICC order must be issued by April 6, 2012.

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On November 8, 2011, ComEd submitted its first filing with the ICC under EIMA for a performance-based formula rate tariff, which initiated a process to establish the model to govern delivery service rate-setting and to set new rates. The initial rate, which is expected to be lower than current rates but will be subject to reconciliation, will take effect within 30 days after the ICC order, which must be issued by May 31, 2012. The filing does not include costs relating to ComEd’s abovementioned Infrastructure Investment Plan. ComEd will file a distribution formula rate plan and updated costs with the ICC each year. ComEd will make its initial reconciliation filing in May 2012, and the adjusted rates will take effect on January 1, 2013 after the ICC’s review. As of December 31, 2011, ComEd recorded its estimated reconciliation for 2011.

• PECO Default Service Plan Filing: On January 13, 2012, PECO filed its Default Service Plan for approval with the Pennsylvania Public Utility Commission (PAPUC). The plan outlines how PECO will purchase electricity for customers not purchasing from a competitive electric generation supplier from June 1, 2013 through May 31, 2015, and proposes several new programs to continue PECO’s support of retail competition in Pennsylvania. To continue to ensure a competitive procurement process for residential customers, PECO proposes to procure electricity through a combination of one-year and two-year fixed full requirements contracts, reduce the amount of time between when the energy is purchased and when it is provided to customers and complete an annual, rather than quarterly, reconciliation of costs for actual versus forecasted energy use. Public hearings for the filing are scheduled in the spring of 2012, with a PAPUC ruling expected in mid-October 2012.

OPERATING COMPANY RESULTS

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

Fourth quarter 2011 net income was $446 million compared with $424 million in the fourth quarter of 2010. Fourth quarter 2011 net income included (all after tax) unrealized gains of $46 million related to NDT fund investments, mark-to-market gains of $45 million from economic hedging activities, a $6 million benefit due to the non-cash annual remeasurement of state deferred income taxes, certain costs of $6 million associated with the proposed merger with Constellation and net costs of $4 million associated with the retirement of certain fossil generating units. Fourth quarter 2010 net income included (all after tax) mark-to-market losses of $113 million from economic hedging activities, unrealized gains of $26 million related to NDT fund investments, costs of $17 million associated with the retirement of certain fossil generating units, a charge of $6 million for certain costs associated with the acquisition of Exelon Wind and a charge of $4 million for costs associated with the 2007 Illinois electric rate settlement.

Excluding the effects of these items, Generation’s net income in the fourth quarter of 2011 decreased $179 million compared with the same quarter in 2010. This decrease primarily reflected:

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

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

• Increased depreciation and amortization expense.

These items were partially offset by the net favorable effect on energy margins primarily reflecting market and portfolio conditions in the Mid-Atlantic and Midwest regions.

Generation’s average realized margin on all electric sales, including sales to affiliates and excluding trading activity, was $39.31 per megawatt-hour (MWh) in the fourth quarter of 2011 compared with $41.45 per MWh in the fourth quarter of 2010.

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

ComEd recorded net income of $121 million in the fourth quarter of 2011, compared with net income of $91 million in the fourth quarter of 2010. Fourth quarter net income in 2010 included an after-tax decrease in costs of $6 million associated with an adjustment to ComEd’s asset retirement obligation. Excluding the effects of these items, ComEd’s net income in the fourth quarter of 2011 was up $36 million from the same quarter in 2010, primarily reflecting:

• Increased distribution revenues as a result of the annual reconciliation in the performance-based distribution formula rate tariff pursuant to EIMA, which became effective in the fourth quarter of 2011;

• A net reduction in operating and maintenance expenses for the allowed recovery of certain 2011 storm costs also pursuant to EIMA; and

• The impact of new electric distribution rates effective June 1, 2011.

These items were partially offset by increased other operating and maintenance expenses and the effect of unfavorable weather in ComEd’s service territory.

In the fourth quarter of 2011, heating degree-days in the ComEd service territory were down 20.1 percent relative to the same period in 2010 and were 19.6 percent below normal. Total retail electric deliveries decreased 2.6 percent quarter over quarter.

Weather-normalized retail electric deliveries increased 0.4 percent in the fourth quarter of 2011 relative to 2010, reflecting increases in deliveries to residential and large commercial and industrial (C&I) customers that were partially offset by a decrease in deliveries to small C&I customers. For ComEd, weather had an unfavorable after-tax effect of $7 million on fourth quarter 2011 earnings relative to 2010 and an unfavorable after-tax effect of $6 million relative to normal weather that is incorporated in Exelon’s earnings guidance.

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

PECO’s net income in the fourth quarter of 2011 was $74 million, up from $21 million in the fourth quarter of 2010. Fourth quarter net income in 2011 included certain after-tax costs of $1 million associated with the proposed merger with Constellation. Fourth quarter net income in 2010 included an after-tax decrease in costs of $1 million associated with an adjustment to PECO’s asset retirement obligation. Excluding the effects of these items, PECO’s net income in the fourth quarter of 2011 was up $55 million from the same quarter in 2010, primarily reflecting:

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

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

Partially offsetting these items was the effect of unfavorable weather in PECO’s service territory.

In the fourth quarter of 2011, heating degree-days in the PECO service territory were down 22.8 percent from 2010 and were 20.3 percent below normal. Total retail electric deliveries were down 6.1 percent from last year. On the retail gas side, deliveries in the fourth quarter of 2011 were down 22.7 percent from the fourth quarter of 2010.

Weather-normalized retail electric deliveries were down 2.2 percent in the fourth quarter of 2011 relative to 2010, reflecting a decline in large C&I deliveries that was partially offset by increased deliveries to residential and small C&I customers. Weather-normalized retail gas deliveries were up 1.9 percent in the fourth quarter of 2011. For PECO, weather had an unfavorable after-tax effect of $25 million on fourth quarter 2011 earnings relative to 2010 and an unfavorable after-tax effect of $22 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 January 25, 2012.

Conference call information: Exelon has scheduled a conference call for 11:00 AM ET (10:00 AM CT) on January 25, 2012. 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 40223937. Media representatives are invited to participate on a listen-only basis. The call will be web-cast and archived on Exelon’s Web site: www.exeloncorp.com. (Please select the Investors page.)

Telephone replays will be available until February 8, 2012. 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 40223937.

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,”

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“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 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; (2) conditions to the closing of the merger may not be satisfied; (3) an unsolicited offer of another company to acquire assets or capital stock of Exelon or Constellation could interfere with the merger; (4) 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; (5) the combined company may be unable to achieve cost-cutting synergies or it may take longer than expected to achieve those synergies; (6) the merger may involve unexpected costs, unexpected liabilities or unexpected delays, or the effects of purchase accounting may be different from the companies’ expectations; (7) the credit ratings of the combined company or its subsidiaries may be different from what the companies expect; (8) the businesses of the companies may suffer as a result of uncertainty surrounding the merger; (9) the companies may not realize the values expected to be obtained for properties expected or required to be divested; (10) the industry may be subject to future regulatory or legislative actions that could adversely affect the companies; and (11) 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 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 September 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

8

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.

###

Exelon Corporation is one of the nation’s largest electric utilities with more than $19 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 494,000 customers in the Philadelphia area. Exelon is headquartered in Chicago and trades on the NYSE under the ticker EXC.

9

Earnings Release Attachments

Table of Contents

Consolidating Statements of Operations—Three Months Ended December 31, 2011 and 2010	1
Consolidating Statements of Operations—Twelve Months Ended December 31, 2011 and 2010	2
Business Segment Comparative Statements of Operations—Generation and ComEd—Three and Twelve Months Ended December 31, 2011 and 2010	3
Business Segment Comparative Statements of Operations—PECO and Other—Three and Twelve Months Ended December 31, 2011 and 2010	4
Consolidated Balance Sheets—December 31, 2011 and December 31, 2010	5
Consolidated Statements of Cash Flows—Twelve Months Ended December 31, 2011 and 2010	6
Reconciliation of Adjusted (non-GAAP) Operating Earnings to GAAP Consolidated Statements of Operations—Exelon—Three Months Ended December  31, 2011 and 2010	7
Reconciliation of Adjusted (non-GAAP) Operating Earnings to GAAP Consolidated Statements of Operations—Exelon—Twelve Months Ended December  31, 2011 and 2010	8
Reconciliation of Adjusted (non-GAAP) Operating Earnings to GAAP Earnings By Business Segment—Three Months Ended December 31, 2011 and 2010	9
Reconciliation of Adjusted (non-GAAP) Operating Earnings to GAAP Earnings By Business Segment—Twelve Months Ended December 31, 2011 and 2010	11
Reconciliation of Adjusted (non-GAAP) Operating Earnings to GAAP Consolidated Statements of Operations—Generation—Three and Twelve Months Ended December 31, 2011 and 2010	13
Reconciliation of Adjusted (non-GAAP) Operating Earnings to GAAP Consolidated Statements of Operations—ComEd—Three and Twelve Months Ended December 31, 2011 and 2010	14
Reconciliation of Adjusted (non-GAAP) Operating Earnings to GAAP Consolidated Statements of Operations—PECO—Three and Twelve Months Ended December 31, 2011 and 2010	15
Reconciliation of Adjusted (non-GAAP) Operating Earnings to GAAP Consolidated Statements of Operations—Other—Three and Twelve Months Ended December 31, 2011 and 2010	16
Exelon Generation Statistics—Three Months Ended December 31, 2011, September 30, 2011, June 30, 2011, March  31, 2011 and December 31, 2010	17
Exelon Generation Statistics—Twelve Months Ended December 31, 2011 and 2010	18
ComEd Statistics—Three and Twelve Months Ended December 31, 2011 and 2010	19
PECO Statistics—Three and Twelve Months Ended December 31, 2011 and 2010	20

EXELON CORPORATION

Consolidating Statements of Operations

(unaudited)

(in millions)

		$0,00			$0,00			$0,00			$0,00			$0,00
	Three Months Ended December 31, 2011
	Generation			ComEd			PECO			Other (b)			Exelon Consolidated
Operating revenues	$	2,421		$	1,362		$	778		$	(310	)	$	4,251
Operating expenses
Purchased power		381			599			282			(320	)		942
Fuel		306			—			76			—			382
Operating and maintenance		842			239			182			26			1,289
Operating and maintenance for regulatory required programs (a)		—			31			14			—			45
Depreciation and amortization		154			137			53			4			348
Taxes other than income		65			71			40			7			183
Total operating expenses		1,748			1,077			647			(283	)		3,189
Operating income (loss)		673			285			131			(27	)		1,062
Other income and deductions
Interest expense		(43	)		(87	)		(32	)		(19	)		(181	)
Other, net		134			4			2			8			148
Total other income and deductions		91			(83	)		(30	)		(11	)		(33	)
Income (loss) before income taxes		764			202			101			(38	)		1,029
Income taxes		318			81			27			(3	)		423
Net income (loss)	$	446		$	121		$	74		$	(35	)	$	606

	Three Months Ended December 31, 2010
	Generation			ComEd			PECO			Other (b)			Exelon Consolidated
Operating revenues	$	2,596		$	1,372		$	1,299		$	(773	)	$	4,494
Operating expenses
Purchased power		602			671			652			(773	)		1,152
Fuel		418			—			123			—			541
Operating and maintenance		731			247			172			10			1,160
Operating and maintenance for regulatory required programs (a)		—			27			17			—			44
Depreciation and amortization		129			130			201			5			465
Taxes other than income		56			68			64			5			193
Total operating expenses		1,936			1,143			1,229			(753	)		3,555
Operating income (loss)		660			229			70			(20	)		939
Other income and deductions
Interest expense		(44	)		(86	)		(34	)		(19	)		(183	)
Other, net		118			10			2			5			135
Total other income and deductions		74			(76	)		(32	)		(14	)		(48	)
Income (loss) before income taxes		734			153			38			(34	)		891
Income taxes		310			62			17			(22	)		367
Net income (loss)	$	424		$	91		$	21		$	(12	)	$	524

(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.

1

EXELON CORPORATION

Consolidating Statements of Operations

(unaudited)

(in millions)

		$0,0.000			$0,0.000			$0,0.000			$0,0.000			$0,0.000
	Twelve Months Ended December 31, 2011
	Generation			ComEd			PECO			Other (b)			Exelon Consolidated
Operating revenues	$	10,568		$	6,056		$	3,720		$	(1,160	)	$	19,184
Operating expenses
Purchased power		2,182			3,035			1,547			(1,220	)		5,544
Fuel		1,528			—			317			(1	)		1,844
Operating and maintenance		3,148			1,086			725			53			5,012
Operating and maintenance for regulatory required programs (a)		—			115			69			—			184
Depreciation and amortization		570			542			202			21			1,335
Taxes other than income		264			296			205			20			785
Total operating expenses		7,692			5,074			3,065			(1,127	)		14,704
Operating income (loss)		2,876			982			655			(33	)		4,480
Other income and deductions
Interest expense		(170	)		(345	)		(134	)		(77	)		(726	)
Loss in equity method investments		(1	)		—			—			—			(1	)
Other, net		122			29			14			34			199
Total other income and deductions		(49	)		(316	)		(120	)		(43	)		(528	)
Income (loss) before income taxes		2,827			666			535			(76	)		3,952
Income taxes		1,056			250			146			5			1,457
Net income (loss)	$	1,771		$	416		$	389		$	(81	)	$	2,495

		$00.,00			$00.,00			$00.,00			$00.,00			$00.,00
	Twelve Months Ended December 31, 2010
	Generation			ComEd			PECO			Other (b)			Exelon Consolidated
Operating revenues	$	10,025		$	6,204		$	5,519		$	(3,104	)	$	18,644
Operating expenses
Purchased power		1,853			3,307			2,361			(3,096	)		4,425
Fuel		1,610			—			401			(1	)		2,010
Operating and maintenance		2,812			975			680			(14	)		4,453
Operating and maintenance for regulatory required programs (a)		—			94			53			—			147
Depreciation and amortization		474			516			1,060			25			2,075
Taxes other than income		230			256			303			19			808
Total operating expenses		6,979			5,148			4,858			(3,067	)		13,918
Operating income (loss)		3,046			1,056			661			(37	)		4,726
Other income and deductions
Interest expense		(153	)		(386	)		(193	)		(85	)		(817	)
Other, net		257			24			8			23			312
Total other income and deductions		104			(362	)		(185	)		(62	)		(505	)
Income (loss) before income taxes		3,150			694			476			(99	)		4,221
Income taxes		1,178			357			152			(29	)		1,658
Net income (loss)	$	1,972		$	337		$	324		$	(70	)	$	2,563

(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.

2

EXELON CORPORATION

Business Segment Comparative Statements of Operations

(unaudited)

(in millions)

		$6,0.56			$6,0.56			$6,0.56			$6,0.56			$6,0.56			$6,0.56
	Generation
	Three Months Ended December 31,									Twelve Months Ended December 31,
	2011			2010			Variance			2011			2010			Variance
Operating revenues	$	2,421		$	2,596		$	(175	)	$	10,568		$	10,025		$	543
Operating expenses
Purchased power		381			602			(221	)		2,182			1,853			329
Fuel		306			418			(112	)		1,528			1,610			(82	)
Operating and maintenance		842			731			111			3,148			2,812			336
Depreciation and amortization		154			129			25			570			474			96
Taxes other than income		65			56			9			264			230			34
Total operating expenses		1,748			1,936			(188	)		7,692			6,979			713
Operating income		673			660			13			2,876			3,046			(170	)
Other income and deductions
Interest expense		(43	)		(44	)		1			(170	)		(153	)		(17	)
Loss in equity method investments		—			—			—			(1	)		—			(1	)
Other, net		134			118			16			122			257			(135	)
Total other income and deductions		91			74			17			(49	)		104			(153	)
Income before income taxes		764			734			30			2,827			3,150			(323	)
Income taxes		318			310			8			1,056			1,178			(122	)
Net income	$	446		$	424		$	22		$	1,771		$	1,972		$	(201	)

		$6,05.a			$6,05.a			$6,05.a			$6,05.a			$6,05.a			$6,05.a
	ComEd
	Three Months Ended December 31,									Twelve Months Ended December 31,
	2011			2010			Variance			2011			2010			Variance
Operating revenues	$	1,362		$	1,372		$	(10	)	$	6,056		$	6,204		$	(148	)
Operating expenses
Purchased power		599			671			(72	)		3,035			3,307			(272	)
Operating and maintenance		239			247			(8	)		1,086			975			111
Operating and maintenance for regulatory required programs (a)		31			27			4			115			94			21
Depreciation and amortization		137			130			7			542			516			26
Taxes other than income		71			68			3			296			256			40
Total operating expenses		1,077			1,143			(66	)		5,074			5,148			(74	)
Operating income		285			229			56			982			1,056			(74	)
Other income and deductions
Interest expense		(87	)		(86	)		(1	)		(345	)		(386	)		41
Other, net		4			10			(6	)		29			24			5
Total other income and deductions		(83	)		(76	)		(7	)		(316	)		(362	)		46
Income before income taxes		202			153			49			666			694			(28	)
Income taxes		81			62			19			250			357			(107	)
Net income	$	121		$	91		$	30		$	416		$	337		$	79

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

3

EXELON CORPORATION

Business Segment Comparative Statements of Operations

(unaudited)

(in millions)

		$00,000			$00,000			$00,000			$00,000			$00,000			$00,000
	PECO
	Three Months Ended December 31,									Twelve Months Ended December 31,
	2011			2010			Variance			2011			2010			Variance
Operating revenues	$	778		$	1,299		$	(521	)	$	3,720		$	5,519		$	(1,799	)
Operating expenses
Purchased power		282			652			(370	)		1,547			2,361			(814	)
Fuel		76			123			(47	)		317			401			(84	)
Operating and maintenance		182			172			10			725			680			45
Operating and maintenance for regulatory required programs (a)		14			17			(3	)		69			53			16
Depreciation and amortization		53			201			(148	)		202			1,060			(858	)
Taxes other than income		40			64			(24	)		205			303			(98	)
Total operating expenses		647			1,229			(582	)		3,065			4,858			(1,793	)
Operating income		131			70			61			655			661			(6)
Other income and deductions
Interest expense		(32	)		(34	)		2			(134	)		(193	)		59
Other, net		2			2			—			14			8			6
Total other income and deductions		(30	)		(32	)		2			(120	)		(185	)		65
Income before income taxes		101			38			63			535			476			59
Income taxes		27			17			10			146			152			(6	)
Net income	$	74		$	21		$	53		$	389		$	324		$	65

		$00,000			$00,000			$00,000			$00,000			$00,000			$00,000
	Other (b)
	Three Months Ended December 31,									Twelve Months Ended December 31,
	2011			2010			Variance			2011			2010			Variance
Operating revenues	$	(310	)	$	(773	)	$	463		$	(1,160	)	$	(3,104	)	$	1,944
Operating expenses
Purchased power		(320	)		(773	)		453			(1,220	)		(3,096	)		1,876
Fuel		—			—			—			(1	)		(1	)		—
Operating and maintenance		26			10			16			53			(14	)		67
Depreciation and amortization		4			5			(1	)		21			25			(4	)
Taxes other than income		7			5			2			20			19			1
Total operating expenses		(283	)		(753	)		470			(1,127	)		(3,067	)		1,940
Operating loss		(27	)		(20	)		(7	)		(33	)		(37	)		4
Other income and deductions
Interest expense		(19	)		(19	)		—			(77	)		(85	)		8
Other, net		8			5			3			34			23			11
Total other income and deductions		(11	)		(14	)		3			(43	)		(62	)		19
Loss before income taxes		(38	)		(34	)		(4	)		(76	)		(99	)		23
Income taxes		(3	)		(22	)		19			5			(29	)		34
Net loss	$	(35	)	$	(12	)	$	(23	)	$	(81	)	$	(70	)	$	(11	)

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

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

4

EXELON CORPORATION

Consolidated Balance Sheets

(unaudited)

(in millions)

		$000,00			$000,00
	December 31, 2011			December 31, 2010
ASSETS
Current assets
Cash and cash equivalents	$	1,016		$	1,612
Restricted cash and investments		40			30
Accounts receivable, net
Customer		1,629			1,932
Other		984			1,196
Mark-to-market derivative assets		432			487
Inventories, net
Fossil fuel		208			216
Materials and supplies		656			590
Deferred income taxes		97			—
Regulatory assets		69			10
Other		358			325
Total current assets		5,489			6,398
Property, plant and equipment, net		32,570			29,941
Deferred debits and other assets
Regulatory assets		4,839			4,140
Nuclear decommissioning trust (NDT) funds		6,507			6,408
Investments		766			732
Goodwill		2,625			2,625
Mark-to-market derivative assets		650			409
Pledged assets for Zion Station decommissioning		734			824
Other		912			763
Total deferred debits and other assets		17,033			15,901
Total assets	$	55,092		$	52,240
Liabilities and shareholders’ equity
Current liabilities
Short-term borrowings	$	163		$	—
Short-term notes payable — accounts receivable agreement		225			225
Long-term debt due within one year		828			599
Accounts payable		1,444			1,373
Mark-to-market derivative liabilities		112			38
Accrued expenses		1,255			1,040
Deferred income taxes		—			85
Regulatory liabilities		53			44
Dividends payable		349			1
Other		560			835
Total current liabilities		4,989			4,240
Long-term debt		11,799			11,614
Long-term debt to financing trusts		390			390
Deferred credits and other liabilities
Deferred income taxes and unamortized investment tax credits		8,351			6,621
Asset retirement obligations		3,884			3,494
Pension obligations		2,194			3,658
Non-pension postretirement benefit obligations		2,263			2,218
Spent nuclear fuel obligation		1,019			1,018
Regulatory liabilities		3,771			3,555
Mark-to-market derivative liabilities		126			21
Payable for Zion Station decommissioning		563			659
Other		1,268			1,102
Total deferred credits and other liabilities		23,439			22,346
Total liabilities		40,617			38,590
Preferred securities of subsidiary		87			87
Shareholders’ equity
Common stock		9,107			9,006
Treasury stock, at cost		(2,327	)		(2,327	)
Retained earnings		10,055			9,304
Accumulated other comprehensive loss, net		(2,450	)		(2,423	)
Total shareholders’ equity		14,385			13,560
Noncontrolling interest		3			3
Total equity		14,388			13,563
Total liabilities and shareholders’ equity	$	55,092		$	52,240

5

EXELON CORPORATION

Consolidated Statements of Cash Flows

(unaudited)

(in millions)

	Twelve Months  Ended December 31,
	2011			2010
Cash flows from operating activities
Net income	$	2,495		$	2,563
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation, amortization and accretion, including nuclear fuel amortization		2,304			2,943
Deferred income taxes and amortization of investment tax credits		1,457			981
Net fair value changes related to derivatives		291			(88	)
Net realized and unrealized losses (gains) on NDT fund investments		14			(105	)
Other non-cash operating activities		782			609
Changes in assets and liabilities:
Accounts receivable		57			(232	)
Inventories		(58	)		(62	)
Accounts payable, accrued expenses and other current liabilities		(254	)		472
Option premiums paid, net		(3	)		(124	)
Counterparty collateral posted, net		(344	)		(155	)
Income taxes		423			(543	)
Pension and non-pension postretirement benefit contributions		(2,360	)		(959	)
Other assets and liabilities		49			(56	)
Net cash flows provided by operating activities		4,853			5,244
Cash flows from investing activities
Capital expenditures		(4,042	)		(3,326	)
Proceeds from nuclear decommissioning trust fund sales		6,139			3,764
Investment in nuclear decommissioning trust funds		(6,332	)		(3,907	)
Acquisitions		(387	)		(893	)
Proceeds from sales of investments		6			28
Purchases of investments		(4	)		(22	)
Change in restricted cash		(3	)		423
Other investing activities		20			39
Net cash flows used in investing activities		(4,603	)		(3,894	)
Cash flows from financing activities
Changes in short-term debt		161			(155	)
Issuance of long-term debt		1,199			1,398
Retirement of long-term debt		(789	)		(828	)
Retirement of long-term debt of variable interest entity		—			(806	)
Dividends paid on common stock		(1,393	)		(1,389	)
Proceeds from employee stock plans		38			48
Other financing activities		(62	)		(16	)
Net cash flows used in financing activities		(846	)		(1,748	)
Increase (decrease) in cash and cash equivalents		(596	)		(398	)
Cash and cash equivalents at beginning of period		1,612			2,010
Cash and cash equivalents at end of period	$	1,016		$	1,612

6

EXELON CORPORATION

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

(unaudited)

(in millions, except per share data)

		$0,0			$0,0			$0,0			$0,0			$0,0			$0,0
	Three Months Ended December 31, 2011									Three Months Ended December 31, 2010
	GAAP (a)			Adjustments			Adjusted Non-GAAP			GAAP (a)			Adjustments			Adjusted Non-GAAP
Operating revenues	$	4,251		$	(24	)(c)	$	4,227		$	4,494		$	6	(h)	$	4,500
Operating expenses
Purchased power		942			46	(d)		988			1,152			(145	)(d)		1,007
Fuel		382			27	(c),(d)		409			541			(41	)(d)		500
Operating and maintenance		1,289			(43	)(c),(e)		1,246			1,160			(2	)(c),(i),(j)		1,158
Operating and maintenance for regulatory required programs (b)		45			—			45			44			—			44
Depreciation and amortization		348			(22	)(c)		326			465			(23	)(c)		442
Taxes other than income		183			—			183			193			—			193
Total operating expenses		3,189			8			3,197			3,555			(211	)		3,344
Operating income		1,062			(32	)		1,030			939			217			1,156
Other income and deductions
Interest expense		(181	)		—			(181	)		(183	)		—			(183	)
Other, net		148			(114	)(f)		34			135			(83	)(f)		52
Total other income and deductions		(33	)		(114	)		(147	)		(48	)		(83	)		(131	)
Income before income taxes		1,029			(146	)		883			891			134			1,025
Income taxes		423			(84	(c),(d),(e),  ) (f),(g)		339			367			27	(c),(d),(f),  (h),(i),(j)		394
Net income	$	606		$	(62	)	$	544		$	524		$	107		$	631
Effective tax rate		41.1	%					38.4	%		41.2	%					38.4	%
Earnings per average common share
Basic	$	0.91		$	(0.09	)	$	0.82		$	0.79		$	0.17		$	0.96
Diluted	$	0.91		$	(0.09	)	$	0.82		$	0.79		$	0.17		$	0.96
Average common shares outstanding
Basic		664						664			662						662
Diluted		666						666			663						663
Effect of adjustments on earnings per average diluted common share recorded in accordance with GAAP:
Retirement of fossil generating units (c)				$	0.01								$	0.03
Mark-to-market impact of economic hedging activities (d)					(0.07	)								0.17
Constellation acquisition costs (e)					0.03									—
Unrealized gains related to NDT fund investments (f)					(0.07	)								(0.04	)
Remeasurement of deferred income taxes (g)					0.01									—
2007 Illinois electric rate settlement (h)					—									0.01
Other acquisition costs (i)					—									0.01
Asset retirement obligation (j)					—									(0.01	)
Total adjustments				$	(0.09	)							$	0.17

(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 mark-to-market impact of Exelon’s economic hedging activities.

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

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

(g) Adjustment to exclude the non-cash impacts of the annual remeasurement of state deferred income taxes.

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

(i) Adjustment to exclude certain costs associated with Exelon’s acquisition of Exelon Wind in 2010.

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

7

EXELON CORPORATION

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

(unaudited)

(in millions, except per share data)

	Twelve Months Ended December 31, 2011									Twelve Months Ended December 31, 2010
	GAAP (a)			Adjustments			Adjusted Non-GAAP			GAAP (a)			Adjustments			Adjusted Non-GAAP
Operating revenues	$	19,184		$	(66	)(c),(d)	$	19,118		$	18,644		$	25	(m),(n)	$	18,669
Operating expenses
Purchased power		5,544			(214	)(e)		5,330			4,425			(3	)(e)		4,422
Fuel		1,844			(78	)(c),(e)		1,766			2,010			32	(e),(o)		2,042
Operating and maintenance		5,012			(124	(c),(d),(f),  )(g),(h),(i)		4,888			4,453			(4	)(c),(f),(h),(p)		4,449
Operating and maintenance for regulatory required programs (b)		184			—			184			147			—			147
Depreciation and amortization		1,335			(87	)(c)		1,248			2,075			(80	)(c)		1,995
Taxes other than income		785			(1	)(c)		784			808			—			808
Total operating expenses		14,704			(504	)		14,200			13,918			(55	)		13,863
Operating income		4,480			438			4,918			4,726			80			4,806
Other income and deductions
Interest expense		(726	)		—			(726	)		(817	)		103	(q)		(714	)
Loss in equity method investments		(1	)		—			(1	)		—			—			—
Other, net		199			(21	)(d),(j)		178			312			(153	)(j),(q)		159
Total other income and deductions		(528	)		(21	)		(549	)		(505	)		(50	)		(555	)
Income before income taxes		3,952			417			4,369			4,221			30			4,251
Income taxes		1,457			149	(c),(d),(e),  (f),(g),(h),  (i),(j),(k),(l)		1,606			1,658			(96	(c),(e),(f),(h),  (j),(m),(n),  )(o),(p),(q)		1,562
Net income	$	2,495		$	268		$	2,763		$	2,563		$	126		$	2,689
Effective tax rate		36.9	%					36.8	%		39.3	%					36.7	%
Earnings per average common share
Basic	$	3.76		$	0.41		$	4.17		$	3.88		$	0.19		$	4.07
Diluted	$	3.75		$	0.41		$	4.16		$	3.87		$	0.19		$	4.06
Average common shares outstanding
Basic		663						663			661						661
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)				$	0.05								$	0.08
Wolf Hollow acquisition (d)					(0.03	)								—
Mark-to-market impact of economic hedging activities (e)					0.27									(0.08	)
Asset retirement obligation (f)					0.02									(0.01	)
Constellation acquisition costs (g)					0.07									—
Other acquisition costs (h)					0.01									0.01
Recovery of costs pursuant to distribution rate case order (i)					(0.03	)								—
Unrealized (gains) losses related to NDT fund investments (j)					—									(0.08	)
Charge resulting from Illinois tax rate change legislation (k)					0.04									—
Remeasurement of deferred income taxes (l)					0.01									—
2007 Illinois electric rate settlement (m)					—									0.02
City of Chicago settlement (n)					—									—
Impairment of certain emission allowances (o)					—									0.05
Charge resulting from health care legislation (p)					—									0.10
Non-cash income tax matters (q)					—									0.10
Total adjustments				$	0.41								$	0.19

(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 in 2011, and a decrease in ComEd and PECO’s asset retirement obligations in 2010.

(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 non-cash charge impacts of the annual remeasurement of state deferred income taxes.

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

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

(o) 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.

(p) 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.

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

8

EXELON CORPORATION

Reconciliation of Adjusted (non-GAAP) Operating

Earnings to GAAP Earnings (in millions)

Three Months Ended December 31, 2011 and 2010

	Exelon Earnings per Diluted Share			Generation			ComEd			PECO			Other (a)			Exelon
2010 GAAP Earnings (Loss)	$	0.79		$	424		$	91		$	21		$	(12	)	$	524
2010 Adjusted (non-GAAP) Operating Earnings (Loss) Adjustments:
Mark-to-Market Impact of Economic Hedging Activities		0.17			113			—			—			—			113
Unrealized Gains Related to NDT Fund Investments (1)		(0.04	)		(26	)		—			—			—			(26	)
Asset Retirement Obligation (2)		(0.01	)		—			(6	)		(1	)		—			(7	)
Retirement of Fossil Generating Units (3)		0.03			17			—			—			—			17
2007 Illinois Electric Rate Settlement		0.01			4			—			—			—			4
Other Acquisition Costs (4)		0.01			6			—			—			—			6
2010 Adjusted (non-GAAP) Operating Earnings (Loss)		0.96			538			85			20			(12	)		631
Year Over Year Effects on Earnings:
Generation Energy Margins, Excluding Mark-to-Market:
Nuclear Volume (5)		(0.01	)		(5	)		—			—			—			(5	)
Nuclear Fuel Costs (6)		(0.02	)		(15	)		—			—			—			(15	)
Capacity Pricing		(0.13	)		(88	)		—			—			—			(88	)
Market and Portfolio Conditions (7)		0.06			38			—			—			—			38
Transmission Upgrades (8)		—			(8	)		—			—			8			—
ComEd and PECO Margins:
Weather		(0.05	)		—			(7	)		(25	)		—			(32	)
Load		—			—			1			(4	)		—			(3	)
Other Energy Delivery (9)		0.11			—			51			20			—			71
2010 Competitive Transition Charge (CTC), Net (10)		0.07			—			—			50			—			50
Operating and Maintenance Expense:
Labor, Contracting and Materials (11)		(0.07	)		(22	)		(19	)		1			—			(40	)
Planned Nuclear Refueling Outages (12)		(0.02	)		(14	)		—			—			—			(14	)
Other Operating and Maintenance (13)		(0.02	)		(28	)		18			(7	)		6			(11	)
Depreciation and Amortization Expense (14)		(0.04	)		(16	)		(4	)		(6	)		—			(26	)
Income Taxes (15)		—			2			1			7			(11	)		(1	)
Interest Expense, Net		—			1			(1	)		1			2			3
Other (16)		(0.02	)		(24	)		(4	)		18			(4	)		(14	)
2011 Adjusted (non-GAAP) Operating Earnings (Loss)		0.82			359			121			75			(11	)		544
2011 Adjusted (non-GAAP) Operating Earnings (Loss) Adjustments:
Mark-to-Market Impact of Economic Hedging Activities		0.07			45			—			—			—			45
Unrealized Gains Related to NDT Fund Investments (1)		0.07			46			—			—			—			46
Retirement of Fossil Generating Units (3)		(0.01	)		(4	)		—			—			—			(4	)
Constellation Acquisition Costs (17)		(0.03	)		(6	)		—			(1	)		(14	)		(21	)
Non-Cash Remeasurement of Deferred Income Taxes (18)		(0.01	)		6			—			—			(10	)		(4	)
2011 GAAP Earnings (Loss)	$	0.91		$	446		$	121		$	74		$	(35	)	$	606

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

9

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

(2) Reflects a decrease in 2010 of ComEd and PECO’s asset retirement obligations primarily related to transmission and distribution substation assets.

(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) Reflects certain costs incurred associated with the acquisition of Exelon Wind in 2010.

(5) Primarily reflects the impact of increased planned nuclear outage days in the Mid-Atlantic region in 2011 where energy prices are typically higher.

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

(7) Primarily reflects the impact of higher realized energy margins in the Mid-Atlantic region partially offset by the lower realized energy margins in the Midwest, energy margins at Exelon Wind, which was acquired in December 2010, and improved hydro performance.

(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, and increased distribution revenues as a result of the performance based formula rate tariff pursuant to the Energy Infrastructure Modernization Act (EIMA). 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 amortization expense, net of recoveries, associated with PECO’s transition period, which ended on December 31, 2010.

(11) Primarily reflects the impacts of inflation and 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) For Generation, primarily reflects the impact of a nuclear insurance credit recorded in 2010 at Generation and increased nuclear refueling outage costs related to Generation’s ownership interests in Salem. For ComEd, primarily reflects a credit for the allowed recovery of certain 2011 storm costs pursuant to EIMA, partially offset by a one-time contribution also pursuant to EIMA.

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

(15) Primarily reflects higher corporate tax rates pursuant to the Illinois tax rate change legislation, partially offset by the transmission and distribution property repairs deduction, production tax credits at Exelon Wind and the incremental impact on the 2010 manufacturing tax deduction associated with the pension contribution made in the first quarter of 2011.

(16) Primarily reflects realized losses associated with NDT funds at Generation as a result of unfavorable market conditions in 2011, partially offset at PECO by decreased gross receipts tax expense (completely offset by decreased PECO margins above).

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

(18) Primarily reflects the non-cash impacts of the annual remeasurement of state deferred income taxes to reflect revised estimates of state apportionments.

10

EXELON CORPORATION

Reconciliation of Adjusted (non-GAAP) Operating

Earnings to GAAP Earnings (in millions)

Twelve Months Ended December 31, 2011 and 2010

	Exelon Earnings per Diluted Share			Generation			ComEd			PECO			Other (a)			Exelon
2010 GAAP Earnings (Loss)	$	3.87		$	1,972		$	337		$	324		$	(70	)	$	2,563
2010 Adjusted (non-GAAP) Operating Earnings (Loss) Adjustments:
Mark-to-Market Impact of Economic Hedging Activities		(0.08	)		(52	)		—			—			—			(52	)
Unrealized Gains Related to NDT Fund Investments (1)		(0.08	)		(52	)		—			—			—			(52	)
Asset Retirement Obligation (2)		(0.01	)		—			(6	)		(1	)		—			(7	)
Retirement of Fossil Generating Units (3)		0.08			50			—			—			—			50
Non-Cash Charge Resulting From Health Care Legislation (4)		0.10			26			12			10			17			65
Non-Cash Remeasurement of Income Tax Uncertainties (5)		0.10			(70	)		106			22			7			65
Impairment of Certain Emission Allowances (6)		0.05			35			—			—			—			35
2007 Illinois Electric Rate Settlement		0.02			12			1			—			—			13
City of Chicago Settlement with ComEd		—			—			2			—			—			2
Acquisition Costs (7)		0.01			7			—			—			—			7
2010 Adjusted (non-GAAP) Operating Earnings (Loss)		4.06			1,928			452			355			(46	)		2,689
Year Over Year Effects on Earnings:
Generation Energy Margins, Excluding Mark-to-Market:
Nuclear Volume (8)		—			(1	)		—			—			—			(1	)
Nuclear Fuel Costs (9)		(0.08	)		(53	)		—			—			—			(53	)
Capacity Pricing		(0.23	)		(153	)		—			—			—			(153	)
Market and Portfolio Conditions (10)		0.87			577			—			—			—			577
Transmission Upgrades (11)		—			(43	)		—			—			43			—
ComEd and PECO Margins:
Weather		(0.07	)		—			(13	)		(31	)		—			(44	)
Load		(0.02	)		—			(6	)		(6	)		—			(12	)
Other Energy Delivery (12)		0.27			—			91			90			—			181
2010 CTC, Net (13)		(0.12	)		—			—			(75	)		—			(75	)
Discrete Impacts of Distribution Rate Case Order (14)		0.03			—			23			—			—			23
Operating and Maintenance Expense:
Labor, Contracting and Materials (15)		(0.21	)		(77	)		(44	)		(18	)		—			(139	)
Planned Nuclear Refueling Outages (16)		(0.05	)		(35	)		—			—			—			(35	)
Pension and Non-Pension Postretirement Benefits (17)		0.03			12			(1	)		7			3			21
2010 Recovery of Bad Debt Expense at ComEd (18)		(0.06	)		—			(36	)		—			—			(36	)
Other Operating and Maintenance (19)		(0.17	)		(65	)		(23	)		(21	)		(2	)		(111	)
Depreciation and Amortization Expense (20)		(0.13	)		(55	)		(16	)		(18	)		1			(88	)
Nuclear Decommissioning Trust Fund Special Transfer Tax Deduction (21)		0.07			46			—			—			—			46
Income Taxes (22)		(0.02	)		(17	)		9			20			(28	)		(16	)
Interest Expense, Net (23)		—			(15	)		(6	)		15			3			(3	)
Other (24)		(0.01	)		(47	)		(27	)		70			(4	)		(8	)
2011 Adjusted (non-GAAP) Operating Earnings (Loss)		4.16			2,002			403			388			(30	)		2,763
2011 Adjusted (non-GAAP) Operating Earnings (Loss) Adjustments:
Mark-to-Market Impact of Economic Hedging Activities		(0.27	)		(174	)		—			—			—			(174	)
Unrealized Losses Related to NDT Fund Investments (1)		—			(1	)		—			—			—			(1	)
Asset Retirement Obligation (2)		(0.02	)		(18	)		—			2			—			(16	)
Retirement of Fossil Generating Units (3)		(0.05	)		(33	)		—			—			—			(33	)
Constellation Acquisition Costs (25)		(0.07	)		(8	)		—			(1	)		(37	)		(46	)
Other Acquisition Costs (7)		(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
Non-Cash Remeasurement of Deferred Income Taxes (29)		(0.01	)		6			—			—			(10	)		(4	)
2011 GAAP Earnings (Loss)	$	3.75		$	1,771		$	416		$	389		$	(81	)	$	2,495

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

11

(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 decrease in 2010 of ComEd and PECO’s asset retirement obligations primarily related to transmission and distribution substation assets and an increase in 2011 in Generation’s decommissioning obligation for spent nuclear fuel at Zion.

(3) 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.

(4) Reflects a non-cash charge in 2010 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.

(5) Reflects the impact of the 2010 remeasurement of income tax uncertainties related to ComEd’s 1999 sale of fossil generating assets and CTCs received by PECO.

(6) 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.

(7) 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.

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

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

(10) 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.

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

(12) For ComEd, primarily reflects increased distribution revenue pursuant to the 2011 electric distribution rate case order, effective June 1, 2011, and increased distribution revenues as a result of the performance based formula rate tariff pursuant to EIMA. For PECO, primarily reflects increased distribution revenue pursuant to the 2010 Pennsylvania electric and natural gas distribution rate case settlements, effective January 1, 2011.

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

(14) 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.

(15) Primarily reflects the impacts of inflation, increased wages and other benefits and the impact of Exelon Wind, which was acquired in December 2010 (exclusive of planned nuclear refueling outages and incremental storm costs as disclosed in numbers 16 and 19 below).

(16) Primarily reflects the impact of increased planned nuclear refueling outages in 2011, excluding Salem.

(17) 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.

(18) 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.

(19) For Generation, primarily reflects additional environmental remediation costs, the impact of a nuclear insurance credit recorded in 2010 and increased nuclear refueling outage costs related to Generation’s ownership interest in Salem. For ComEd, primarily reflects increased storm costs in its service territory and a one-time contribution pursuant to EIMA partially offset by a credit for the allowed recovery of certain 2011 storm costs also pursuant to EIMA. For PECO, primarily reflects increased storm costs in its service territory.

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

(21) 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.

(22) 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.

(23) 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 Energy Transition Trust (PETT) transition bonds on September 1, 2010 and lower outstanding debt at Corporate.

(24) Primarily reflects increased gross receipts tax expense at Generation (completely offset by increased Generation margins above), realized losses associated with NDT funds at Generation as a result of unfavorable market conditions in 2011 and Illinois electric distribution tax refunds recorded in 2010 at ComEd, partially offset by decreased gross receipts tax expense at PECO (completely offset by decreased PECO margins above).

(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.

(29) Primarily reflects the non-cash impacts of the annual remeasurement of state deferred income taxes to reflect revised estimates of state apportionments.

12

EXELON CORPORATION

Reconciliation of Adjusted (non-GAAP) Operating Earnings to

GAAP Consolidated Statements of Operations

(unaudited)

(in millions)

		$,000,0			$,000,0			$,000,0			$,000,0			$,000,0			$,000,0
	Generation
	Three Months Ended December 31, 2011									Three Months Ended December 31, 2010
	GAAP (a)			Adjustments			Adjusted Non-GAAP			GAAP (a)			Adjustments			Adjusted Non-GAAP
Operating revenues	$	2,421		$	(24	)(b)	$	2,397		$	2,596		$	6	(g)	$	2,602
Operating expenses
Purchased power		381			46	(c)		427			602			(145	)(c)		457
Fuel		306			27	(b),(c)		333			418			(41	)(c)		377
Operating and maintenance		842			(18	)(b),(d)		824			731			(13	)(b),(h)		718
Depreciation and amortization		154			(22	)(b)		132			129			(23	)(b)		106
Taxes other than income		65			—			65			56			—			56
Total operating expenses		1,748			33			1,781			1,936			(222	)		1,714
Operating income		673			(57	)		616			660			228			888
Other income and deductions
Interest expense		(43	)		—			(43	)		(44	)		—			(44	)
Other, net		134			(114	)(e)		20			118			(83	)(e)		35
Total other income and deductions		91			(114	)		(23	)		74			(83	)		(9	)
Income before income taxes		764			(171	)		593			734			145			879
Income taxes		318			(84	(b),(c),(d),  )(e),(f)		234			310			31	(b),(c),(e),  (g),(h)		341
Net income	$	446		$	(87	)	$	359		$	424		$	114		$	538

	Twelve Months Ended December 31, 2011									Twelve Months Ended December 31, 2010
	GAAP (a)			Adjustments			Adjusted Non-GAAP			GAAP (a)			Adjustments			Adjusted Non-GAAP
Operating revenues	$	10,568		$	(66	)(b),(i)	$	10,502		$	10,025		$	21	(g)	$	10,046
Operating expenses
Purchased power		2,182			(214	)(c)		1,968			1,853			(3	)(c)		1,850
Fuel		1,528			(78	)(b),(c)		1,450			1,610			32	(c),(l)		1,642
Operating and maintenance		3,148			(77	(b),(d),(h),  )(i),(j)		3,071			2,812			(18	)(b),(h),(m)		2,794
Depreciation and amortization		570			(87	)(b)		483			474			(80	)(b)		394
Taxes other than income		264			(1	)(c)		263			230			—			230
Total operating expenses		7,692			(457	)		7,235			6,979			(69	)		6,910
Operating income		2,876			391			3,267			3,046			90			3,136
Other income and deductions
Interest expense		(170	)		—			(170	)		(153	)		—			(153	)
Loss in equity method investments		(1	)		—			(1	)		—			—			—
Other, net		122			(21	)(e),(i)		101			257			(155	)(e)		102
Total other income and deductions		(49	)		(21	)		(70	)		104			(155	)		(51	)
Income before income taxes		2,827			370			3,197			3,150			(65	)		3,085
Income taxes		1,056			139	(b),(c),(d),  (e),(f),(h),  (i),(j),(k)		1,195			1,178			(21	(b),(c),(e),(g),  )(h),(l),(m),(n)		1,157
Net income	$	1,771		$	231		$	2,002		$	1,972		$	(44	)	$	1,928

(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 mark-to-market impact of Generation’s economic hedging activities.

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

(e) Adjustment to exclude the unrealized gains in 2011 for the three months ended, unrealized losses in 2011 for the twelve months ended and unrealized gains in 2010 associated with Generation’s NDT fund investments and the associated contractual accounting relating to income taxes.

(f) Adjustment to exclude the non-cash impacts of the annual remeasurement of state deferred income taxes.

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

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

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

(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 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.

(m) 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.

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

13

EXELON CORPORATION

Reconciliation of Adjusted (non-GAAP) Operating Earnings to

GAAP Consolidated Statements of Operations

(unaudited)

(in millions)

		$0000,000			$0000,000		$0000,000			$0000,000			$0000,000			$0000,000
	ComEd
	Three Months Ended December 31, 2011								Three Months Ended December 31, 2010
	GAAP (a)			Adjustments		Adjusted Non-GAAP			GAAP (a)			Adjustments			Adjusted Non-GAAP
Operating revenues	$	1,362		$	—	$	1,362		$	1,372		$	—		$	1,372
Operating expenses
Purchased power		599			—		599			671			—			671
Operating and maintenance		239			—		239			247			10	(c)		257
Operating and maintenance for regulatory required programs (b)		31			—		31			27			—			27
Depreciation and amortization		137			—		137			130			—			130
Taxes other than income		71			—		71			68			—			68
Total operating expenses		1,077			—		1,077			1,143			10			1,153
Operating income		285			—		285			229			(10	)		219
Other income and deductions
Interest expense		(87	)		—		(87	)		(86	)		—			(86	)
Other, net		4			—		4			10			—			10
Total other income and deductions		(83	)		—		(83	)		(76	)		—			(76	)
Income before income taxes		202			—		202			153			(10	)		143
Income taxes		81			—		81			62			(4	)(c)		58
Net income	$	121		$	—	$	121		$	91		$	(6	)	$	85

		$0000,0			$0000,0			$0000,0			$0000,0			$0000,0			$0000,0
	Twelve Months Ended December 31, 2011									Twelve Months Ended December 31, 2010
	GAAP (a)			Adjustments			Adjusted Non-GAAP			GAAP (a)			Adjustments			Adjusted Non-GAAP
Operating revenues	$	6,056		$	—		$	6,056		$	6,204		$	4	(f),(g)	$	6,208
Operating expenses
Purchased power		3,035			—			3,035			3,307			—			3,307
Operating and maintenance		1,086			13	(d)		1,099			975			7	(c),(h)		982
Operating and maintenance for regulatory required programs (b)		115			—			115			94			—			94
Depreciation and amortization		542			—			542			516			—			516
Taxes other than income		296			—			296			256			—			256
Total operating expenses		5,074			13			5,087			5,148			7			5,155
Operating income		982			(13	)		969			1,056			(3	)		1,053
Other income and deductions
Interest expense		(345	)		—			(345	)		(386	)		59	(i)		(327	)
Other, net		29			—			29			24			—			24
Total other income and deductions		(316	)		—			(316	)		(362	)		59			(303	)
Income before income taxes		666			(13	)		653			694			56			750
Income taxes		250			—	(d),(e)		250			357			(59	(c),(f),(g),  )(h),(i)		298
Net income	$	416		$	(13	)	$	403		$	337		$	115		$	452

(a) Results reported in accordance with GAAP.

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

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

(d) Adjustment to exclude 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.

14

EXELON CORPORATION

Reconciliation of Adjusted (non-GAAP) Operating Earnings to

GAAP Consolidated Statements of Operations

(unaudited)

(in millions)

		$0000,000			$0000,000			$0000,000			$0000,000			$0000,000			$0000,000
	PECO
	Three Months Ended December 31, 2011									Three Months Ended December 31, 2010
	GAAP (a)			Adjustments			Adjusted Non- GAAP			GAAP (a)			Adjustments			Adjusted Non- GAAP
Operating revenues	$	778		$	—		$	778		$	1,299		$	—		$	1,299
Operating expenses
Purchased power		282			—			282			652			—			652
Fuel		76			—			76			123			—			123
Operating and maintenance		182			(1	)(c)		181			172			1	(d)		173
Operating and maintenance for regulatory required programs (b)		14			—			14			17			—			17
Depreciation and amortization		53			—			53			201			—			201
Taxes other than income		40			—			40			64			—			64
Total operating expenses		647			(1	)		646			1,229			1			1,230
Operating income		131			1			132			70			(1	)		69
Other income and deductions
Interest expense		(32	)		—			(32	)		(34	)		—			(34	)
Other, net		2			—			2			2			—			2
Total other income and deductions		(30	)		—			(30	)		(32	)		—			(32	)
Income before income taxes		101			1			102			38			(1	)		37
Income taxes		27			—	(c)		27			17			—	(d)		17
Net income	$	74		$	1		$	75		$	21		$	(1	)	$	20

	Twelve Months Ended December 31, 2011									Twelve Months Ended December 31, 2010
	GAAP (a)			Adjustments			Adjusted Non- GAAP			GAAP (a)			Adjustments			Adjusted Non- GAAP
Operating revenues	$	3,720		$	—		$	3,720		$	5,519		$	—		$	5,519
Operating expenses
Purchased power		1,547			—			1,547			2,361			—			2,361
Fuel		317			—			317			401			—			401
Operating and maintenance		725			1	(c),(d)		726			680			(1	)(d),(e)		679
Operating and maintenance for regulatory required programs (b)		69			—			69			53			—			53
Depreciation and amortization		202			—			202			1,060			—			1,060
Taxes other than income		205			—			205			303			—			303
Total operating expenses		3,065			1			3,066			4,858			(1	)		4,857
Operating income		655			(1	)		654			661			1			662
Other income and deductions
Interest expense		(134	)		—			(134	)		(193	)		36	(f)		(157	)
Other, net		14			—			14			8			2	(f)		10
Total other income and deductions		(120	)		—			(120	)		(185	)		38			(147	)
Income before income taxes		535			(1	)		534			476			39			515
Income taxes		146			—	(c),(d)		146			152			8	(d),(e),(f)		160
Net income	$	389		$	(1	)	$	388		$	324		$	31		$	355

(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 2011 and 2010 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.

15

EXELON CORPORATION

Reconciliation of Adjusted (non-GAAP) Operating Earnings to

GAAP Consolidated Statements of Operations

(unaudited)

(in millions)

		$0000,000			$0000,000			$0000,000			$0000,000			$0000,000		$0000,000
	Other (a)
	Three Months Ended December 31, 2011									Three Months Ended December 31, 2010
	GAAP (b)			Adjustments			Adjusted Non- GAAP			GAAP (b)			Adjustments		Adjusted Non- GAAP
Operating revenues	$	(310	)	$	—		$	(310	)	$	(773	)	$	—	$	(773	)
Operating expenses
Purchased power		(320	)		—			(320	)		(773	)		—		(773	)
Operating and maintenance		26			(24	)(c)		2			10			—		10
Depreciation and amortization		4			—			4			5			—		5
Taxes other than income		7			—			7			5			—		5
Total operating expenses		(283	)		(24	)		(307	)		(753	)		—		(753	)
Operating loss		(27	)		24			(3	)		(20	)		—		(20	)
Other income and deductions
Interest expense		(19	)		—			(19	)		(19	)		—		(19	)
Other, net		8			—			8			5			—		5
Total other income and deductions		(11	)		—			(11	)		(14	)		—		(14	)
Loss before income taxes		(38	)		24			(14	)		(34	)		—		(34	)
Income taxes		(3	)		—	(c),(d)		(3	)		(22	)		—		(22	)
Net loss	$	(35	)	$	24		$	(11	)	$	(12	)	$	—	$	(12	)

	Twelve Months Ended December 31, 2011									Twelve Months Ended December 31, 2010
	GAAP (b)			Adjustments			Adjusted Non- GAAP			GAAP (b)			Adjustments			Adjusted Non- GAAP
Operating revenues	$	(1,160	)	$	—		$	(1,160	)	$	(3,104	)	$	—		$	(3,104	)
Operating expenses
Purchased power		(1,220	)		—			(1,220	)		(3,096	)		—			(3,096	)
Fuel		(1	)		—			(1	)		(1	)		—			(1	)
Operating and maintenance		53			(61	)(c)		(8	)		(14	)		8	(f)		(6	)
Depreciation and amortization		21			—			21			25			—			25
Taxes other than income		20			—			20			19			—			19
Total operating expenses		(1,127	)		(61	)		(1,188	)		(3,067	)		8			(3,059	)
Operating income (loss)		(33	)		61			28			(37	)		(8	)		(45	)
Other income and deductions
Interest expense		(77	)		—			(77	)		(85	)		8	(g)		(77	)
Other, net		34			—			34			23			—			23
Total other income and deductions		(43	)		—			(43	)		(62	)		8			(54	)
Loss before income taxes		(76	)		61			(15	)		(99	)		—			(99	)
Income taxes		5			10	(c),(d),(e)		15			(29	)		(24	)(f),(g)		(53	)
Net loss	$	(81	)	$	51		$	(30	)	$	(70	)	$	24		$	(46	)

(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 the non-cash impacts of the annual remeasurement of state deferred income taxes.

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

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

16

EXELON CORPORATION

Exelon Generation Statistics

		$,0000,,000		$,0000,,000		$,0000,,000		$,0000,,000		$,0000,,000
	Three Months Ended
	Dec. 31, 2011		Sept. 30, 2011		Jun. 30, 2011		Mar. 31, 2011		Dec. 31, 2010
Supply (in GWhs)
Nuclear Generation (a)
Mid-Atlantic		11,587		12,158		11,172		12,370		11,974
Midwest		23,306		23,887		21,995		22,822		23,141
Total Nuclear Generation		34,893		36,045		33,167		35,192		35,115
Fossil and Renewables
Mid-Atlantic (a) (b)		1,637		1,724		2,054		2,166		2,115
Midwest (c)		188		88		163		157		45
South and West (c)		851		1,463		638		509		93
Total Fossil and Renewables		2,676		3,275		2,855		2,832		2,253
Purchased Power
Mid-Atlantic		739		702		707		750		442
Midwest		1,143		1,756		1,659		1,412		1,776
South and West		1,632		3,815		2,411		2,181		2,632
Total Purchased Power		3,514		6,273		4,777		4,343		4,850
Total Supply by Region
Mid-Atlantic		13,963		14,584		13,933		15,286		14,531
Midwest		24,637		25,731		23,817		24,391		24,962
South and West		2,483		5,278		3,049		2,690		2,725
		41,083		45,593		40,799		42,367		42,218

	Three Months Ended
	Dec. 31, 2011			Sept. 30, 2011		Jun. 30, 2011			Mar. 31, 2011			Dec. 31, 2010
Electric Sales (in GWhs)
PECO (d)		—			—		—			—			9,756
Market and Retail (d)		41,083			45,593		40,799			42,367			32,462
Total Electric Sales (d) (e)		41,083			45,593		40,799			42,367			42,218
Average Margin ($/MWh) (f)(g)(h)
Mid-Atlantic	$	56.29		$	57.32	$	58.92		$	59.92		$	51.75
Midwest		34.18			33.15		37.28			39.60			41.14
South and West		(5.24	)		18.57		(3.61	)		(1.49	)		(10.64	)
Average Margin—Overall Portfolio	$	39.31		$	39.19	$	41.59		$	44.30		$	41.45
Around-the-clock Market Prices ($/MWh) (i)
PJM West Hub	$	35.07		$	46.17	$	47.27		$	45.82		$	43.65
NiHub		25.97			37.30		34.94			34.10			27.26
ERCOT North Spark Spread		1.11			36.70		6.73			8.00			(0.69	)

(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 186 GWh, 76 GWh, 154 GWh, 155 GWh and 41 GWh in the Midwest and 394 GWh, 249 GWh, 431 GWh, 358 GWh and 84 GWh in the South and West for the three months ended December 31, 2011, 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 1,235 GWh, 1,679 GWh, 1,496 GWh, 1,333 GWh, and 740 GWh for the three months ended December 31, 2011, September 30, 2011, June 30, 2011, March 31, 2011 and December 31, 2010 respectively.

(f) Excludes retail gas activity, trading portfolio activity and 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.

17

EXELON CORPORATION

Exelon Generation Statistics

Twelve Months Ended December 31, 2011 and 2010

		$0000,0000		$0000,0000
	December 31, 2011		December 31, 2010
Supply (in GWhs)
Nuclear Generation (a)
Mid-Atlantic		47,287		47,517
Midwest		92,010		92,493
Total Nuclear Generation		139,297		140,010
Fossil and Renewables
Mid-Atlantic (a) (b)		7,580		9,436
Midwest (c)		596		68
South and West (c)		3,462		1,213
Total Fossil and Renewables		11,638		10,717
Purchased Power
Mid-Atlantic		2,898		1,918
Midwest		5,970		7,032
South and West		10,040		12,112
Total Purchased Power		18,908		21,062
Total Supply by Region
Mid-Atlantic		57,765		58,871
Midwest		98,576		99,593
South and West		13,502		13,325
		169,843		171,789

		$00,0000		$00,0000
	December 31, 2011		December 31, 2010
Electric Sales (in GWhs)
ComEd (d)		—		5,323
PECO (d)		—		42,003
Market and Retail (d)		169,843		124,463
Total Electric Sales (e)		169,843		171,789
Average Margin ($/MWh) (f)(g)(h)
Mid-Atlantic	$	58.15	$	42.67
Midwest		35.98		40.98
South and West		5.18		(9.83	)
Average Margin—Overall Portfolio	$	41.07	$	37.62
Around-the-clock Market Prices ($/MWh) (i)
PJM West Hub	$	43.56	$	45.93
NiHub		33.07		33.09
ERCOT North Spark Spread		11.88		2.31

(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 570 GWhs and 41 GWhs in the Midwest and 1,432 GWhs and 84 GWhs in the South for the years ended December 31, 2011 and 2010, 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 5,742 GWhs and 3,625 GWhs for the years ended December 31, 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 years ended December 31, 2011 and 2010, respectively.

18

EXELON CORPORATION

ComEd Statistics

Three Months Ended December 31, 2011 and 2010

	Electric Deliveries (in GWhs)										Revenue (in millions)
	2011		2010		% Change			Weather- Normal %  Change			2011		2010		% Change
Retail Deliveries and Sales (a)
Residential		6,166		6,393		(3.6	)%		1.2	%	$	764	$	761		0.4	%
Small Commercial & Industrial		7,632		7,929		(3.7	)%		(1.2	)%		340		366		(7.1	)%
Large Commercial & Industrial		6,721		6,725		(0.1	)%		1.8	%		95		91		4.4	%
Public Authorities & Electric Railroads		316		346		(8.7	)%		(3.1	)%		12		14		(14.3	)%
Total Retail		20,835		21,393		(2.6	)%		0.4	%		1,211		1,232		(1.7	)%
Other Revenue (b)												151		140		7.9	%
Total Electric Revenue											$	1,362	$	1,372		(0.7	)%
Purchased Power											$	599	$	671		(10.7	)%

							% Change
Heating and Cooling Degree-Days	2011		2010		Normal		From 2010			From Normal
Heating Degree-Days		1,832		2,292		2,278		(20.1	)%		(19.6	)%
Cooling Degree-Days		14		15		7		(6.7	)%		100.0	%

Twelve Months Ended December 31, 2011 and 2010

	Electric Deliveries (in GWhs)										Revenue (in millions)
	2011		2010		% Change			Weather- Normal Change			2011		2010		% Change
Retail Deliveries and Sales (a)
Residential		28,273		29,171		(3.1	)%		(1.3	)%	$	3,510	$	3,549		(1.1	)%
Small Commercial & Industrial		32,281		32,904		(1.9	)%		(0.8	)%		1,517		1,639		(7.4	)%
Large Commercial & Industrial		27,732		27,717		0.1	%		0.6	%		383		397		(3.5	)%
Public Authorities & Electric Railroads		1,235		1,273		(3.0	)%		(1.2	)%		50		62		(19.4	)%
Total Retail		89,521		91,065		(1.7	)%		(0.5	)%		5,460		5,647		(3.3	)%
Other Revenue (b)												596		557		7.0	%
Total Electric Revenue											$	6,056	$	6,204		(2.4	)%
Purchased Power											$	3,035	$	3,307		(8.2	)%

							% Change
Heating and Cooling Degree-Days	2011		2010		Normal		From 2010			From Normal
Heating Degree-Days		6,134		5,991		6,362		2.4	%		(3.6	)%
Cooling Degree-Days		1,036		1,181		855		(12.3	)%		21.2	%

Number of Electric Customers	2011		2010
Residential		3,448,481		3,438,677
Small Commercial & Industrial		365,824		363,393
Large Commercial & Industrial		2,032		2,005
Public Authorities & Electric Railroads		4,797		5,078
Total		3,821,134		3,809,153

(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.

19

EXELON CORPORATION

PECO Statistics

Three Months Ended December 31, 2011 and 2010

	Electric and Gas Deliveries										Revenue (in millions)
	2011		2010		% Change			Weather- Normal %  Change			2011		2010		% Change
Electric (in GWhs)
Retail Deliveries and Sales (a)
Residential		2,937		3,124		(6.0	)%		1.1	%	$	392	$	444		(11.7	)%
Small Commercial & Industrial		1,884		1,958		(3.8	)%		0.3	%		114		233		(51.1	)%
Large Commercial & Industrial		3,665		3,975		(7.8	)%		(6.8	)%		45		327		(86.2	)%
Public Authorities & Electric Railroads		235		226		4.0	%		8.8	%		9		22		(59.1	)%
Total Retail		8,721		9,283		(6.1	)%		(2.2	)%		560		1,026		(45.4	)%
Other Revenue (b)												63		61		3.3	%
Total Electric Revenue												623		1,087		(42.7	)%
Gas (in mmcfs)
Retail Deliveries and Sales (c)
Retail Sales		15,257		19,730		(22.7	)%		1.9	%		147		205		(28.3	)%
Transportation and Other		6,776		7,253		(6.6	)%		(4.5	)%		8		7		14.3	%
Total Gas		22,033		26,983		(18.3	)%		0.1	%		155		212		(26.9	)%
Total Electric and Gas Revenues											$	778	$	1,299		(40.1	)%
Purchased Power											$	282	$	652		(56.7	)%
Fuel												76		123		(38.2	)%
Total Purchased Power and Fuel											$	358	$	775		(53.8	)%

							% Change
Heating and Cooling Degree-Days	2011		2010		Normal		From 2010			From Normal
Heating Degree-Days		1,302		1,686		1,634		(22.8	)%		(20.3	)%
Cooling Degree-Days		14		19		21		(26.3	)%		(33.3	)%

Twelve Months Ended December 31, 2011 and 2010

	Electric and Gas Deliveries										Revenue (in millions)
	2011		2010		% Change			Weather- Normal % Change			2011		2010		% Change
Electric (in GWhs)
Retail Deliveries and Sales (a)
Residential		13,687		13,913		(1.6	)%		1.7	%	$	1,934	$	2,069		(6.5	)%
Small Commercial & Industrial		8,321		8,503		(2.1	)%		(0.7	)%		584		1,060		(44.9	)%
Large Commercial & Industrial		15,677		16,372		(4.2	)%		(3.3	)%		304		1,362		(77.7	)%
Public Authorities & Electric Railroads		945		925		2.2	%		4.6	%		38		89		(57.3	)%
Total Retail		38,630		39,713		(2.7	)%		(0.9	)%		2,860		4,580		(37.6	)%
Other Revenue (b)												249		255		(2.4	)%
Total Electric Revenue												3,109		4,835		(35.7	)%
Gas (in mmcfs)
Retail Deliveries and Sales (c)
Retail Sales		54,239		56,833		(4.6	)%		1.2	%		575		656		(12.3	)%
Transportation and Other		28,204		30,911		(8.8	)%		(7.5	)%		36		28		28.6	%
Total Gas		82,443		87,744		(6.0	)%		(1.8	)%		611		684		(10.7	)%
Total Electric and Gas Revenues											$	3,720	$	5,519		(32.6	)%
Purchased Power											$	1,547	$	2,361		(34.5	)%
Fuel												317		401		(20.9	)%
Total Purchased Power and Fuel											$	1,864	$	2,762		(32.5	)%

							% Change
Heating and Cooling Degree-Days	2011		2010		Normal		From 2010			From Normal
Heating Degree-Days		4,157		4,396		4,638		(5.4	)%		(10.4	)%
Cooling Degree-Days		1,617		1,817		1,292		(11.0	)%		25.2	%

Number of Electric Customers	2011		2010		Number of Gas Customers	2011		2010
Residential		1,415,681		1,411,643	Residential		451,382		448,391
Small Commercial & Industrial		157,137		156,865	Commercial & Industrial		41,373		41,303
Large Commercial & Industrial		3,110		3,071	Total Retail		492,755		489,694
Public Authorities & Electric Railroads		1,122		1,102	Transportation		879		838
Total		1,577,050		1,572,681	Total		493,634		490,532

(a) Reflects delivery volumes and revenues from customers purchasing electricity directly from PECO and customers purchasing electricity directly 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.

20

EX-99.2

Earnings Conference Call

4

th

Quarter 2011

January 25, 2012

Exhibit 99.2

Cautionary Statements Regarding

Forward-Looking Information

2

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 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; (2) conditions to the closing of the merger may not be satisfied; (3) an unsolicited offer of another

company to acquire assets or capital stock of Exelon or Constellation could interfere with the merger; (4) 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; (5) the combined company may be unable to achieve cost-cutting synergies or it may take longer than

expected to achieve those synergies; (6) the merger may involve unexpected costs, unexpected liabilities or unexpected delays, or the

effects of purchase accounting may be different from the companies’ expectations; (7) the credit ratings of the combined company or

its subsidiaries may be different from what the companies expect; (8) the businesses of the companies may suffer as a result of

uncertainty surrounding the merger; (9) the companies may not realize the values expected to be obtained for properties expected or

required to be divested; (10) the industry may be subject to future regulatory or legislative actions that could adversely affect the

companies; and (11) 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)

3

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 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 September 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: Year In Review

4

Financial Success

Q4 operating EPS of

$0.82 per share

2011 operating EPS of

$4.16 per share and

above original

expectations

Strategic

Execution

Acquired Wolf Hollow CCGT

in Texas and AVSR 1 Solar

PV facility in California

Nuclear uprate program

added 138.6 MW in 2011

Exelon Wind added 90 MW

in 2011

2011 was a year of exemplary financial and operating performance, constructive 

regulatory environment and solid execution on strategic initiatives

EPA: Clean Air Standards

5

Final rules substantially similar to proposed

rules; no significant changes to standards for

existing units

Rule provides sufficient flexibility for

compliance

•

Compliance timeline is three years

•

Some units will be granted a 1 year

extension on a case by case basis  

PJM coal plant retirement estimate

unchanged by final rule

•

Expect rule to lead to the retirement of         

15 GW of coal capacity

Rule to be implemented in early 2015

D.C. Court of Appeals granted a stay on the

Cross State Air Pollution Rule (CSAPR)

Court’s recent order demonstrates

commitment to resolve this case on an

expedited basis

CSAPR is not a major driver of coal plant

retirements, as demonstrated by EPA

modeling

Minimal impact to Exelon’s 2012 gross

margin as generation position in PJM is well

hedged

Air Toxics Rule

Cross State Air Pollution Rule

•

Final

briefs

due

by

March

16

th

2012

•

Oral

arguments

on

April

13

th

2012

Air Toxics Rule is still expected to be the more impactful rule to drive coal plant 

retirements, and we continue to believe the CSAPR is valid   

Merger Approvals Process on Schedule    

(as of 1/20/2012)

6

Note: The Department of Public Utilities in Massachusetts concluded on September 26, 2011 that it does not have jurisdiction over the merger.

Stakeholder

Status of Key Milestones

Approved

Texas PUC

(Case No. 39413)

Approval received on August 3, 2011

Securities and Exchange Commission

(SEC)

(File No. 333-175162)

Joint proxy statement declared effective on October 11, 2011

Shareholder Approval

Shareholders overwhelmingly approved the merger on November 17, 2011

New York PSC

(Case No. 11–E–0245)

Declaratory ruling on December 15, 2011 confirming that Commission review is

not required

Department of Justice (DOJ)

U.S. DOJ clearance received on December 21, 2011

Nuclear Regulatory Commission

(Docket Nos. 50-317, 50-318, 50-220,

50-410, 50-244, 72-8, 72-67)

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

Federal Energy Regulatory Commission

(FERC)

(Docket No. EC 11-83)

Settlement agreement filed with PJM Market Monitor on October 11, 2011

Maryland PSC

(Case No. 9271)

Settlement agreement reached with key stakeholders in Maryland on

December 15, 2011

Hearings scheduled for January 25 –

27, 2012

Briefs due February 6, 2012

Order expected on February 17, 2012

7

Key Financial Messages

Q4 2011 operating earnings of $0.82 per share

Full year 2011 operating earnings of $4.16 per share

Strong cash flow from operations

Credit metrics above target range across all operating

companies

Disciplined execution of ratable hedge program continues to

create value

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

8

Exelon Generation

Operating EPS Contribution

$2.91

$0.81

$3.01

$0.54

Full Year

4Q

2011

2010

Outage Days

(3)

4Q10

4Q11

Refueling

97

103

Non-refueling

18

11

Favorable market/portfolio conditions:

$0.06

(2)

Unfavorable capacity pricing: $(0.13)

Higher O&M costs, including refueling costs

at Salem: $(0.08)

Increased planned nuclear refueling costs:

$(0.02)

Higher nuclear fuel costs: $(0.02)

Higher depreciation expense: $(0.02)

Nuclear volume: $(0.01)

Key Drivers –

4Q11 vs. 4Q10

(1)

(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) Favorable market/portfolio conditions includes: $0.03 higher realized prices in the Mid-Atlantic net of lower realized prices in the Midwest, $0.02 Wind and $0.01 

Hydro volume.

(3) Outage days exclude Salem. 

9

ComEd Operating EPS Contribution

$0.68

$0.13

$0.61

$0.18

Full Year

4Q

2011

2010

4Q10

Actual

4Q11

Actual

Normal

Heating Degree-Days

2,292

1,832

2,278

Cooling Degree-Days

15

14

7

Energy Infrastructure Modernization Act, 

net

(2)

: $0.06

Electric distribution rates: $0.03

Higher O&M costs: $(0.04)

Weather: $(0.01)

Key Drivers –

4Q11 vs. 4Q10

(1)

(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)

O&M impacts include credit for the allowed recovery of certain 2011 storm costs, partially offset by a one-time contribution.

10

PECO 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.

Note: CTC = Competitive Transition Charge

$0.54

$0.03

$0.58

$0.11

Full Year

4Q

2010

2011

4Q10

Actual

4Q11

Actual

Normal

Heating Degree-Days

1,686

1,302

1,634

Cooling Degree-Days

19

14

21

2010 CTC amortization expense, net of

collections: $0.07

Electric and gas distribution rates: $0.04

Weather: $(0.04)

Key Drivers –

4Q11 vs. 4Q10

(1)

11

2011 Actual Sources and Uses of Cash

(1)

Excludes counterparty collateral activity.

(2)

Cash Flow from Operations primarily includes net cash flows provided by operating activities, replacement of credit facilities and net cash flows used in investing activities other than capital

expenditures. 

(3)

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

(4)

Includes $350 million in Nuclear Uprates and $250 million for Exelon Wind spend.

(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

800

3,475

4,975

CapEx (excluding Nuclear Fuel, Nuclear Uprates, Exelon

Wind and Utility Growth CapEx)

(750)

(350)

(825)

(1,975)

Nuclear Fuel

n/a

n/a

(1,075)

(1,075)

Dividend

(3)

(1,400)

Nuclear Uprates and Exelon Wind

(4)

n/a

n/a

(600)

(600)

Wolf Hollow Acquisition

n/a

n/a

(300)

(300)

Antelope Valley Solar Ranch One Acquisition

n/a

n/a

(75)

(75)

Utility Growth CapEx

(5)

(275)

(125)

n/a

(400)

Net Financing (excluding Dividend):

Debt Issuances

(6)

1,200

--

--

1,200

Debt Retirements

(550)

(250)

--

(800)

Other

(7)

--

(50)

25

200

Ending Cash Balance

(1)

$550

Post-Merger Legal Entity Structure

BGE

•

BGE will exist as a separate subsidiary under Exelon with its current ring-fenced

structure

•

BGE

will

continue

as

a

separate

SEC

registrant

and

will

continue

to

issue

debt

Constellation Energy Group, Inc. (CEG) will be merged into Exelon Corporation

•

CEG subsidiaries, excluding BGE, will then be transferred to Exelon Generation and

become direct wholly-owned subsidiaries of Exelon Generation

•

Exelon Corporation will assume the obligations of CEG’s publicly-held debt, guarantees

and other contracts

Benefits of merging CEG into Exelon

•

Placement at HoldCo provides bondholders with diversity of cash flows from regulated

and unregulated businesses

•

Optimizes funding costs by utilizing the Exelon Generation credit as the primary

financing vehicle for the unregulated business post-merger

•

Simplifies accounting and reporting through elimination of separate CEG SEC registrant

•

No impacts on BGE ring-fencing commitments to Maryland PSC

12

Exelon Generation Hedging Program

Percentage of Expected Generation Hedged

Being close to fully hedged in 2012 has protected us from the recent decline in power prices

0%

20%

40%

60%

80%

100%

2014

2013

2012

Ratable

% Hedged without Options

Option %

2012 Gross Margin Comparison

(1)

4,450

5,150

3,500

4,000

4,500

5,000

5,500

6,000

6,500

5,965

09/30/2011

5,975

12/31/2011

2012 Hedged Gross Margin ($ millions)

2012 Open Gross Margin

13

(1) Gross Margin estimates are rounded. Open Gross Margin assumes no hedges.

Exelon Generation Hedging Program

As a consequence of being ahead of a ratable pace in

2009 and 2010 in the PJM portfolio we were able to

capture higher market prices and be selective in 2011 by

holding off on sales when prices were low.

2012 Midwest & Mid-Atlantic Hedging

Over the Past Three Years

2012 South & West Hedging

Over the Past Three Years

We have consciously kept more open length in the

South and West region to benefit from increased heat

rates and volatility in the ERCOT market and are well

positioned to capture upside in the spot market.

$54.73

0%

20%

40%

60%

80%

100%

$40.00

$45.00

$50.00

$55.00

$60.00

$65.00

2011

2010

2009

West Hub 2012 ATC Avg Yearly Price

Ratable

2012 Year End Hedge %

9.98

0%

20%

40%

60%

80%

100%

8.40

8.60

8.80

9.00

9.20

9.40

9.60

9.80

10.00

10.20

2011

2010

2009

ERCOT North 2012 On Peak Yearly Avg Heat Rate

Ratable

2012 Year End Hedge %

14

$45.68

$44.91

8.75

8.91

While our three-year ratable hedging program ensures stable cash flows, we continue to use our

market views to create incremental value via timing, product and regional allocations of sales

15

John Rowe’s Key Accomplishments

•

Unicom/PECO merger

Creating Exelon

•

Running nuclear plants at world-class levels

Turning Around Nuclear

•

Vision for a cleaner, more competitive future

Selling ComEd’s

Fossil Fleet

•

Letting competitive markets work

Separating Generation

•

Keeping the lights on

Improving ComEd’s

Service

•

Smooth transition to competitive market, starting with the 

2007 settlement

Promoting Competition in Illinois

•

Environmental strategy committed to clean generation

Launching Exelon 2020

•

Maintaining a solid regulatory relationship

Making Pennsylvania Proud

•

PECO’s rate settlement and ComEd’s

infrastructure

legislation

Regulatory Outcomes

•

Cost management, risk management

Maintaining Financial Discipline

Exelon Generation Hedging Disclosures

(as of December 31, 2011)

16

17

Important Information

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

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

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

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

future events.  In fact, many of the factors that ultimately will determine Exelon Generation’s

actual gross margin are based upon highly variable market factors outside of our control.  The

information on the following slides is as of December 31, 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.

18

Portfolio Management Objective

Align Hedging Activities with Financial Commitments

Power Team utilizes several product types

and channels to market

•

Wholesale and retail sales

•

Block products

•

Load-following products

and load auctions

•

Put/call options

Exelon’s hedging program is designed to

protect the long-term value of our

generating fleet and maintain an

investment-grade balance sheet

•

Hedge enough commodity risk to meet future cash

requirements if prices drop

•

Consider:  financing policy (credit rating objectives,

capital structure, liquidity); spending (capital and

O&M); shareholder value return policy

Consider market, credit, operating risk

Approach to managing volatility

•

Increase hedging as delivery approaches

•

Have enough supply to meet peak load

•

Purchase fossil fuels as power is sold

•

Choose hedging products based on generation

portfolio

–

sell what we own

•

Heat rate options

•

Fuel products

•

Capacity

•

Renewable credits

% Hedged

High End of Profit

Low End of Profit

Open Generation

with LT Contracts

Portfolio

Optimization

Portfolio

Management

Portfolio Management Over Time

19

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

risks

•

By

using

the

appropriate

product

mix,

expected

generation

hedged

approaches

the

mid-90s percentile as the delivery period approaches

•

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

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

quarter to quarter

Exelon Generation Hedging Program

20

2012

2013

2014

Estimated Open Gross Margin ($ millions)

(1)(2)

$4,450

$4,950

$5,400

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)

$3.24

$29.77

$38.86

$7.29

$3.94

$31.44

$41.26

$6.37

$4.34

$33.15

$43.97

$5.22

Exelon Generation Open Gross Margin and

Reference Prices

(1)

Based on December 31, 2011 market conditions. 

(2)

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

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

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

nuclear power plants. Open gross margin contains assumptions for other gross margin line items such as various ISO bill and ancillary revenues and costs and PPA

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

(3)

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

21

2012

2013

2014

Expected Generation

(GWh)

(1)

173,100

167,600

166,100

Midwest

99,200

95,800

95,400

Mid-Atlantic

56,800

56,100

55,700

South & West

17,100

15,700

15,000

Percentage

of

Expected

Generation

Hedged

(2)

88-91%

61-64%

32-35%

Midwest

89-92

62-65

30-33

Mid-Atlantic

94-97

66-69

33-36

South & West

65-68

43-46

34-37

Effective Realized Energy Price

($/MWh)

(3)

Midwest

$40.50

$40.00

$37.50

Mid-Atlantic

$50.50

$50.50

$51.00

South & West

$2.00

$3.00

$2.00

Generation Profile

(1)

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

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

Expected generation assumes 10 refueling outages in 2012 and 2013 and 11 refueling outages in 2014 at Exelon-operated nuclear plants and Salem.  Expected generation assumes

capacity factors of 93.5%, 93.3% and 93.4% in 2012, 2013 and 2014 at Exelon-operated nuclear plants. These estimates of expected generation in 2012, 2013 and 2014 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.

22

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%

2012

$20

$(5)

$40

$(30)

$15

$(15)

+/-

$35

2013

$260

$(230)

$185

$(180)

$115

$(110)

+/-

$40

2014

$600

$(560)

$335

$(330)

$205

$(205)

+/-

$40

Exelon Generation Gross Margin Sensitivities

(with Existing Hedges)

(1)

Based on December 31, 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.

23

95% case

5% case

$5,300

$6,100

$5,800

$6,400

Exelon Generation Gross Margin Upside / Risk

(with Existing Hedges)

$3,000

$4,000

$5,000

$6,000

$7,000

$8,000

$9,000

2012

2013

2014

$7,000

$4,600

(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 , 2013 and 2014 do not represent earnings guidance or a

forecast of future results as Exelon has not completed its planning or optimization processes for those years. The price distributions that generate this range are calibrated to

market quotes for power, fuel, load following products, and options as of December 31, 2011.

24

Midwest

Mid-Atlantic

South & West

Step 1

Start

with

fleetwide

open

gross

margin

$4.45 billion

Step 2

Determine the mark-to-market value

of energy

hedges

99,200GWh * 90% *

($40.50/MWh-$29.77MWh)

= $0.96 billion

56,800GWh * 94% *

($50.50/MWh-$38.86MWh)

= $0.62 billion

17,100GWh * 66% *

($2.00/MWh-$7.29MWh)

= $(0.06) billion

Step 3

Estimate

hedged

gross

margin

by

adding open gross margin to mark-to-

market value of energy hedges

Open gross margin:                              $4.45 billion

MTM

value

of

energy

hedges:

$0.96billion

+

$0.62billion

+

$(0.06)

billion

Estimated hedged gross margin:          $5.97 billion

Illustrative Example

of Modeling Exelon Generation 2012 Gross Margin

(with Existing Hedges)

20

25

30

35

40

45

50

55

1/11

2/11

3/11

4/11

5/11

6/11

7/11

8/11

9/11

10/11

11/11

12/11

1/12

30

35

40

45

50

55

60

65

70

1/11

2/11

3/11

4/11

5/11

6/11

7/11

8/11

9/11

10/11

11/11

12/11

1/12

3.0

3.5

4.0

4.5

5.0

5.5

6.0

1/11

2/11

3/11

4/11

5/11

6/11

7/11

8/11

9/11

10/11

11/11

12/11

1/12

65

70

75

80

85

90

95

100

1/11

2/11

3/11

4/11

5/11

6/11

7/11

8/11

9/11

10/11

11/11

12/11

1/12

Market Price Snapshot

Forward NYMEX Natural Gas

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

PJM-West and Ni-Hub Wrap Forward Prices

2014

$4.01

2013  $3.53

Forward NYMEX Coal

2014

$72.69

2013

$68.44

2013 Ni-Hub  $33.58

2014 Ni-Hub

$35.73

2014 PJM-West  $44.85

2013 PJM-West

$42.15

2013 Ni-Hub

$23.04

2014 Ni-Hub

$24.05

2014 PJM-West

$33.28

2013 PJM-West

$31.07

25

Rolling

12

months,

as

of

January

18

th

2012.

Source:

OTC

quotes

and

electronic

trading

system.

Quotes

are

daily.

6

7

8

9

10

11

12

13

14

15

16

17

1/11

2/11

3/11

4/11

5/11

6/11

7/11

8/11

9/11

10/11

11/11

12/11

1/12

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

11.2

11.4

11.6

11.8

12.0

12.2

1/11

2/11

3/11

4/11

5/11

6/11

7/11

8/11

9/11

10/11

11/11

12/11

1/12

35

40

45

50

55

60

65

1/11

2/11

3/11

4/11

5/11

6/11

7/11

8/11

9/11

10/11

11/11

12/11

1/12

3.0

3.5

4.0

4.5

5.0

5.5

6.0

6.5

1/11

2/11

3/11

4/11

5/11

6/11

7/11

8/11

9/11

10/11

11/11

12/11

1/12

Market Price Snapshot

2014

10.88

2013

11.52

2013

$40.11

2014

$43.10

2013

$3.48

2014

$3.96

Houston Ship Channel Natural Gas

Forward Prices

ERCOT North On-Peak Forward Prices

ERCOT North On-Peak v. Houston Ship Channel

Implied Heat Rate

2013

$12.47

2014

$12.00

ERCOT North On Peak Spark Spread

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

26

Rolling

12

months,

as

of

January

18

th

2012.

Source:

OTC

quotes

and

electronic

trading

system.

Quotes

are

daily.

27

Appendix

2011 results were achieved in a very

challenging market environment due to

effectiveness of asset allocations and

hedging strategy

•

Decreased equity investments and

increased investment in fixed income

securities and alternative investments

•

The liability hedge has offset more than 

50% of the pension liability increase

caused by lower interest rates

Pension plans are 83% funded as of

December 31, 2011

Pension Funds Performance

Exelon’s pension investment strategy has effectively dampened the volatility

of plan assets and plan funded status

28

S&P 500

Exelon Pension Assets

2.1%

9.8%

2011 Actual Returns

29

Exelon Generation 2011 EPS Contribution

$ / Share

$ 3.01

$ (0.03)

$ (0.01)

$ (0.08)

$ (0.26)

$ 0.49

$ 2.91

Other

RNF

2010A

O&M

2011A

Key Items:

Expiration of PECO PPA

$0.62

Market/portfolio conditions

(1)

$0.25

Unfavorable capacity pricing

($0.23)

Nuclear Fuel

($0.08)

Transmission

Upgrades

(2)

($0.06)

Key Items:

Inflation

($0.08)

Nuclear Outages

($0.05)

Exelon Wind

($0.04)

Higher refueling costs at Salem

($0.02)

Depreciation &

Amortization

Interest

Expense

(1)

Includes $0.15 of favorable market and portfolio conditions in the South and $0.07 related to Exelon Wind.

(2)

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

30

ComEd 2011 EPS Contribution

$ / Share

30

$ 0.61

$ (0.02)

$ (0.02)

$ (0.02)

$ (0.14)

$ 0.13

$ 0.68

2011A

Other

O&M

RNF

2010A

Key Items:

Distribution Revenue

(1)

$0.08

Formula Rate Legislation

(2)

$0.03

Transmission Revenue

$0.02

Weather

($0.02)

Key Items:

2010 Bad Debt Recovery

(3)

($0.06)

Inflation

($0.03)

One-time contribution

(4)

($0.01)

Storm costs

(5)

($0.01)

2010 Distribution Rate Case Order

$0.02

(1)

Increased distribution revenue pursuant to the 2011 electric distribution rate case order, effective June 1, 2011.

(2)

Increased distribution revenues as a result of the annual true-up in the performance based formula rate tariff pursuant to the Energy Infrastructure  

Modernization Act (EIMA).

(3)

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.

(4)

Represents a one-time contribution to a new Science and Technology Innovation Trust accrued pursuant to EIMA.

(5)

Includes a $0.04 credit for the allowed recovery of certain 2011

storm costs, net of amortization expense.

Depreciation &

Amortization

Interest

Expense

31

PECO 2011 EPS Contribution

$ / Share

$ 0.58

$ 0.04

$ 0.03

$ (0.04)

$ (0.03)

$ (0.05)

$ 0.08

$ 0.54

2011A

Other

Taxes

CTC, net

O&M

RNF

2010A

Key Items:

Electric & Gas Distribution Rate

(1)

$0.15

Weather

($0.05)

Key Items:

Storm costs

($0.01)

Inflation

($0.02)

(1)

Reflects increased distribution revenue pursuant to the 2010 Pennsylvania electric and natural gas distribution rate case settlements effective January 1,

2011.

(2)

Includes associated gross receipts taxes.

Key Items:

Revenue net of amortization

(2)

($0.06)

Interest on PECO transition

$0.02

bonds

Key Items:

T&D

tax repairs deductions    $0.05

Depreciation &

Amortization

ComEd Load Trends

-3%

-2%

-1%

0%

1%

2%

3%

3Q11

2Q11

1Q11

4Q12

3Q12

2Q12

1Q12

4Q11

Residential

Gross Metro Product

All Customer Classes

Large C&I

Note: C&I = Commercial & Industrial

Chicago

U.S.

Unemployment rate

(1)

10.5%

8.5%

2011 annualized growth in

gross

domestic/metro

product

(2)

1.7%

1.8%

(1)

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

Department of Security (November 2011)

(2)

Source: Global Insight (November 2011)

(3)

Not adjusted for leap year

4Q11 

2011        2012E

(3)

Average Customer Growth

0.3%  

0.4%    

0.4%

Average Use-Per-Customer

0.9%

(1.7)%

(1.0)%

Total Residential

1.2%   

(1.3)%      (0.6)%

Small C&I

(1.2)%

(0.8)%    

0.0%

Large C&I

1.8%  

0.6%     

(0.2)%

All Customer Classes

0.4%   

(0.5)%     

(0.2)%

32

Weather-Normalized Load Year-over-Year 

Key Economic Indicators

Weather-Normalized Load

PECO Load Trends

Note: C&I = Commercial & Industrial

-12.5%

-10.0%

-7.5%

-5.0%

-2.5%

0.0%

2.5%

5.0%

4Q12

3Q12

2Q12

1Q12

4Q11

3Q11

2Q11

1Q11

Gross Metro Product

Residential

Large C&I

All Customer Classes

Philadelphia

U.S.

Unemployment rate

(1)

7.9%

8.5%

2011 annualized growth in

gross domestic/metro product

(2)

0.9%             1.8%

(1)

Source:

U.S.

Dept.

of

Labor

data

(December

2011)

–

US

U.S.

Dept.

of

Labor

prelim.

data

(November

2011)

–

Philadelphia

(2)

Source: Global Insight (November 2011)

(3)

Not adjusted for leap year

4Q11

2011        2012E

(3)

Average Customer Growth

0.3%  

0.3%    

0.4%

Average Use-Per-Customer

0.9%

1.3%

(2.5)%

Total Residential

1.1%   

1.7%        (2.2)%

Small C&I

0.3%

(0.7)%   

(1.7)%

Large C&I

(6.8)%  

(3.3)%     (10.5)%

All Customer Classes

(2.2)%   

(0.9)%   

(5.4)%

Large C&I (excluding refinery impact)

Oil refinery closing estimated impact to reduce Large C&I and total load in 2012

by 9.1% and 3.7%, respectively

33

Weather-Normalized Load Year-over-Year 

Key Economic Indicators

Weather-Normalized Load

Maryland Settlement Summary

34

Settlement agreement with State of Maryland, City of Baltimore and other

key parties increases value of merger package to more than $1 billion

Package

includes

285

–

300

MW

of

new

generation

in

Maryland

•

120 MW of natural gas generation

•

125

MW

of

Tier

1

renewable

generation,

of

which

at

least

62.5

MW

will

be

wind

generation

•

30 MW of solar energy

•

10 -

25 MW of generation capacity from poultry litter

Significant benefits to the state and customers

•

$100 credit to each residential customer

•

Construction of LEED office building in Baltimore

•

$50M funding for low income weatherization measures

•

$32M funding for offshore wind research and development in Maryland

Commitments to preserve BGE as a leading Maryland company

•

Maintain capital and O&M spend and no dividend contributions to parent through 2014

•

Maintain investment in smart meters, reliability and other key initiatives

35

Exelon Dividend

Exelon’s Board of Directors approved a contingent stub dividend for Exelon shareholders of

$0.00583/share

per

day

for

Q2

2012

in

anticipation

of

the

merger

close

($0.525/share

for

the

quarter)

Stub dividend declaration ensures that Exelon shareholders continue to receive all dividends at the

current $2.10 per share annualized rate

Pre-

and post-close stub dividends must be declared separately to account for Constellation

shareholders becoming Exelon shareholders at merger close

Assuming

a

February

29,

2012

close

for

illustrative

purposes

only:

(1)

Assuming a 2/29/2012 merger close; for Exelon shareholders, Q2 2012 dividend will be based on a per diem rate of $0.00583 ($0.525 divided by 90 days).

(2)

Future dividend, following the stub dividend, is subject to approval by the Board of Directors.

$0.525

Record Date

Payment Date

Dividend Type

Per Share Amount

2/15/2011

3/9/2011

Regular Dividend

$0.525

2/28/2012

3/28/2012

Pre-

close

Stub

Dividend

(1)

$0.076

5/15/2012

6/8/2012

Post-

close

Stub

Dividend

(1)

$0.449

8/15/2012

9/10/2012

Regular

Dividend

(2)

$0.525

11/15/2012

12/10/2012

Regular

Dividend

(2)

$0.525

Current Exelon shareholders will continue to receive a total dividend of 

$0.525 per quarter

36

Constellation Energy’s Board of Directors approved a contingent stub dividend for Constellation

shareholders of $0.00264/share per day for Q1 2012 in anticipation of merger close

Stub dividend declaration ensures that Constellation shareholders continue to receive their existing

quarterly dividend rate prior to the merger, and benefit from the Exelon annualized dividend rate

($2.10 per share) beginning on the day the merger closes

Pre-

and post-close stub dividends must be declared separately to account for Constellation

shareholders becoming Exelon shareholders at merger close

Assuming

a

February

29,

2012

close

for

illustrative

purposes

only

:

(1)

Assuming a 2/29/2012 merger close, Q1 2012 dividend will be based on a per diem rate of $0.00264 ($0.24 divided by 91 days).

Post-close

Exelon

Q2

2012

stub

dividend

will

be

based

on

a

per

diem

rate

of

$0.00583.

(2)

Assuming a 2/29/2012 merger close, Constellation shareholders will start receiving the full quarterly Exelon dividend of

$0.525

per

share

in

Q3

2012.

Future

dividend,

following

the

stub

dividend,

is

subject

to

approval

by

the

Board

of

Directors.

Constellation Dividend

Record Date

Payment Date

Dividend Type

Per Share Amount

12/12/2011

1/3/2012

Regular CEG Dividend

$0.24

2/28/2012

3/28/2012

Pre-

close

CEG

Stub

Dividend

(1)

$0.206

5/15/2012

6/8/2012

Post-

close EXC Stub Dividend

(1)

$0.449

8/15/2012

9/10/2012

Regular EXC Dividend

(2)

$0.525

11/15/2012

12/10/2012

Regular Dividend

(2)

$0.525

Constellation shareholders will receive the Exelon dividend rate upon merger close

37

ComEd –

Regulatory Schedule for 2012

Q1

Q2

Q3

Q4

Initial filing with

ICC (11/8/11)

Proposed order

(around 5/1);

Final order 

(by 5/31)

Procurements

for

ATC

supply

and

RECs

for

6/1/13-

12/31/17

(by

end

of

February)

Q4 2011

Distribution

Formula Rate 

(Docket # 11-0721)

Performance

Metrics

(Docket # 11-0772)

Illinois Power

Agency

Procurement

Transmission

Rate Update

Annual update

filing with FERC

(5/15)

Rates effective

(June 2012 thru

May 2013)

Rates effective

June thru Dec.

Filing with ICC

(12/8/11)

Final order 

(by 4/6)

Second filing with

ICC (by 5/1)

Rates

effective Jan.

thru Dec.

Regular annual 

procurement

event (Spring)

Note: ICC = Illinois Commerce Commission; FERC = Federal Energy Regulatory Commission; ATC = around-the-clock; REC = renewable energy credit

Final order

(by 12/27)

Annual

updates (by

6/1)

2013

38

PECO –

Default Service Plan Filing (DSP II)

(1) FR = Full Requirements;   (2) FPFR = Fixed-Price Full Requirements

Proposed Procurement Mix

Class

DSP I (1/1/11

–

5/31/13)

DSP II (6/1/13

–

5/31/15)

Large C&I

Current load

retained: 4%

100% spot-priced FR

(1)

products

2011 opt-in FPFR

(2)

product

100% of supply procured directly from the PJM spot

market

Medium

Commercial

Current load

retained: 22%

85% 1-year FPFR products, 15% spot-priced FR

products

100% 6-month FPFR products

Small

Commercial

Current load

retained: 48%

70% 1-year FPFR products, 20% 2-year FPFR

products, 10% spot-priced FR products

100% 1-year FPFR products

Residential

Current load

retained: 75%

45% 2-year FPFR products; 30% 1-year FPFR

products; targeted 20% block products of 1-yr, 2-yr,

5-yr and seasonal terms; targeted 5% spot market

purchases

As block products expire, block and spot is replaced

by FPFR products with terms ending 5/31/15 (end of

DSP II period)

Remainder of portfolio is a mix of 2-yr and 1-yr FPFR

products, with delivery periods overlapping on a semi-

annual basis

Filing Schedule:

On 1/13/12, PECO filed a new Default Service Plan with the PAPUC, which outlines how PECO will purchase

electricity for customers not purchasing from a competitive generation supplier from 6/1/13 through 5/31/15

PAPUC will assign an Administrative Law Judge to set a procedural schedule with a Final Order requested no later

than mid-October 2012

Note: PAPUC = Pennsylvania Public Utility Commission

Incorporates Retail Market Enhancements suggested by PAPUC Order

issued 12/15/11:

Offers a 1-year opt-in auction program with price at least 5% less than PECO’s expected Price to Compare as of 6/1/13

Establishes a residential customer referral program to promote the lowest 1-year, fixed price available each month

Provides

customer

information

and

referral

programs

for

various

products;

“seamless”

moves

between

properties

Sufficient Liquidity

($ millions)

Exelon

(3)

Aggregate

Bank

Commitments

(1)

$1,000

$600

$5,600

$7,700

Outstanding Facility Draws

--

--

--

--

Outstanding Letters of Credit

(1)

(1)

(884)

(894)

Available

Capacity

Under

Facilities

999

599

4,716

6,806

Outstanding Commercial Paper

--

--

--

(136)

Available Capacity Less Outstanding

Commercial Paper

$999

$599

$4,716

$6,670

Exelon bank facilities are largely untapped

39

(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.

Available Capacity Under Bank Facilities as of January 17, 2012

(2)

Key Credit Metrics

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:

A1

A-

A

15-18%

Generation:

A3

BBB

BBB+

30-35%

(4)

10%

20%

30%

40%

50%

60%

Exelon

PECO

ComEd

2011A

2010A

2009A

0X

2X

4X

6X

8X

10X

12X

Exelon

PECO

ComEd

2011A

2010A

2009A

40%

50%

60%

70%

80%

Exelon

PECO

ComEd

2011A

2010A

2009A

FFO/Debt

(1)

Interest Coverage

(1)

Debt to Cap

(1)

40

(1)

See slide 41 for reconciliations to GAAP.

(2)

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

ComEd and PECO as of January 20, 2012.

(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.

ExGen/

Corp

ExGen/

Corp

ExGen/

Corp

Exelon Consolidated Metric Calculations and Ratios

Exelon 2010 YE Adjustments

FFO Calculation

2010 YE

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

Net Cash Flows provided by Operating Activities

         5,244

Pg 159 - Stmt. of Cash Flows

+/- Change in Working Capital

            644

Pg 159 - Stmt. of Cash Flows

(1)

-    PECO Transition Bond Principal Paydown

           (392)

Pg 174 - Stmt. of Cash Flows

(2)

+    PPA Depreciation Adjustment

            207

Pg 295 - Commitments and Contingencies

(3)

+/- Pension/OPEB Contribution Normalization

            448

Pg 268-269 - Post-retirement Benefits

(4)

+    Operating Lease Depreciation Adjustment

              35

Pg 299 - Commitments and Contingencies

(5)

+/- Decommissioning activity

           (143)

Pg 159- Stmt. of Cash Flows

+/- Other Minor FFO Adjustments

(6)

             (54)

= FFO (a)

         5,989

Debt Calculation

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

       12,828

Pg 161 - Balance Sheet

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

               -  

Pg 161 - Balance Sheet

-    PECO Transition Bond Principal Paydown

               -  

N/A - no debt outstanding at year-end

+    PPA Imputed Debt

         1,680

Pg 295 - Commitments and Contingencies

(7)

+    Pension/OPEB Imputed Debt

         3,825

Pg 268 - Post-retirement benefits

(8)

+    Operating Lease Imputed Debt

            428

Pg 299 - Commitments and Contingencies

(9)

+    Asset Retirement Obligation

               -  

Pg 261-267 - Asset Retirement Obligations

(10)

+/- Other Minor Debt Equivalents

(11)

              84

= Adjusted Debt (b)

       18,845

Interest Calculation

Net Interest Expense

            817

Pg 158 - Statement of Operations

-    PECO Transition Bond Interest Expense

             (22)

Pg 182 - Significant Accounting Policies

+   Interest  on Present Value (PV) of Operating Leases

              29

Pg 299 - Commitments and Contingencies

(12)

+   Interest  on PV of Purchased Power Agreements (PPAs)

              99

Pg 295 - Commitments and Contingencies

(13)

+/- Other Minor Interest Adjustments

(14)

              37

= Adjusted Interest (c)

            960

Equity Calculation

Total Equity

       13,563

Pg 161 - Balance Sheet

+    Preferred Securities of Subsidaries

              87

Pg 161 - Balance Sheet

+/- Other Minor Equity Equivalents

(15)

            111

= Adjusted Equity (d)

       13,761

(1)

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

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

(2)

Reflects retirement of variable interest entity + change in restricted cash

(3)

Reflects

net

capacity

payment

–

interest

on

PV

of

PPAs

(using

weighted

average

cost

of

debt)

(4)

Reflects

employer

contributions

–

(service

costs

+

interest

costs

+

expected

return

on

assets),

net

of

taxes at 35%

(5)

Reflects

operating

lease

payments

–

interest

on

PV

of

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

on

securities

qualifying

for

hybrid

treatment

(50% debt / 50% equity)

(15)

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

2010A Credit Metrics

41

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%

=

=

=

42

4Q GAAP EPS Reconciliation

Three Months Ended December 31, 2011

ExGen

ComEd

PECO

Other

Exelon

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

$0.54

$0.18

$0.11

$(0.02)

$0.82

Mark-to-market adjustments from economic hedging activities

0.07

-

-

-

0.07

Unrealized gains related to nuclear decommissioning trust funds

0.07

-

-

-

0.07

Retirements of fossil generation units

(0.01)

-

-

-

(0.01)

Constellation acquisition costs

(0.01)

-

(0.00)

(0.02)

(0.03)

Non-cash remeasurement of deferred income taxes

0.01

-

-

(0.02)

(0.01)

4Q 2011 GAAP Earnings (Loss) Per Share

$0.67

$0.18

$0.11

$(0.05)

$0.91

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 December 31, 2010

ExGen

ComEd

PECO

Other

Exelon

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

$0.81

$0.13

$0.03

$(0.01)

$0.96

Mark-to-market adjustments from economic hedging activities

(0.17)

-

-

-

(0.17)

2007 Illinois electric rate settlement

(0.01)

-

-

-

(0.01)

Unrealized gains related to nuclear decommissioning trust funds

0.04

-

-

-

0.04

Retirements of fossil generation units

(0.03)

-

-

-

(0.03)

Exelon Wind acquisition costs

(0.01)

-

-

-

(0.01)

Asset retirement obligation

-

0.01

-

-

0.01

4Q 2010 GAAP Earnings (Loss) Per Share

$0.63

$0.14

$0.03

$(0.01)

$0.79

43

Full Year GAAP EPS Reconciliation

Twelve Months Ended December 31, 2011

ExGen

ComEd

PECO

Other

Exelon

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

$3.01

$0.61

$0.58

$(0.05)

$4.16

Mark-to-market adjustments from economic hedging activities

(0.27)

-

-

-

(0.27)

Unrealized losses related to nuclear decommissioning trust funds

(0.00)

-

-

-

(0.00)

Retirement of fossil generating units

(0.05)

-

-

-

(0.05)

Asset retirement obligation

(0.03)

-

0.00

-

(0.02)

Constellation acquisition costs

(0.01)

-

(0.00)

(0.06)

(0.07)

AVSR 1 acquisition costs

(0.01)

-

-

-

(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

-

-

-

0.03

Recovery of costs pursuant to distribution rate case order

-

0.03

-

-

0.03

Non-cash remeasurement of deferred income taxes

0.01

-

-

(0.02)

(0.01)

FY 2011 GAAP Earnings (Loss) Per Share

$2.66

$0.63

$0.58

$(0.12)

$3.75

Twelve Months Ended December 31, 2010

ExGen

ComEd

PECO

Other

Exelon

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

$2.91

$0.68

$0.54

$(0.07)

$4.06

Mark-to-market adjustments from economic hedging activities

0.08

-

-

-

0.08

2007 Illinois electric rate settlement

(0.02)

-

-

-

(0.02)

Unrealized gains related to nuclear decommissioning trust funds

0.08

-

-

-

0.08

Asset retirement obligation

-

0.01

-

-

0.01

Retirement of fossil generating units

(0.08)

-

-

-

(0.08)

Non-cash remeasurement of income tax uncertainties

0.10

(0.16)

(0.03)

(0.01)

(0.10)

Non-cash charge resulting from health care legislation

(0.04)

(0.02)

(0.02)

(0.02)

(0.10)

Emission allowances impairment

(0.05)

-

-

-

(0.05)

Exelon Wind acquisition costs

(0.01)

-

-

-

(0.01)

FY 2010 GAAP Earnings (Loss) Per Share

$2.97

$0.51

$0.49

$(0.10)

$3.87

Note:

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