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

February 7, 2013

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
1-1910	BALTIMORE GAS AND ELECTRIC COMPANY (a Maryland corporation) 2 Center Plaza 110 West Fayette Street Baltimore, Maryland 21201 (410) 234-5000	52-0280210

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 February 7, 2013, Exelon Corporation (Exelon) announced via press release its results for the fourth quarter ended December 31, 2012. 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 2012 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 10:00 AM ET (9:00 AM CT) on February 7, 2013. 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 86145798. 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 21, 2013. The U.S. and Canada call-in number for replays is 800-585-8367, and the international call-in number is 404-537-3406. The conference ID number is 86145798.

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 Corporation, Exelon Generation Company, LLC, Commonwealth Edison Company, PECO Energy Company, and Baltimore Gas and Electric Company (Registrants). Information contained herein relating to any individual Registrant has been furnished by such Registrant on its own behalf. No Registrant makes any representation as to information relating to any other Registrant.

This Current Report includes forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995 that are subject to risks and uncertainties. The factors that could cause actual results to differ materially from these forward-looking statements include those discussed herein as well as those discussed in (1) Exelon’s 2011 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) Constellation Energy Group’s 2011 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; (3) the Registrant’s Third Quarter 2012 Quarterly Report on Form 10-Q in (a) Part II, Other Information, ITEM 1A. Risk Factors and (b) Part I, Financial Information, ITEM 1. Financial Statements: Note 16; and (4) other factors discussed in filings with the SEC by the Registrants. Readers are cautioned not to place undue reliance on these forward-looking statements, which apply only as of the date of this Current Report. None of the Registrants undertakes any obligation to publicly release any revision to its forward-looking statements to reflect events or circumstances after the date of this Current Report.

SIGNATURES

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

EXELON CORPORATION

/s/ Jonathan W. Thayer

Jonathan W. Thayer

Executive Vice President and Chief Financial Officer

Exelon Corporation

EXELON GENERATION COMPANY, LLC

/s/ Bryan P. Wright

Bryan P. Wright

Senior Vice President and Chief Financial Officer Exelon Generation Company, LLC

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, Chief Financial Officer and

Treasurer

PECO Energy Company

BALTIMORE GAS AND ELECTRIC COMPANY

/s/ Carim V. Khouzami

Carim V. Khouzami

Vice President, Chief Financial Officer and Treasurer

Baltimore Gas and Electric Company

February 7, 2013

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: Ravi Ganti Investor Relations 312-394-2348   Paul Adams Corporate Communications 410-470-4167 FOR IMMEDIATE RELEASE

EXELON ANNOUNCES FOURTH QUARTER AND FULL YEAR 2012

RESULTS; INTRODUCES 2013 GUIDANCE; DECLARES FIRST QUARTER

DIVIDEND AND SETS REVISED DIVIDEND POLICY

CHICAGO (Feb. 7, 2013) — Exelon Corporation (NYSE: EXC) announced fourth quarter and full year 2012 consolidated earnings as follows:

Exelon Consolidated Earnings (unaudited)

	Full Year				Fourth Quarter
	2012		2011		2012		2011
Adjusted (non-GAAP) Operating Results:
Net Income ($ millions)	$	2,330	$	2,763	$	547	$	544
Diluted Earnings per Share	$	2.85	$	4.16	$	0.64	$	0.82
GAAP Results:
Net Income ($ millions)	$	1,160	$	2,495	$	378	$	606
Diluted Earnings per Share	$	1.42	$	3.75	$	0.44	$	0.91

“Exelon had another strong year of operational performance and closed on a very successful, transformational merger that gives us a presence across the value chain,” said Christopher M. Crane, Exelon’s president and CEO. “Despite major storms and severe economic challenges, we delivered 2012 earnings within our guidance range. We have revised our dividend, effective with the second quarter 2013 dividend, to position us to maintain our investment grade rating, return a stable dividend and provide capacity to invest in growth.”

Fourth Quarter Operating Results

Fourth quarter 2012 earnings include financial results for Constellation Energy and Baltimore Gas and Electric Company (BGE). Therefore, the composition of results of operations from 2012 and 2011 are not comparable for Exelon Generation Company, LLC (Generation), BGE and Exelon.

1

As shown in the table above, Exelon’s adjusted (non-GAAP) operating earnings declined to $0.64 per share in the fourth quarter of 2012 from $0.82 per share in the fourth quarter of 2011. Earnings in fourth quarter 2012 primarily reflected the following negative factors:

• Lower energy margins at Generation, resulting from decreased capacity pricing related to the Reliability Pricing Model (RPM) for the PJM Interconnection, LLC (PJM) market, higher nuclear fuel costs and lower realized market prices for the sale of energy in the Mid-Atlantic and Midwest regions;

• Higher operating and maintenance expenses, including increased labor, contracting and materials and the impact of higher storm costs at PECO and BGE due to Sandy;

• Impact of increased average diluted common shares outstanding as a result of the merger; and

• Higher depreciation and amortization expense due to ongoing capital expenditures.

These factors were partially offset by:

• The addition of Constellation Energy’s contribution to Generation’s energy margins; and

• Favorable impacts of weather at ComEd and PECO.

Adjusted (non-GAAP) operating earnings for the fourth quarter of 2012 do not include the following items (after tax) that were included in reported GAAP earnings:

	(in millions)			(per diluted share)
Mark-to-Market Impact of Economic Hedging Activities	$	123		$	0.14
Unrealized Gains Related to NDT (Nuclear Decommissioning Trust) Fund Investments	$	2			—
Plant Retirements and Divestitures	$	(38	)	$	(0.05	)
Constellation Merger and Integration Costs	$	(46	)	$	(0.05	)
Non-Cash Remeasurement of Deferred Income Taxes	$	1			—
Amortization of Commodity Contract Intangibles	$	(211	)	$	(0.24	)
Amortization of the Fair Value of Certain Debt	$	3			—
Asset Retirement Obligation	$	5		$	0.01
Midwest Generation Bankruptcy Charges	$	(8	)	$	(0.01	)

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)
Mark-to-Market Impact of Economic Hedging Activities	$	45		$	0.07
Unrealized Gains Related to NDT Fund Investments	$	46		$	0.07
Plant Retirements and Divestitures	$	(4	)	$	(0.01	)
Constellation Merger and Integration Costs	$	(21	)	$	(0.03	)
Non-Cash Remeasurement of Deferred Income Taxes	$	(4	)	$	(0.01	)

2

Dividend

Exelon’s Board of Directors declared the first quarter 2013 dividend of $0.525 per share and approved a revised dividend policy going forward. The first quarter dividend is payable on March 8, 2013 to shareholders of record at 5:00 PM EST on Feb. 19, 2013. The first quarter dividend is based on our previous level of $2.10 per share on an annualized basis, while the new dividend contemplates a regular $0.31 per share quarterly dividend beginning in the second quarter of 2013 (or $1.24 per share on an annualized basis). Exelon intends to maintain the normal cadence of quarterly dividend declarations by the Board, so the Board will take formal action to declare the next dividend in the second quarter.

2013 Earnings Outlook

Exelon introduced a guidance range for 2013 adjusted (non-GAAP) operating earnings of $2.35 to $2.65 per share. Operating earnings guidance is based on the assumption of normal weather.

The outlook for 2013 adjusted (non-GAAP) operating earnings for Exelon and its subsidiaries excludes the following items:

• Mark-to-market adjustments from economic hedging activities;

• Financial impacts associated with the planned retirement of fossil generating units and the sale in the fourth quarter of 2012 of three generating stations as required by the merger;

• Certain costs incurred related to the Constellation merger and integration initiatives;

• Non-cash amortization of intangible assets, net, related to commodity contracts recorded at fair value at the merger date;

• Non-cash amortization of certain debt recorded at fair value at the merger date expected to be retired in 2013;

• Significant impairments of assets, including goodwill;

• Other unusual items; and

• Significant changes to GAAP.

Fourth Quarter and Recent Highlights

• Nuclear Operations: Generation’s nuclear fleet, including its owned output from the Salem Generating Station, produced 34,882 gigawatt-hours (GWh) in the fourth quarter of 2012, compared with 34,893 GWh in the fourth quarter of 2011. The output data excludes the units owned by Constellation Energy Nuclear Group LLC (CENG). Excluding Salem and the units owned by CENG, the Exelon-operated nuclear plants achieved a 93.0 percent capacity factor for both the fourth quarter of 2012 and fourth quarter of 2011. The number of planned refueling outage days totaled 113 in the fourth quarter of 2012 versus 103 days in the fourth quarter of 2011. The number of non-refueling outage days at the Exelon-operated plants totaled one day in the fourth quarter of 2012, compared with 11 days in the fourth quarter of 2011.

3

• Fossil and Renewables Operations: The equivalent demand forced outage rate for Generation’s fossil fleet was 1.5 percent in the fourth quarter of 2012, compared with 1.6 percent in the fourth quarter of 2011. The 2012 results include former Constellation plants, exclusive of the Maryland Clean Coal plants that were sold on Dec. 3, 2012, whereas 2011 data includes only legacy Exelon plants. The equivalent availability factor for the hydroelectric facilities was 95.0 percent in the fourth quarter of 2012, compared with 95.9 percent in the fourth quarter of 2011. The energy capture for the wind fleet was 92.2 percent in the fourth quarter of 2012, compared with 94.8 percent in the fourth quarter of 2011.

• ComEd Distribution Formula Rate Cases: On Oct. 3, 2012, the Illinois Commerce Commission (ICC) issued its final Order on Remand (Rehearing Order) in ComEd’s expedited rehearing of specific items pursuant to the Electric Infrastructure Modernization Act (EIMA). The Rehearing Order (which covered docket 11-0721) addressed three key conclusions reached in the ICC’s May Order: (1) ComEd’s pension asset recovery; (2) the rate of interest to affix to over or under recovered costs; and (3) the use of a year-end or an “average year” rate base in determining ComEd’s reconciliation revenue requirement. In the Rehearing Order, the ICC adopted ComEd’s position on the return on its pension asset. As a result, ComEd recorded in the fourth quarter an increase in revenue of approximately $135 million pre-tax in 2012 consistent with the terms of the Rehearing Order.

On Dec. 19, 2012, the ICC ruled on ComEd’s formula rate (docket 12-0321) setting rates for 2013 based on (1) 2011 actual costs updated for 2012 plant additions and the associated depreciation and accumulated deferred income taxes and (2) reconciling the revenue requirements underlying the rates in effect in 2011 with 2011 actual costs and factoring in the ROE Collar. The ICC approved a $72.6 million increase over the rates approved in docket 11-0721 on re-hearing. ComEd had requested an increase of $74.2 million. The contested items from docket 11-0721 on re-hearing such as use of average vs. year-end rate base and the interest rate on the reconciliation are currently under appeal with the court and are not included in the approved amount.

• Credit Facility Synergies: On Dec. 31, 2012, Exelon achieved targeted credit facility reductions and associated synergies with the termination of the $1.5 billion legacy Constellation revolver. Cost effective liquidity was established earlier in 2012 for all operating companies through 2017. The ComEd $1 billion facility was established in March 2012. Via the “Amend and Extend” program executed in August 2012, facilities were refinanced at BGE ($600 million), Exelon Corp ($500 million), Generation ($5.3 billion) and PECO ($600 million),

• Pension Funding Strategy: Exelon executed a lump sum buyout offering for terminated vested employees in the largest pension plans (approximately 7,500 former employees). This transaction involved using $260 million of pension trust assets to buyout terminated vested employees and permanently settling the associated obligation. Exelon’s gross pension liability was reduced by $425 million, resulting in a $165 million improvement in the funded status of the pension plans at year end. The lump sum buyout option was an incremental step in Exelon’s ongoing effort to manage benefit costs and de-risk the pension plans over time.

4

• ComEd Like-Kind-Exchange: As previously disclosed, in 1999 ComEd deferred $1.2 billion of gain on the sale of its fossil generating facilities by acquiring like-kind property in a purchase leaseback transaction. In a recent decision, a court disallowed deductions stemming from a lease-in, lease-out transaction. This decision has caused Exelon to assess whether it is more likely than not that it will prevail in litigation with the IRS concerning the purchase leaseback transaction. As a result of the assessment, Exelon expects to record in the first quarter of 2013 a non-cash charge to earnings of approximately $270 million, which represents the full amount of interest expense (after-tax) and incremental state tax expense that would be payable if Exelon is unsuccessful in litigation. Of this amount, approximately $185 million will be recorded at ComEd and the balance at Exelon. These charges to expense will not be reflected in adjusted (non-GAAP) operating earnings. Exelon intends to hold ComEd harmless from any unfavorable impacts of the after-tax interest amounts on ComEd’s equity. For additional information, please see the Form 8-K that Exelon filed on January 31, 2013.

• Renewable Fleet: Four wind construction projects (totaling 273 megawatts (MW)) achieved commercial operation in the fourth quarter: Harvest II (59 MW in Huron County, Mich.) on Nov. 1, 2012; Beebe (82 MW in Gratiot, Mich.) on Dec. 18, 2012; Whitetail (92 MW in Webb, Texas) on Dec. 21, 2012; and High Mesa (40 MW in Twin Falls County, Idaho) on Dec. 27, 2012. In addition, the first block (31 MW) of the Antelope Valley Solar Ranch Project became operational in December 2012. The remaining phases of the project are on track to be completed by the original planned commercial operation date of December 2013.

• Fossil Fleet Sales and Retirements: Exelon Power finalized the sale of its three Maryland power plants (2,648 MW of installed capacity) to Raven Power Holdings LLC on Dec. 3, 2012. The sale fulfills Exelon’s commitment to divest the plants as a part of its merger with Constellation. Exelon Power also completed the sale of its ownership stake in ACE Cogeneration, a 102-MW coal facility in Trona, Calif., to DCO Energy on Nov. 6, 2012. In addition to the asset sales, Exelon Power informed PJM on Oct. 31, 2012 of its intent to retire Schuylkill Unit 1 in Philadelphia and Riverside Unit 6 in Baltimore County. Schuylkill Unit 1 was deactivated on Jan. 1, 2013. Riverside 6 will be deactivated by Jun. 1, 2014.

• 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 Dec. 31, 2012, is 94 to 97 percent for 2013, 62 to 65 percent for 2014, and 27 to 30 percent for 2015. The primary objective of Exelon’s hedging program is to manage market risks and protect the value of its generation and its investment-grade balance sheet while preserving its ability to participate in improving long-term market fundamentals.

5

Operating Company Results

Generation consists of owned and contracted electric generating facilities and wholesale and retail customer supply of electric and natural gas products and services, including renewable energy products, risk management services and natural gas exploration and production activities.

Fourth quarter 2012 GAAP net income was $137 million, compared with $446 million in the fourth quarter of 2011. Adjusted (non-GAAP) operating earnings for the fourth quarter of 2011 and 2012 do not include various items (after tax) that were included in reported GAAP earnings. A reconciliation of Adjusted (non-GAAP) Operating Earnings to GAAP Net Income is in the table below:

($ millions)	4Q12			4Q11
Generation Adjusted (non-GAAP) Operating Earnings	$	283		$	359
Mark-to-Market Impact of Economic Hedging Activities	$	145		$	45
Unrealized Gains Related to NDT Fund Investments	$	2		$	46
Plant Retirements and Divestitures	$	(38	)	$	(4	)
Constellation Merger and Integration Costs	$	(35	)	$	(6	)
Non-Cash Remeasurement of Deferred Income Taxes	$	(9	)	$	6
Amortization of Commodity Contract Intangibles	$	(211	)		—
Amortization of Fair Value of Certain Debt	$	3			—
Asset Retirement Obligation	$	5			—
Midwest Generation Bankruptcy Charges	$	(8	)		—
Generation GAAP Net Income	$	137		$	446

Generation’s Adjusted (non-GAAP) Operating Earnings in the fourth quarter of 2012 decreased $76 million compared with the same quarter in 2011. This decrease primarily reflected:

• Lower energy margins at Generation, resulting from decreased capacity pricing related to RPM for the PJM market, higher nuclear fuel costs and lower realized market prices for the sale of energy in the Mid-Atlantic and Midwest regions;

• Higher operating and maintenance expenses;

• Higher depreciation and amortization expense due to ongoing capital expenditures; and

• Higher interest due to higher outstanding debt balance.

These items were partially offset by contribution to Generation’s energy margins from the addition of Constellation Energy to Generation’s operations.

6

Generation’s average realized margin on all electric sales, including sales to affiliates and excluding trading activity, was $26.52 per megawatt-hour (MWh) in the fourth quarter of 2012, compared with $39.31 per MWh in the fourth quarter of 2011.

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

ComEd recorded GAAP net income of $160 million in the fourth quarter of 2012, compared with net income of $121 million in the fourth quarter of 2011. Adjusted (non-GAAP) operating earnings for the fourth quarter of 2011 and 2012 do not include an item (after tax) that was included in reported GAAP earnings. A reconciliation of Adjusted (non-GAAP) Operating Earnings to GAAP Net Income is in the table below:

($ millions)	4Q12			4Q11
ComEd Adjusted (non-GAAP) Operating Earnings	$	162		$	121
Constellation Merger and Integration Costs	$	(2	)		—
ComEd GAAP Net Income	$	160		$	121

ComEd’s Adjusted (non-GAAP) Operating Earnings in the fourth quarter of 2012 were up $41 million from the same quarter in 2011, primarily due to:

• Impacts of the October 2012 rehearing order issued by the ICC primarily related to ComEd’s recovery of the pension asset;

• Lower interest expense due to tax settlements; and

• Lower income taxes.

These items were partially offset by lower distribution revenue due to lower allowed ROE under the provision of the formula rate mechanism and a 2011 credit for the allowed recovery of certain storm costs pursuant to EIMA.

For the fourth quarter of 2012, heating degree-days in the ComEd service territory were up 10.8 percent relative to the same period in 2011 but were 11.5 percent below normal. Total retail electric deliveries increased 0.4 percent quarter over quarter.

Weather-normalized retail electric deliveries decreased 0.1 percent in the fourth quarter of 2012 relative to 2011, reflecting decreases in deliveries to residential and large commercial & industrial customers, partially offset by increases in deliveries to small commercial & industrial customers. For ComEd, weather had a favorable after-tax effect of $1 million on fourth quarter 2012 earnings relative to 2011 and an unfavorable after-tax effect of $4 million relative to normal weather.

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

PECO’s GAAP net income in the fourth quarter of 2012 was $79 million, compared with $73 million in the fourth quarter of 2011. Adjusted (non-GAAP) Operating Earnings for the fourth quarter of 2011 and 2012 do not include an item (after tax) that was included in reported GAAP earnings. A reconciliation of Adjusted (non-GAAP) Operating Earnings to GAAP Net Income is in the table below:

($ millions)	4Q12			4Q11
PECO Adjusted (non-GAAP) Operating Earnings	$	81		$	74
Constellation Merger and Integration Costs	$	(2	)	$	(1	)
PECO GAAP Net Income	$	79		$	73

7

PECO’s Adjusted (non-GAAP) Operating Earnings in the fourth quarter of 2012 increased $7 million from the same quarter in 2011, reflecting the impact of favorable weather and lower income taxes primarily due to gas tax repairs deduction; these favorable items were partially offset by higher storm costs from Sandy.

For the fourth quarter of 2012, heating degree-days in the PECO service territory were up 13.8 percent from 2011 but were 9.0 percent below normal. Total retail electric deliveries were up 2.3 percent quarter over quarter. On the gas side, deliveries in the fourth quarter of 2012 were up 12.4 percent from the fourth quarter of 2011.

Weather-normalized retail electric deliveries were up 0.6 percent in the fourth quarter of 2012 relative to 2011, reflecting increases in deliveries to residential and large consumer & industrial customers and declines in deliveries to small commercial & industrial customers. Weather-normalized gas deliveries were up 0.6 percent in the fourth quarter of 2012. For PECO, weather had a favorable after-tax effect of $17 million on fourth quarter 2012 earnings relative to 2011 and unfavorable after-tax effect of $10 million relative to normal weather.

BGE consists of electricity transmission and distribution operations and retail natural gas distribution operations in central Maryland.

BGE’s GAAP net income in the fourth quarter of 2012 was $15 million. The net income included after-tax costs of $3 million associated with the merger and integration initiatives. Excluding the effects of these items, BGE’s adjusted (non-GAAP) Operating Earnings in the fourth quarter of 2012 were $18 million.

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 10 and 11 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 February 7, 2013.

8

Cautionary Statements Regarding Forward-Looking Information

This news release contains certain forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995, that are subject to risks and uncertainties. The factors that could cause actual results to differ materially from the forward-looking statements made by Exelon Corporation, Commonwealth Edison Company, PECO Energy Company, Baltimore Gas and Electric Company and Exelon Generation Company, LLC (Registrants) include those factors discussed herein, as well as the items discussed in (1) Exelon’s 2011 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) Constellation Energy Group’s 2011 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; (3) the Registrants’ Third Quarter 2012 Quarterly Report on Form 10-Q in (a) Part II, Other Information, ITEM 1A. Risk Factors and (b) Part I, Financial Information, ITEM 1. Financial Statements: Note 15; and (4) other factors discussed in filings with the SEC by the Registrants. Readers are cautioned not to place undue reliance on these forward-looking statements, which apply only as of the date of this new release. None of the Registrants undertakes any obligation to publicly release any revision to its forward-looking statements to reflect events or circumstances after the date of this news release.

# # #

Exelon Corporation is the nation’s leading competitive energy provider, with 2012 revenues of approximately $23.5 billion. Headquartered in Chicago, Exelon has operations and business activities in 47 states, the District of Columbia and Canada. Exelon is one of the largest competitive U.S. power generators, with approximately 35,000 megawatts of owned capacity comprising one of the nation’s cleanest and lowest-cost power generation fleets. The company’s Constellation business unit provides energy products and services to approximately 100,000 business and public sector customers and more than 1 million residential customers. Exelon’s utilities deliver electricity and natural gas to more than 6.6 million customers in central Maryland (BGE), northern Illinois (ComEd) and southeastern Pennsylvania (PECO).

9

Earnings Release Attachments

Table of Contents

Consolidating Statements of Operations - Three Months Ended December 31, 2012 and 2011	1
Consolidating Statements of Operations - Twelve Months Ended December 31, 2012 and 2011	2
Business Segment Comparative Statements of Operations - Generation and ComEd - Three and Twelve Months Ended December 31, 2012 and 2011	3
Business Segment Comparative Statements of Operations - PECO and BGE - Three and Twelve Months Ended December 31, 2012 and 2011	4
Business Segment Comparative Statements of Operations - Other - Three and Twelve Months Ended December 31, 2012 and 2011	5
Consolidated Balance Sheets - December 31, 2012 and December 31, 2011	6
Consolidated Statements of Cash Flows - Twelve Months Ended December 31, 2012 and 2011	7
Reconciliation of Adjusted (non-GAAP) Operating Earnings to GAAP Consolidated Statements of Operations - Exelon - Three Months Ended December 31, 2012 and 2011	8
Reconciliation of Adjusted (non-GAAP) Operating Earnings to GAAP Consolidated Statements of Operations - Exelon - Twelve Months Ended December 31, 2012 and 2011	9
Reconciliation of Adjusted (non-GAAP) Operating Earnings to GAAP Earnings By Business Segment - Three Months Ended December 31, 2012 and 2011	10
Reconciliation of Adjusted (non-GAAP) Operating Earnings to GAAP Earnings By Business Segment - Twelve Months Ended December 31, 2012 and 2011	11
Reconciliation of Adjusted (non-GAAP) Operating Earnings to GAAP Consolidated Statements of Operations - Generation - Three and Twelve Months Ended December 31, 2012 and 2011	12
Reconciliation of Adjusted (non-GAAP) Operating Earnings to GAAP Consolidated Statements of Operations - ComEd - Three and Twelve Months Ended December 31, 2012 and 2011	13
Reconciliation of Adjusted (non-GAAP) Operating Earnings to GAAP Consolidated Statements of Operations - PECO - Three and Twelve Months Ended December 31, 2012 and 2011	14
Reconciliation of Adjusted (non-GAAP) Operating Earnings to GAAP Consolidated Statements of Operations - BGE - Three Months Ended December 31, 2012 and March 12, 2012 through December 31, 2012.	15
Reconciliation of Adjusted (non-GAAP) Operating Earnings to GAAP Consolidated Statements of Operations - Other - Three and Twelve Months Ended December 31, 2012 and 2011	16
Exelon Generation Statistics - Three Months Ended December 31, 2012, September 30, 2012, June 30, 2012, March 31, 2012 and December 31, 2011	17
Exelon Generation Statistics - Twelve Months Ended December 31, 2012 and 2011	18
ComEd Statistics - Three and Twelve Months Ended December 31, 2012 and 2011	19
PECO Statistics - Three and Twelve Months Ended December 31, 2012 and 2011	20
BGE Statistics - Three Months Ended December 31, 2012 and March 12, 2012 through December 31, 2012.	21

EXELON CORPORATION

Consolidating Statements of Operations

(unaudited)

(in millions)

	Three Months Ended December 31, 2012
	Generation			ComEd			PECO			BGE			Other (a)			Exelon Consolidated
Operating revenues	$	3,928		$	1,289		$	790		$	703		$	(426	)	$	6,284
Operating expenses
Purchased power and fuel		2,043			421			342			326			(373	)		2,759
Operating and maintenance		1,272			345			235			171			(11	)		2,012
Depreciation, amortization, accretion and depletion		204			152			56			80			13			505
Taxes other than income		97			71			40			65			9			282
Total operating expenses		3,616			989			673			642			(362	)		5,558
Equity in earnings of unconsolidated affiliates		(22	)		—			—			—			—			(22	)
Operating income		290			300			117			61			(64	)		704
Other income and deductions
Interest expense		(78	)		(77	)		(30	)		(34	)		(12	)		(231	)
Other, net		54			27			2			5			5			93
Total other income and deductions		(24	)		(50	)		(28	)		(29	)		(7	)		(138	)
Income (loss) before income taxes		266			250			89			32			(71	)		566
Income taxes		127			90			9			14			(58	)		182
Net income (loss)		139			160			80			18			(13	)		384
Net loss attributable to noncontrolling interests, preferred security dividends and preference stock dividends		2			—			1			3			—			6
Net income (loss) on common stock	$	137		$	160		$	79		$	15		$	(13	)	$	378
	Three Months Ended December 31, 2011
	Generation			ComEd			PECO			BGE			Other (a)			Exelon Consolidated
Operating revenues	$	2,528		$	1,362		$	778		$	—		$	(310	)	$	4,358
Operating expenses
Purchased power and fuel		794			599			358			—			(320	)		1,431
Operating and maintenance		842			258			196			—			26			1,322
Depreciation, amortization, accretion and depletion		154			149			53			—			4			360
Taxes other than income		65			71			40			—			7			183
Total operating expenses		1,855			1,077			647			—			(283	)		3,296
Equity in loss of unconsolidated affiliates		(1	)		—			—			—			—			(1	)
Operating income		672			285			131			—			(27	)		1,061
Other income and deductions
Interest expense		(43	)		(87	)		(32	)		—			(19	)		(181	)
Other, net		135			4			2			—			9			150
Total other income and deductions		92			(83	)		(30	)		—			(10	)		(31	)
Income before income taxes		764			202			101						(37	)		1,030
Income taxes		318			81			27			—			(3	)		423
Net income (loss)		446			121			74			—			(34	)		607
Preferred security dividends		—			—			1			—			—			1
Net income (loss) on common stock	$	446		$	121		$	73		$	—		$	(34	)	$	606

(a) 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)

	Twelve Months Ended December 31, 2012 (a)
	Generation			ComEd			PECO			BGE			Other (b)			Exelon Consolidated
Operating revenues	$	14,437		$	5,443		$	3,186		$	2,091		$	(1,668	)	$	23,489
Operating expenses
Purchased power and fuel		7,061			2,307			1,375			1,052			(1,638	)		10,157
Operating and maintenance		5,028			1,345			809			596			183			7,961
Depreciation, amortization, accretion and depletion		768			610			217			238			48			1,881
Taxes other than income		369			295			162			167			26			1,019
Total operating expenses		13,226			4,557			2,563			2,053			(1,381	)		21,018
Equity in losses of unconsolidated affiliates		(91	)		—			—			—			—			(91	)
Operating income (loss)		1,120			886			623			38			(287	)		2,380
Other income and deductions
Interest expense		(301	)		(307	)		(123	)		(111	)		(86	)		(928	)
Other, net		239			39			8			19			41			346
Total other income and deductions		(62	)		(268	)		(115	)		(92	)		(45	)		(582	)
Income (loss) before income taxes		1,058			618			508			(54	)		(332	)		1,798
Income taxes		500			239			127			(23	)		(216	)		627
Net income (loss)		558			379			381			(31	)		(116	)		1,171
Net loss attributable to noncontrolling interests, preferred security dividends and preference stock dividends		(4	)		—			4			11			—			11
Net income (loss) on common stock	$	562		$	379		$	377		$	(42	)	$	(116	)	$	1,160
	Twelve Months Ended December 31, 2011
	Generation			ComEd			PECO			BGE			Other (b)			Exelon Consolidated
Operating revenues	$	10,447		$	6,056		$	3,720		$	—		$	(1,160	)	$	19,063
Operating expenses
Purchased power and fuel		3,589			3,035			1,864			—			(1,221	)		7,267
Operating and maintenance		3,148			1,189			794			—			53			5,184
Depreciation, amortization, accretion and depletion		570			554			202			—			21			1,347
Taxes other than income		264			296			205			—			20			785
Total operating expenses		7,571			5,074			3,065			—			(1,127	)		14,583
Equity in loss of unconsolidated affiliates		(1	)		—			—			—			—			(1	)
Operating income (loss)		2,875			982			655			—			(33	)		4,479
Other income and deductions
Interest expense		(170	)		(345	)		(134	)		—			(77	)		(726	)
Other, net		122			29			14			—			38			203
Total other income and deductions		(48	)		(316	)		(120	)		—			(39	)		(523	)
Income (loss) before income taxes		2,827			666			535			—			(72	)		3,956
Income taxes		1,056			250			146			—			5			1,457
Net income (loss)		1,771			416			389			—			(77	)		2,499
Preferred security dividends		—			—			4			—			—			4
Net income (loss) on common stock	$	1,771		$	416		$	385		$	—		$	(77	)	$	2,495

(a) Includes financial results for Constellation and BGE beginning on March 12, 2012, the date the merger was completed.

(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)

	Generation
	Three Months Ended December 31,									Twelve Months Ended December 31,
	2012			2011			Variance			2012 (a)			2011			Variance
Operating revenues	$	3,928		$	2,528		$	1,400		$	14,437		$	10,447		$	3,990
Operating expenses
Purchased power and fuel		2,043			794			1,249			7,061			3,589			3,472
Operating and maintenance		1,272			842			430			5,028			3,148			1,880
Depreciation, amortization, accretion and depletion		204			154			50			768			570			198
Taxes other than income		97			65			32			369			264			105
Total operating expenses		3,616			1,855			1,761			13,226			7,571			5,655
Equity in earnings (losses) of unconsolidated affiliates		(22	)		(1	)		(21	)		(91	)		(1	)		(90	)
Operating income		290			672			(382	)		1,120			2,875			(1,755	)
Other income and deductions
Interest expense		(78	)		(43	)		(35	)		(301	)		(170	)		(131	)
Other, net		54			135			(81	)		239			122			117
Total other income and deductions		(24	)		92			(116	)		(62	)		(48	)		(14	)
Income before income taxes		266			764			(498	)		1,058			2,827			(1,769	)
Income taxes		127			318			(191	)		500			1,056			(556	)
Net income		139			446			(307	)		558			1,771			(1,213	)
Net loss attributable to noncontrolling interests		2			—			2			(4	)		—			(4	)
Net income on common stock	$	137		$	446		$	(309	)	$	562		$	1,771		$	(1,209	)

(a) Includes financial results for Constellation beginning on March 12, 2012, the date the merger was completed.

	ComEd
	Three Months Ended December 31,									Twelve Months Ended December 31,
	2012			2011			Variance			2012			2011			Variance
Operating revenues	$	1,289		$	1,362		$	(73	)	$	5,443		$	6,056		$	(613	)
Operating expenses
Purchased power		421			599			(178	)		2,307			3,035			(728	)
Operating and maintenance		345			258			87			1,345			1,189			156
Depreciation and amortization		152			149			3			610			554			56
Taxes other than income		71			71			—			295			296			(1	)
Total operating expenses		989			1,077			(88	)		4,557			5,074			(517	)
Operating income		300			285			15			886			982			(96	)
Other income and deductions
Interest expense		(77	)		(87	)		10			(307	)		(345	)		38
Other, net		27			4			23			39			29			10
Total other income and deductions		(50	)		(83	)		33			(268	)		(316	)		48
Income before income taxes		250			202			48			618			666			(48	)
Income taxes		90			81			9			239			250			(11	)
Net income	$	160		$	121		$	39		$	379		$	416		$	(37	)

3

EXELON CORPORATION

Business Segment Comparative Statements of Operations

(unaudited)

(in millions)

	PECO
	Three Months Ended December 31,									Twelve Months Ended December 31,
	2012			2011			Variance			2012			2011			Variance
Operating revenues	$	790		$	778		$	12		$	3,186		$	3,720		$	(534	)
Operating expenses
Purchased power and fuel		342			358			(16	)		1,375			1,864			(489	)
Operating and maintenance		235			196			39			809			794			15
Depreciation and amortization		56			53			3			217			202			15
Taxes other than income		40			40			—			162			205			(43	)
Total operating expenses		673			647			26			2,563			3,065			(502	)
Operating income		117			131			(14	)		623			655			(32	)
Other income and deductions
Interest expense		(30	)		(32	)		2			(123	)		(134	)		11
Other, net		2			2			—			8			14			(6	)
Total other income and deductions		(28	)		(30	)		2			(115	)		(120	)		5
Income before income taxes		89			101			(12	)		508			535			(27	)
Income taxes		9			27			(18	)		127			146			(19	)
Net income		80			74			6			381			389			(8	)
Preferred security dividends		1			1			—			4			4			—
Net income on common stock	$	79		$	73		$	6		$	377		$	385		$	(8	)
	BGE
	Three Months Ended December 31,									March 12, 2012 through December 31,
	2012			2011			Variance			2012			2011			Variance
Operating revenues	$	703		$	—		$	703		$	2,091		$	—		$	2,091
Operating expenses
Purchased power and fuel		326			—			326			1,052			—			1,052
Operating and maintenance		171			—			171			596			—			596
Depreciation and amortization		80			—			80			238			—			238
Taxes other than income		65			—			65			167			—			167
Total operating expenses		642			—			642			2,053			—			2,053
Operating income		61			—			61			38			—			38
Other income and deductions
Interest expense		(34	)		—			(34	)		(111	)		—			(111	)
Other, net		5			—			5			19			—			19
Total other income and deductions		(29	)		—			(29	)		(92	)		—			(92	)
Income (loss) before income taxes		32			—			32			(54	)		—			(54	)
Income taxes		14			—			14			(23	)		—			(23	)
Net income (loss)		18			—			18			(31	)		—			(31	)
Preference stock dividends		3			—			3			11			—			11
Net income (loss) on common stock	$	15		$	—		$	15		$	(42	)	$	—		$	(42	)

4

EXELON CORPORATION

Business Segment Comparative Statements of Operations

(unaudited)

(in millions)

	Other (a)
	Three Months Ended December 31,									Twelve Months Ended December 31,
	2012			2011			Variance			2012 (b)			2011			Variance
Operating revenues	$	(426	)	$	(310	)	$	(116	)	$	(1,668	)	$	(1,160	)	$	(508	)
Operating expenses
Purchased power and fuel		(373	)		(320	)		(53	)		(1,638	)		(1,221	)		(417	)
Operating and maintenance		(11	)		26			(37	)		183			53			130
Depreciation and amortization		13			4			9			48			21			27
Taxes other than income		9			7			2			26			20			6
Total operating expenses		(362	)		(283	)		(79	)		(1,381	)		(1,127	)		(254	)
Operating income (loss)		(64	)		(27	)		(37	)		(287	)		(33	)		(254	)
Other income and deductions
Interest expense		(12	)		(19	)		7			(86	)		(77	)		(9	)
Other, net		5			9			(4	)		41			38			3
Total other income and deductions		(7	)		(10	)		3			(45	)		(39	)		(6	)
Income (loss) before income taxes		(71	)		(37	)		(34	)		(332	)		(72	)		(260	)
Income taxes		(58	)		(3	)		(55	)		(216	)		5			(221	)
Net loss	$	(13	)	$	(34	)	$	21		$	(116	)	$	(77	)	$	(39	)

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

(b) Includes financial results for Constellation and BGE beginning on March 12, 2012, the date the merger was completed.

5

EXELON CORPORATION

Consolidated Balance Sheets

(unaudited)

(in millions)

	December 31, 2012 (a)			December 31, 2011
ASSETS
Current assets
Cash and cash equivalents	$	1,411		$	1,016
Cash and cash equivalents of variable interest entities		75			—
Restricted cash and investments		86			40
Restricted cash and investments of variable interest entities		47			—
Accounts receivable, net
Customer		2,787			1,613
Other		1,107			1,000
Accounts receivable, net, variable interest entities		292			—
Mark-to-market derivative assets		879			432
Unamortized energy contract assets		886			16
Inventories, net
Fossil fuel		246			208
Materials and supplies		768			656
Deferred income taxes		210			—
Regulatory assets		759			390
Other		561			342
Total current assets		10,114			5,713
Property, plant and equipment, net		45,149			32,570
Deferred debits and other assets
Regulatory assets		6,497			4,518
Nuclear decommissioning trust (NDT) funds		7,248			6,507
Investments		1,184			751
Investments in affiliates		22			15
Investment in CENG		1,849			—
Goodwill		2,625			2,625
Mark-to-market derivative assets		968			650
Unamortized energy contract assets		1,073			424
Pledged assets for Zion Station decommissioning		614			734
Deferred income taxes		634			—
Other		1,128			488
Total deferred debits and other assets		23,842			16,712
Total assets	$	79,105		$	54,995
Liabilities and shareholders’ equity
Current liabilities
Short-term borrowings	$	—		$	163
Short-term notes payable - accounts receivable agreement		210			225
Long-term debt due within one year		975			828
Long-term debt due within one year of variable interest entities		72			—
Accounts payable		2,446			1,444
Accounts payable of variable interest entities		202			—
Mark-to-market derivative liabilities		293			112
Unamortized energy contract liabilities		455			—
Accrued expenses		1,854			1,255
Deferred income taxes		57			1
Regulatory liabilities		321			197
Dividends payable		4			349
Other		888			560
Total current liabilities		7,777			5,134
Long-term debt		17,192			11,799
Long-term debt to financing trusts		648			390
Long-term debt of variable interest entity		506			—
Deferred credits and other liabilities
Deferred income taxes and unamortized investment tax credits		12,139			8,253
Asset retirement obligations		5,074			3,884
Pension obligations		3,428			2,194
Non-pension postretirement benefit obligations		2,662			2,263
Spent nuclear fuel obligation		1,020			1,019
Regulatory liabilities		3,981			3,627
Mark-to-market derivative liabilities		313			126
Unamortized energy contract liabilities		528			—
Payable for Zion Station decommissioning		432			563
Other		1,625			1,268
Total deferred credits and other liabilities		31,202			23,197
Total liabilities		57,325			40,520
Commitments and contingencies
Preferred securities of subsidiary		87			87
Shareholders’ equity
Common stock		16,610			9,107
Treasury stock, at cost		(2,327	)		(2,327	)
Retained earnings		9,893			10,055
Accumulated other comprehensive loss, net		(2,767	)		(2,450	)
Total shareholders’ equity		21,409			14,385
BGE preference stock not subject to mandatory redemption		193			—
Noncontrolling interest		91			3
Total equity		21,693			14,388
Total liabilities and shareholders’ equity	$	79,105		$	54,995

(a) Includes the financial information of Constellation and BGE.

6

EXELON CORPORATION

Consolidated Statements of Cash Flows

(unaudited)

(in millions)

	Twelve Months Ended December 31,
	2012 (a)			2011
Cash flows from operating activities
Net income	$	1,171		$	2,499
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation, amortization, and accretion, including nuclear fuel and energy contract amortization		4,073			2,316
Loss on sale of three Maryland generating stations		272			—
Deferred income taxes and amortization of investment tax credits		547			1,457
Net fair value changes related to derivatives		(604	)		291
Net realized and unrealized (gains) losses on nuclear decommissioning trust fund investments		(157	)		14
Other non-cash operating activities		1,389			770
Changes in assets and liabilities:
Accounts receivable		113			57
Inventories		26			(58	)
Accounts payable, accrued expenses and other current liabilities		(524	)		(254	)
Option premiums paid, net		(114	)		(3	)
Counterparty collateral received (posted), net		135			(344	)
Income taxes		717			492
Pension and non-pension postretirement benefit contributions		(462	)		(2,360	)
Other assets and liabilities		(450	)		(24	)
Net cash flows provided by operating activities		6,132			4,853
Cash flows from investing activities
Capital expenditures		(5,789	)		(4,042	)
Proceeds from nuclear decommissioning trust fund sales		7,265			6,139
Investment in nuclear decommissioning trust funds		(7,483	)		(6,332	)
Cash acquired from Constellation		964			—
Acquisitions of long lived assets		(21	)		(387	)
Proceeds from sale of three Maryland generating stations		371			—
Proceeds from sales of investments		28			6
Purchases of investments		(13	)		(4	)
Change in restricted cash		(34	)		(3	)
Other investing activities		137			20
Net cash flows used in investing activities		(4,575	)		(4,603	)
Cash flows from financing activities
Payment of accounts receivable agreement		(15	)		—
Changes in short-term debt		(197	)		161
Issuance of long-term debt		2,027			1,199
Retirement of long-term debt		(1,145	)		(789	)
Dividends paid on common stock		(1,716	)		(1,393	)
Proceeds from employee stock plans		72			38
Other financing activities		(113	)		(62	)
Net cash flows used in financing activities		(1,087	)		(846	)
Increase (decrease) in cash and cash equivalents		470			(596	)
Cash and cash equivalents at beginning of period		1,016			1,612
Cash and cash equivalents at end of period	$	1,486		$	1,016

(a) Includes financial results for Constellation and BGE beginning on March 12, 2012, the date the merger was completed.

7

EXELON CORPORATION

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

(unaudited)

(in millions, except per share data)

	Three Months Ended December 31, 2012 (a)									Three Months Ended December 31, 2011
	GAAP (b)			Adjustments			Adjusted Non-GAAP			GAAP (b)			Adjustments			Adjusted Non-GAAP
Operating revenues	$	6,284		$	160	(c),(d),(e)	$	6,444		$	4,358		$	(24	) (c)	$	4,334
Operating expenses
Purchased power and fuel		2,759			66	(c),(d),(e)		2,825			1,431			73	(c),(d)		1,504
Operating and maintenance		2,012			(130	) (c),(f),(g),(h)		1,882			1,322			(43	) (c),(f)		1,279
Depreciation, amortization, accretion and depletion		505			(3	) (c)		502			360			(22	) (c)		338
Taxes other than income		282			(3	) (c)		279			183			—			183
Total operating expenses		5,558			(70	)		5,488			3,296			8			3,304
Equity in earnings of unconsolidated affiliates		(22	)		40	(e)		18			(1	)		—			(1	)
Operating income		704			270			974			1,061			(32	)		1,029
Other income and deductions
Interest expense		(231	)		(5	) (i)		(236	)		(181	)		—			(181	)
Other, net		93			(20	) (c),(f),(j)		73			150			(114	) (j)		36
Total other income and deductions		(138	)		(25	)		(163	)		(31	)		(114	)		(145	)
Income before income taxes		566			245			811			1,030			(146	)		884
Income taxes		182			76	(c),(d),(e),(f),    (g),(h),(i),(j),(k)		258			423			(84	(c),(d),(f),  ) (j),(k)		339
Net income		384			169			553			607			(62	)		545
Net loss attributable to noncontrolling interests, preferred security dividends and preference stock dividends		6			—			6			1			—			1
Net income on common stock	$	378		$	169		$	547		$	606		$	(62	)	$	544
Effective tax rate		32.2	%					31.8	%		41.1	%					38.3	%
Earnings per average common share
Basic	$	0.44		$	0.20		$	0.64		$	0.91		$	(0.09	)	$	0.82
Diluted	$	0.44		$	0.20		$	0.64		$	0.91		$	(0.09	)	$	0.82
Average common shares outstanding
Basic		854						854			664						664
Diluted		857						857			666						666
Effect of adjustments on earnings per average diluted common share recorded in accordance with GAAP:
Plant retirements and divestitures (c)				$	0.05								$	0.01
Mark-to-market impact of economic hedging activities (d)					(0.14	)								(0.07	)
Amortization of commodity contract intangibles (e)					0.24									—
Constellation merger and integration costs (f)					0.05									0.03
Asset retirement obligation (g)					(0.01	)								—
Midwest Generation bankruptcy charges (h)					0.01									—
Amortization of the fair value of certain debt (i)					—									—
Unrealized (gains) losses related to NDT fund investments (j)					—									(0.07	)
Non-cash remeasurement of deferred income taxes (k)					—									0.01
Total adjustments				$	0.20								$	(0.09	)

(a) Includes financial results for Constellation and BGE beginning on March 12, 2012, the date the merger was completed.

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

(c) Adjustment to exclude costs associated with the retirement of fossil generating units, the impacts of the FERC approved reliability-must-run rate schedule and the impact associated with the sale in the fourth quarter of 2012 of three generating stations associated with certain of the regulatory approvals required for the merger.

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

(e) Adjustment to exclude the non-cash amortization of intangible assets, net, related to commodity contracts recorded at fair value at the merger date.

(f) Adjustment to exclude certain costs incurred associated with the merger, including transaction costs, employee-related expenses (e.g. severance, retirement, relocation and retention bonuses) and integration initiatives.

(g) Adjustment to exclude the decrease in Generation’s asset retirement obligation for certain retired fossil-fueled generating stations.

(h) Adjustment to exclude estimated liabilities pursuant to the Midwest Generation bankruptcy.

(i) Adjustment to exclude the non-cash amortization of certain debt recorded at fair value at the merger date expected to be retired in 2013.

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

(k) Adjustment to exclude the non-cash impacts of the remeasurement of state deferred income taxes, primarily as a result of the merger in 2012 and as a result of revised estimates of state apportionments in 2011.

8

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, 2012 (a)									Twelve Months Ended December 31, 2011
	GAAP (b)			Adjustments			Adjusted Non-GAAP			GAAP (b)			Adjustments			Adjusted Non-GAAP
Operating revenues	$	23,489		$	1,185	(c),(d),(e),(f)	$	24,674		$	19,063		$	(66	) (c),(o)	$	18,997
Operating expenses
Purchased power and fuel		10,157			607	(c),(d),(e),(g)		10,764			7,267			(292	) (c),(d)		6,975
Operating and maintenance		7,961			(1,182	(c),(e),(f),(g),  ) (h),(i),(j),(k)		6,779			5,184			(124	(c),(g),(j),(k),  ) (o),(p)		5,060
Depreciation, amortization, accretion and depletion		1,881			(47	) (c),(g)		1,834			1,347			(87	) (c)		1,260
Taxes other than income		1,019			(9	) (c),(f),(g)		1,010			785			(1	) (c)		784
Total operating expenses		21,018			(631	)		20,387			14,583			(504	)		14,079
Equity in earnings (losses) of unconsolidated affiliates		(91	)		150	(e),(g)		59			(1	)		—			(1	)
Operating income		2,380			1,966			4,346			4,479			438			4,917
Other income and deductions
Interest expense		(928	)		(13	) (g),(l)		(941	)		(726	)		—			(726	)
Other, net		346			(94	) (c),(g),(m)		252			203			(21	) (m),(o)		182
Total other income and deductions		(582	)		(107	)		(689	)		(523	)		(21	)		(544	)
Income before income taxes		1,798			1,859			3,657			3,956			417			4,373
Income taxes		627			689	(c),(d),(e),(f),    (g),(h),(i),(j),    (k),(l),(m),(n)		1,316			1,457			149	(c),(d),(g),(j),    (k),(m),(n),    (o),(p)		1,606
Net income on common stock		1,171			1,170			2,341			2,499			268			2,767
Net loss attributable to noncontrolling interests, preferred security dividends and preference stock dividends		11			—			11			4			—			4
Net income	$	1,160		$	1,170		$	2,330		$	2,495		$	268		$	2,763
Effective tax rate		34.9	%					36.0	%		36.8	%					36.7	%
Earnings per average common share
Basic	$	1.42		$	1.43		$	2.85		$	3.76		$	0.41		$	4.17
Diluted	$	1.42		$	1.43		$	2.85		$	3.75		$	0.41		$	4.16
Average common shares outstanding
Basic		816						816			663						663
Diluted		819						819			665						665
Effect of adjustments on earnings per average diluted common share recorded in accordance with GAAP:
Plant retirements and divestitures (c)				$	0.29								$	0.05
Mark-to-market impact of economic hedging activities (d)					(0.38	)								0.27
Amortization of commodity contract intangibles (e)					0.93									—
Maryland commitments (f)					0.28									—
Constellation merger and integration costs (g)					0.31									0.07
Midwest Generation bankruptcy charges (h)					0.01									—
FERC settlement (i)					0.21									—
Other acquisition costs (j)					—									0.01
Asset retirement obligation (k)					—									0.02
Amortization of the fair value of certain debt (l)					(0.01	)								—
Unrealized (gains) losses related to NDT fund investments (m)					(0.07	)								—
Remeasurement of state deferred income taxes (n)					(0.14	)								0.05
Wolf Hollow acquisition (o)					—									(0.03	)
Recovery of costs pursuant to the 2011 distribution rate case order (p)					—									(0.03	)
Total adjustments				$	1.43								$	0.41

(a) Includes financial results for Constellation Energy including BGE, beginning on March 12, 2012, the date the acquisition was completed.

(b) Results reported in accordance with GAAP.

(c) Adjustment to exclude costs associated with the retirement of fossil generating units, the impacts of the FERC approved reliability-must-run rate schedule and the impact associated with the sale in the fourth quarter of 2012 of three generation stations associated with certain of the regulatory approvals required for the merger.

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

(e) Adjustment to exclude the non-cash amortization of intangible assets, net, related to commodity contracts recorded at fair value at the merger date.

(f) Adjustment to exclude costs incurred as part of the Maryland order approving the merger transaction.

(g) Adjustment to exclude certain activities associated with the merger, including transaction costs, employee-related expenses (e.g. severance, retirement, relocation and retention bonuses) and integration initiatives.

(h) Adjustment to exclude estimated liabilities pursuant to the Midwest Generation bankruptcy.

(i) Adjustment to exclude costs associated with the March 2012 settlement with the FERC.

(j) Adjustment to exclude certain costs associated with various acquisitions.

(k) Adjustment to exclude the increase in Generation’s decommissioning obligation for spent nuclear fuel at retired nuclear units in 2011 and 2012, a decrease in Generation’s asset retirement obligation for certain retired fossil-fueled generating stations in 2012 and a decrease in PECO’s asset retirement obligation in 2011.

(l) Adjustment to exclude the non-cash amortization of certain debt recorded at fair value at the merger date expected to be retired in 2013.

(m) Adjustment to exclude the unrealized losses in 2011 and gains in 2012 associated with Generation’s NDT fund investments and the associated contractual accounting relating to income taxes.

(n) Adjustment to exclude the non-cash impacts of the remeasurement of state deferred income taxes, primarily as a result of the merger in 2012 and as a result of revised estimates of state apportionments in 2011.

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

(p) 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.

9

EXELON CORPORATION (a)

Reconciliation of Adjusted (non-GAAP) Operating

Earnings to GAAP Earnings (in millions)

Three Months Ended December 31, 2012 and 2011

	Exelon Earnings per Diluted Share			Generation			ComEd			PECO			BGE			Other (b)			Exelon
2011 GAAP Earnings (Loss)	$	0.91		$	446		$	121		$	73		$	—		$	(34	)	$	606
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	)
Plant Retirements and Divestitures (2)		0.01			4			—			—			—			—			4
Constellation Merger and Integration Costs (3)		0.03			6			—			1			—			14			21
Non-Cash Remeasurement of Deferred Income Taxes (4)		0.01			(6	)		—			—			—			10			4
2011 Adjusted (non-GAAP) Operating Earnings (Loss)		0.82			359			121			74			—			(10	)		544
Year Over Year Effects on Earnings:
Generation Energy Margins, Excluding Mark-to-Market:
Nuclear Volume		—			(1	)		—			—			—			—			(1	)
Nuclear Fuel Costs (5)		(0.01	)		(12	)		—			—			—			—			(12	)
Capacity Pricing (6)		—			(4	)		—			—			—			—			(4	)
Market and Portfolio Conditions (7)		0.22			188			—			—			—			—			188
Transmission Upgrades (8)		—			19			—			—			—			(19	)		—
ComEd, PECO and BGE Margins:
Weather		0.02			—			1			17			—	(c)		—			18
Load		—			—			1			—			—	(c)		—			1
Other Energy Delivery (9)		0.34			—			61			8			226			—			295
Operating and Maintenance Expense:
Labor, Contracting and Materials (10)		(0.20	)		(115	)		(13	)		3			(46	)		—			(171	)
Planned Nuclear Refueling Outages		0.01			8			—			—			—			—			8
Pension and Non-Pension Postretirement Benefits (11)		(0.04	)		(10	)		(4	)		(3	)		(5	)		(12	)		(34	)
Other Operating and Maintenance (12)		(0.21	)		(90	)		(34	)		(32	)		(49	)		25			(180	)
Depreciation and Amortization Expense (13)		(0.12	)		(42	)		(2	)		(3	)		(48	)		(5	)		(100	)
Equity in Earnings of Unconsolidated Affiliates (14)		0.01			12			—			—			—			—			12
Income Taxes (15)		0.06			8			11			16			(1	)		20			54
Interest Expense, Net (16)		(0.03	)		(24	)		17			1			(20	)		2			(24	)
Other		(0.05	)		(13	)		3			—			(39	)		2			(47	)
Share Differential (17)		(0.18	)		—			—			—			—			—			—
2012 Adjusted (non-GAAP) Operating Earnings		0.64			283			162			81			18			3			547
2012 Adjusted (non-GAAP) Operating Earnings (Loss) Adjustments:
Mark-to-Market Impact of Economic Hedging Activities		0.14			145			—			—			—			(22	)		123
Unrealized Gains Related to NDT Fund Investments (1)		—			2			—			—			—			—			2
Plant Retirements and Divestitures (2)		(0.05	)		(38	)		—			—			—			—			(38	)
Constellation Merger and Integration Costs (3)		(0.05	)		(35	)		(2	)		(2	)		(3	)		(4	)		(46	)
Non-Cash Remeasurement of Deferred Income Taxes (4)		—			(9	)		—			—			—			10			1
Amortization of Commodity Contract Intangibles (18)		(0.24	)		(211	)		—			—			—			—			(211	)
Amortization of the Fair Value of Certain Debt (19)		—			3			—			—			—			—			3
Asset Retirement Obligation (20)		0.01			5			—			—			—			—			5
Midwest Generation Bankruptcy Charges (21)		(0.01	)		(8	)		—			—			—			—			(8	)
2012 GAAP Earnings (Loss)	$	0.44		$	137		$	160		$	79		$	15		$	(13	)	$	378

(a) For the three months ended December 31, 2012, includes financial results for Constellation and BGE. Therefore, the results of operations from 2012 and 2011 are not comparable for Generation, BGE, Other and Exelon. The explanations below identify any other significant or unusual items affecting the results of operations.

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

(c) As approved by the Maryland PSC, BGE records a monthly adjustment to rates for residential and the majority of its commercial and industrial customers to eliminate the effect of abnormal weather and usage patterns per customer on distribution volumes.

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

(2) For 2012, primarily reflects the impact associated with the sale of three generating stations associated with certain of the regulatory approvals required for the merger. For 2011, primarily reflects incremental accelerated depreciation associated with the retirement of four fossil generating units and compensation for operating two of the units past their planned retirement date under a FERC-approved reliability-must-run rate schedule.

(3) Reflects certain costs incurred associated with the merger, including transaction costs, employee-related expenses (e.g. severance, retirement, relocation and retention bonuses) and integration initiatives.

(4) Reflects the non-cash impacts of the remeasurement of state deferred income taxes, primarily as a result of the merger in 2012 and as a result of revised estimates of state apportionments in 2011.

(5) Primarily reflects the impact of higher nuclear fuel prices during the amortization period, excluding CENG.

(6) Primarily reflects the impact of decreased capacity prices related to the Reliability Pricing Model (RPM) for the PJM Interconnection, LLC (PJM) market, partially offset by the addition of Constellation’s financial results in 2012.

(7) Primarily reflects the addition of Constellation’s financial results in 2012, partially offset by the impact of decreased realized market prices for the sale of energy in the Mid-Atlantic and Midwest regions.

(8) For Generation, reflects intercompany expense in 2011 and PJM bill credits in 2012 related to upgrades in transmission assets owned by ComEd, which are reflected as assets at Exelon Corporate.

(9) For ComEd, primarily reflects the impacts of the October 2012 rehearing order issued by the ICC related to ComEd’s recovery of pension asset costs associated with the formula rate proceeding under EIMA. For ComEd, also reflects recovery of increased costs and capital investment, net of lower allowed return on equity, pursuant to the formula rate under EIMA, and recovery of increased costs and capital investment pursuant to the FERC approved transmission formula rate. For PECO, primarily reflects increased cost recovery for regulatory required programs (partially offset in operating and maintenance expense, depreciation expense and income taxes).

(10) Primarily reflects the addition of Constellation and BGE’s financial results in 2012 and the impacts of increased wages and other benefits and increased contracting expenses (exclusive of planned nuclear refueling outages and incremental storm costs). At ComEd, primarily reflects increased contracting expenses on new projects related to EIMA. At PECO, primarily reflects a decrease in contracting expenses.

(11) The increase in pension and OPEB costs primarily reflects the impact of lower actuarially assumed discount rates and expected return on assets for 2012 as compared to 2011.

(12) Primarily reflects the addition of Constellation and BGE’s financial results in 2012 and the impact of higher storm costs in the PECO and BGE service territories. For ComEd, primarily reflects a credit in 2011 for the allowed recovery of certain storm costs pursuant to EIMA, partially offset by a 2011 one-time contribution by ComEd also pursuant to EIMA.

(13) Primarily reflects the addition of Constellation and BGE’s financial results in 2012, increased depreciation expense across the operating companies for ongoing capital expenditures and the non-cash amortization of intangible assets at Generation primarily related to the trade name and retail relationships recorded at fair value at the merger date.

(14) Primarily reflects equity in earnings in CENG, partially offset by the non-cash amortization of the fair value basis difference recorded at the merger date.

(15) At Generation, primarily reflects changes in state income tax rates. At ComEd, primarily reflects a benefit related to the final 1999-2001 IRS settlement (offset at Generation) and a favorable remeasurement of Illinois state deferred taxes. At PECO, primarily reflects a benefit for the gas property repairs deduction.

(16) Primarily reflects the addition of Constellation and BGE’s financial results in 2012. For Generation and BGE, also reflects the impact of higher interest expense due to higher outstanding debt during 2012. For ComEd, primarily reflects lower interest expense related to the 1999-2001 IRS settlement, lower outstanding debt during 2012 and lower interest rates on long-term debt.

(17) Reflects the impact on earnings per share due to the increase in Exelon’s average diluted common shares outstanding as a result of the merger.

(18) Represents the non-cash amortization of intangible assets, net, related to commodity contracts recorded at fair value at the merger date.

(19) Represents the non-cash amortization of certain debt recorded at fair value at the merger date expected to be retired in 2013.

(20) Reflects a decrease in Generation’s asset retirement obligation for certain retired fossil-fueled generating stations.

(21) For Generation, reflects estimated liabilities pursuant to the Midwest Generation bankruptcy.

10

EXELON CORPORATION (a)

Reconciliation of Adjusted (non-GAAP) Operating

Earnings to GAAP Earnings (in millions)

Twelve Months Ended December 31, 2012 and 2011

	Exelon Earnings per Diluted Share			Generation			ComEd			PECO			BGE			Other (b)			Exelon
2011 GAAP Earnings (Loss)	$	3.75		$	1,771		$	416		$	385		$	—		$	(77	)	$	2,495
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
Plant Retirements and Divestitures (2)		0.05			33			—			—			—			—			33
Asset Retirement Obligation (3)		0.02			18			—			(2	)		—			—			16
Recovery of Costs Pursuant to the 2011 Distribution Rate Case Order (4)		(0.03	)		—			(17	)		—			—			—			(17	)
Constellation Merger and Integration Costs (5)		0.07			8			—			1			—			37			46
Other Acquisition Costs		0.01			5			—			—			—			—			5
Wolf Hollow Acquisition (6)		(0.03	)		(23	)		—			—			—			—			(23	)
Non-Cash Remeasurement of Deferred Income Taxes (7)		0.05			15			4			—			—			14			33
2011 Adjusted (non-GAAP) Operating Earnings (Loss) Year Over Year Effects on Earnings:		4.16			2,002			403			384			—			(26	)		2,763
Generation Energy Margins, Excluding Mark-to-Market:
Nuclear Volume		—			—			—			—			—			—			—
Nuclear Fuel Costs (8)		(0.07	)		(56	)		—			—			—			—			(56	)
Capacity Pricing (9)		(0.13	)		(105	)		—			—			—			—			(105	)
Market and Portfolio Conditions (10)		0.71			581			—			—			—			—			581
Transmission Upgrades (11)		—			53			—			—			—			(53	)		—
ComEd, PECO and BGE Margins:
Weather		(0.03	)		—			1			(23	)		—	(c)		—			(22	)
Load		(0.02	)		—			(2	)		(16	)		—	(c)		—			(18	)
Other Energy Delivery (12)		0.95			—			81			6			691			—			778
Discrete Impacts of the 2011 Distribution Rate Case Order (13)		(0.03	)		—			(21	)		—			—			—			(21	)
Operating and Maintenance Expense:
Labor, Contracting and Materials (14)		(0.79	)		(439	)		(56	)		21			(175	)		—			(649	)
Planned Nuclear Refueling Outages (15)		0.03			27			—			—			—			—			27
Pension and Non-Pension Postretirement Benefits (16)		(0.13	)		(34	)		(24	)		(9	)		(19	)		(21	)		(107	)
Other Operating and Maintenance (17)		(0.38	)		(224	)		9			(9	)		(141	)		45			(320	)
Depreciation and Amortization Expense (18)		(0.43	)		(150	)		(34	)		(11	)		(143	)		(15	)		(353	)
2011 Nuclear Decommissioning Trust Fund Special Transfer (19)		(0.06	)		(46	)		—			—			—			—			(46	)
Equity in Earnings of Unconsolidated Affiliates (20)		0.05			38			—			—			—			—			38
Income Taxes (21)		0.06			8			(3	)		9			1			36			51
Interest Expense, Net (22)		(0.14	)		(88	)		25			7			(61	)		2			(115	)
Other (23)		(0.12	)		(19	)		2			28			(107	)		—			(96	)
Share Differential (24)		(0.78	)		—			—			—			—			—			—
2012 Adjusted (non-GAAP) Operating Earnings (Loss) 2012 Adjusted (non-GAAP) Operating Earnings (Loss) Adjustments:		2.85			1,548			381			387			46			(32	)		2,330
Mark-to-Market Impact of Economic Hedging Activities		0.38			312			—			—			—			(2	)		310
Unrealized Gains Related to NDT Fund Investments (1)		0.07			56			—			—			—			—			56
Plant Retirements and Divestitures (2)		(0.29	)		(236	)		—			—			—			—			(236	)
Asset Retirement Obligation (3)		—			(1	)		—			—			—			—			(1	)
Constellation Merger and Integration Costs (5)		(0.31	)		(167	)		(2	)		(10	)		(5	)		(73	)		(257	)
Non-Cash Remeasurement of Deferred Income Taxes (7)		0.14			4			—			—			—			113			117
Maryland Commitments (25)		(0.28	)		(22	)		—			—			(83	)		(122	)		(227	)
Amortization of Commodity Contract Intangibles (26)		(0.93	)		(758	)		—			—			—			—			(758	)
FERC Settlement (27)		(0.21	)		(172	)		—			—			—			—			(172	)
Amortization of the Fair Value of Certain Debt (28)		0.01			9			—			—			—			—			9
Other Acquisition Costs		—			(3	)		—			—			—			—			(3	)
Midwest Generation Bankruptcy Charges (29)		(0.01	)		(8	)		—			—			—			—			(8	)
2012 GAAP Earnings (Loss)	$	1.42		$	562		$	379		$	377		$	(42	)	$	(116	)	$	1,160

(a) For the twelve months ended December 31, 2012, includes financial results for Constellation and BGE beginning on March 12, 2012, the date the merger was completed. Therefore, the results of operations from 2012 and 2011 are not comparable for Generation, BGE, Other and Exelon. The explanations below identify any other significant or unusual items affecting the results of operations.

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

(c) As approved by the Maryland PSC, BGE records a monthly adjustment to rates for residential and the majority of its commercial and industrial customers to eliminate the effect of abnormal weather and usage patterns per customer on distribution volumes.

(1) Reflects the impact of unrealized losses in 2011 and unrealized gains in 2012 on NDT fund investments to the extent not offset by contractual accounting as described in the notes to the consolidated financial statements.

(2) For 2012, primarily reflects the impact associated with the sale of three generating stations associated with certain of the regulatory approvals required for the merger. For 2012 and 2011, also reflects incremental accelerated depreciation associated with the retirement of certain fossil generating units and compensation for operating two of the units past their planned retirement date under a FERC-approved reliability-must-run rate schedule.

(3) For 2011 and 2012, primarily reflects an increase in Generation’s decommissioning obligation for spent nuclear fuel at retired nuclear units. For 2012, also reflects a decrease in Generation’s asset retirement obligation for certain retired fossil-fueled generating stations.

(4) 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.

(5) Reflects certain costs incurred associated with the merger, including transaction costs, employee-related expenses (e.g. severance, retirement, relocation and retention bonuses) and integration initiatives.

(6) Primarily reflects a non-cash bargain purchase gain (negative goodwill) in 2011 in connection with the acquisition of Wolf Hollow, net of acquisition costs.

(7) Reflects the non-cash impacts of the remeasurement of state deferred income taxes, primarily as a result of the merger in 2012 and as a result of revised estimates of state apportionments in 2011.

(8) Primarily reflects the impact of higher nuclear fuel prices during the amortization period, excluding CENG.

(9) Primarily reflects the impact of decreased capacity prices related to the RPM for the PJM market, partially offset by the addition of Constellation’s financial results in 2012.

(10) Primarily reflects the addition of Constellation’s financial results in 2012, partially offset by the impact of decreased realized market prices for the sale of energy in the Mid-Atlantic and Midwest regions.

(11) For Generation, reflects intercompany expense in 2011 and PJM bill credits in 2012 related to upgrades in transmission assets owned by ComEd, which are reflected as assets at Exelon Corporate.

(12) For ComEd, primarily reflects recovery of increased costs and capital investment, net of lower allowed return on equity, pursuant to the formula rate under EIMA, and recovery of increased costs and capital investment pursuant to the FERC approved transmission formula rate.

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

(14) Primarily reflects the addition of Constellation and BGE’s financial results in 2012 and the impacts of increased wages and other benefits and increased contracting expenses (exclusive of planned nuclear refueling outages and incremental storm costs). At ComEd, primarily reflects increased contracting expenses on new projects related to EIMA. At PECO, primarily reflects a decrease in contracting expenses.

(15) Primarily reflects the impact of decreased planned nuclear refueling outage days in 2012, excluding Salem and CENG.

(16) The increase in pension and OPEB costs primarily reflects the impact of lower actuarially assumed discount rates and expected return on assets for 2012 as compared to 2011.

(17) Primarily reflects the addition of Constellation and BGE’s financial results in 2012 and the impact of higher storm costs in the PECO and BGE service territories, partially offset at ComEd by a 2011 one-time contribution pursuant to EIMA.

(18) Primarily reflects the addition of Constellation and BGE’s financial results in 2012, increased depreciation expense across the operating companies for ongoing capital expenditures and the non-cash amortization of intangible assets at Generation primarily related to the trade name and retail relationships recorded at fair value at the merger date.

(19) Reflects one-time interest and tax benefits in 2011 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 related Treasury Regulations.

(20) Primarily reflects equity in earnings in CENG, partially offset by the non-cash amortization of the fair value basis difference recorded at the merger date.

(21) At Generation, primarily reflects a decrease in state income taxes and an increase in investment tax credits, partially offset by a 2012 reduction in manufacturing deduction benefits. At PECO, primarily reflects a benefit for the gas property repairs deduction.

(22) Primarily reflects the addition of Constellation and BGE’s financial results in 2012. In addition, reflects the impact of higher interest expense at Generation and BGE due to higher outstanding debt during 2012, partially offset by the impact of lower interest expense at ComEd and PECO due to lower outstanding debt during 2012 and lower interest rates on long-term debt. For ComEd, also reflects lower interest expense related to the 1999-2001 IRS settlement.

(23) For Generation, primarily reflects the addition of Constellation’s financial results, partially offset by realized NDT fund gains related to changes to the investment strategy and favorable market conditions in 2012. For PECO, primarily reflects decreased gross receipts tax (completely offset by decreased PECO margins) and reduced sales and use tax.

(24) Reflects the impact on earnings per share due to the increase in Exelon’s average diluted common shares outstanding as a result of the merger.

(25) Reflects costs incurred as part of the Maryland order approving the merger transaction.

(26) Represents the non-cash amortization of intangible assets, net, related to commodity contracts recorded at fair value at the merger date.

(27) Reflects costs incurred as part of a March 2012 settlement with the FERC to resolve a dispute related to Constellation’s prior period hedging and risk management transactions.

(28) Represents the non-cash amortization of certain debt recorded at fair value at the merger date expected to be retired in 2013.

(29) For Generation, reflects estimated liabilities pursuant to the Midwest Generation bankruptcy.

11

EXELON CORPORATION

Reconciliation of Adjusted (non-GAAP) Operating Earnings to

GAAP Consolidated Statements of Operations

(unaudited)

(in millions)

	Generation
	Three Months Ended December 31, 2012									Three Months Ended December 31, 2011
	GAAP (b)			Adjustments			Adjusted Non-GAAP			GAAP (b)			Adjustments			Adjusted Non-GAAP
Operating revenues	$	3,928		$	123	(c),(d),(e)	$	4,051		$	2,528		$	(24	) (c)	$	2,504
Operating expenses
Purchased power and fuel		2,043			66	(c),(d),(e)		2,109			794			73	(c),(d)		867
Operating and maintenance		1,272			(111	) (c),(f),(g),(h)		1,161			842			(18	) (c),(f)		824
Depreciation, amortization, accretion and depletion		204			(3	) (c)		201			154			(22	) (c)		132
Taxes other than income		97			(3	) (c)		94			65			—			65
Total operating expenses		3,616			(51	)		3,565			1,855			33			1,888
Equity in earnings of unconsolidated affiliates		(22	)		40	(e)		18			(1	)		—			(1	)
Operating income		290			214			504			672			(57	)		615
Other income and deductions
Interest expense		(78	)		(5	) (i)		(83	)		(43	)		—			(43	)
Other, net		54			(20	) (c),(f),(j)		34			135			(114	) (j)		21
Total other income and deductions		(24	)		(25	)		(49	)		92			(114	)		(22	)
Income before income taxes		266			189			455			764			(171	)		593
Income taxes		127			43	(c),(d),(e),    (f),(g),(h),    (i),(j),(k)		170			318			(84	(c),(d),(f),  ) (j),(k)		234
Net income		139			146			285			446			(87	)		359
Net loss attributable to noncontrolling interests		2			—			2			—			—			—
Net income on common stock	$	137		$	146		$	283		$	446		$	(87	)	$	359
	Twelve Months Ended December 31, 2012 (a)									Twelve Months Ended December 31, 2011
	GAAP (b)			Adjustments			Adjusted Non-GAAP			GAAP (b)			Adjustments			Adjusted Non-GAAP
Operating revenues	$	14,437		$	1,065	(c),(d),(e)	$	15,502		$	10,447		$	(66	) (c),(o)	$	10,381
Operating expenses
Purchased power and fuel		7,061			607	(c),(d),(e),(f)		7,668			3,589			(292	) (c),(d)		3,297
Operating and maintenance		5,028			(889	(c),(e),(f),(g),  ) (h),(l),(m),(n)		4,139			3,148			(77	(c),(f),(g),  ) (l),(o)		3,071
Depreciation, amortization, accretion and depletion		768			(47	) (c),(f)		721			570			(87	) (c)		483
Taxes other than income		369			(11	) (c)		358			264			(1	) (d)		263
Total operating expenses		13,226			(340	)		12,886			7,571			(457	)		7,114
Equity in earnings (losses) of unconsolidated affiliates		(91	)		150	(e),(f)		59			(1	)		—			(1)
Operating income		1,120			1,555			2,675			2,875			391			3,266
Other income and deductions
Interest expense		(301	)		(16	) (i)		(317	)		(170	)		—			(170	)
Other, net		239			(94	) (c),(f),(j)		145			122			(21	) (j),(o)		101
Total other income and deductions		(62	)		(110	)		(172	)		(48	)		(21	)		(69	)
Income before income taxes		1,058			1,445			2,503			2,827			370			3,197
						(c),(d),(e),(f),									(c),(d),(f),
						(g),(h),(i),(j),									(g),(j),(k),
Income taxes		500			459	(k),(l),(m),(n)		959			1,056			139	(l),(o)		1,195
Net income		558			986			1,544			1,771			231			2,002
Net income attributable to noncontrolling interests		(4	)		—			(4	)		—			—			—
Net income on common stock	$	562		$	986		$	1,548		$	1,771		$	231		$	2,002

(a) Includes financial results for Constellation beginning on March 12, 2012, the date the merger was completed.

(b) Results reported in accordance with GAAP.

(c) Adjustment to exclude costs associated with the retirement of fossil generating units, the impacts of the FERC approved reliability-must-run rate schedule and the impact associated with the sale in the fourth quarter of 2012 of three generating stations associated with certain of the regulatory approvals required for the merger.

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

(e) Adjustment to exclude the non-cash amortization of intangible assets, net, related to commodity contracts recorded at fair value at the merger date.

(f) Adjustment to exclude certain costs incurred associated with the merger, including transaction costs, employee-related expenses (e.g. severance, retirement, relocation and retention bonuses) and integration initiatives.

(g) Adjustment to exclude the increase in Generation’s decommissioning obligation for spent nuclear fuel at retired nuclear units in 2011 and 2012, and a decrease in Generation’s asset retirement obligation for certain retired fossil-fueled generating stations in 2012.

(h) Adjustment to exclude estimated liabilities pursuant to the Midwest Generation bankruptcy.

(i) Adjustment to exclude the non-cash amortization of certain debt recorded at fair value at the merger date expected to be retired in 2013.

(j) 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 2012 associated with Generation’s NDT fund investments and the associated contractual accounting relating to income taxes.

(k) Adjustment to exclude the non-cash impacts of the remeasurement of state deferred income taxes, primarily as a result of the merger for 2012 and as a result of revised estimates of state apportionments for 2011.

(l) Adjustment to exclude certain costs associated with various acquisitions.

(m) Adjustment to exclude costs incurred as part of the Maryland order approving the merger transaction.

(n) Adjustment to exclude costs associated with the March 2012 settlement with the FERC.

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

12

EXELON CORPORATION

Reconciliation of Adjusted (non-GAAP) Operating Earnings to

GAAP Consolidated Statements of Operations

(unaudited)

(in millions)

	ComEd
	Three Months Ended December 31, 2012									Three Months Ended December 31, 2011
	GAAP (a)			Adjustments			Adjusted Non- GAAP			GAAP (a)			Adjustments			Adjusted Non- GAAP
Operating revenues	$	1,289		$	—		$	1,289		$	1,362		$	—		$	1,362
Operating expenses
Purchased power		421			—			421			599			—			599
Operating and maintenance		345			(3	)(b)		342			258			—			258
Depreciation and amortization		152			—			152			149			—			149
Taxes other than income		71			—			71			71			—			71
Total operating expenses		989			(3	)		986			1,077			—			1,077
Operating income		300			3			303			285			—			285
Other income and deductions
Interest expense		(77	)		—			(77	)		(87	)		—			(87	)
Other, net		27			—			27			4			—			4
Total other income and deductions		(50	)		—			(50	)		(83	)		—			(83	)
Income before income taxes		250			3			253			202			—			202
Income taxes		90			1	(b)		91			81			—			81
Net income	$	160		$	2		$	162		$	121		$	—		$	121
	Twelve Months Ended December 31, 2012									Twelve Months Ended December 31, 2011
	GAAP (a)			Adjustments			Adjusted Non- GAAP			GAAP (a)			Adjustments			Adjusted Non- GAAP
Operating revenues	$	5,443		$	—		$	5,443		$	6,056		$	—		$	6,056
Operating expenses
Purchased power		2,307			—			2,307			3,035			—			3,035
Operating and maintenance		1,345			(5	)(b)		1,340			1,189			13	(c)		1,202
Depreciation and amortization		610			—			610			554			—			554
Taxes other than income		295			—			295			296			—			296
Total operating expenses		4,557			(5	)		4,552			5,074			13			5,087
Operating income		886			5			891			982			(13	)		969
Other income and deductions
Interest expense		(307	)		—			(307	)		(345	)		—			(345	)
Other, net		39			—			39			29			—			29
Total other income and deductions		(268	)		—			(268	)		(316	)		—			(316	)
Income before income taxes		618			5			623			666			(13	)		653
Income taxes		239			3	(b)		242			250			—	(c),(d)		250
Net income	$	379		$	2		$	381		$	416		$	(13	)	$	403

(a) Results reported in accordance with GAAP.

(b) Adjustment to exclude certain costs incurred associated with the merger, including transaction costs, employee-related expenses (e.g. severance, retirement, relocation and retention bonuses) and integration initiatives.

(c) 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.

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

13

EXELON CORPORATION

Reconciliation of Adjusted (non-GAAP) Operating Earnings to

GAAP Consolidated Statements of Operations

(unaudited)

(in millions)

	PECO
	Three Months Ended December 31, 2012									Three Months Ended December 31, 2011
	GAAP (a)			Adjustments			Adjusted Non- GAAP			GAAP (a)			Adjustments			Adjusted Non- GAAP
Operating revenues	$	790		$	—		$	790		$	778		$	—		$	778
Operating expenses
Purchased power and fuel		342			—			342			358			—			358
Operating and maintenance		235			(4	)(b)		231			196			(1	)(b)		195
Depreciation and amortization		56			—			56			53			—			53
Taxes other than income		40			—			40			40			—			40
Total operating expenses		673			(4	)		669			647			(1	)		646
Operating income		117			4			121			131			1			132
Other income and deductions
Interest expense		(30	)		—			(30	)		(32	)		—			(32	)
Other, net		2			—			2			2			—			2
Total other income and deductions		(28	)		—			(28	)		(30	)		—			(30	)
Income before income taxes		89			4			93			101			1			102
Income taxes		9			2	(b)		11			27			—	(b)		27
Net income		80			2			82			74			1			75
Preferred security dividends		1			—			1			1			—			1
Net income on common stock	$	79		$	2		$	81		$	73		$	1		$	74
	Twelve Months Ended December 31, 2012									Twelve Months Ended December 31, 2011
	GAAP (a)			Adjustments			Adjusted Non- GAAP			GAAP (a)			Adjustments			Adjusted Non- GAAP
Operating revenues	$	3,186		$	—		$	3,186		$	3,720		$	—		$	3,720
Operating expenses
Purchased power and fuel		1,375			—			1,375			1,864			—			1,864
Operating and maintenance		809			(17	)(b)		792			794			1	(b),(c)		795
Depreciation and amortization		217			—			217			202			—			202
Taxes other than income		162			—			162			205			—			205
Total operating expenses		2,563			(17	)		2,546			3,065			1			3,066
Operating income		623			17			640			655			(1	)		654
Other income and deductions
Interest expense		(123	)		—			(123	)		(134	)		—			(134	)
Other, net		8			—			8			14			—			14
Total other income and deductions		(115	)		—			(115	)		(120	)		—			(120	)
Income before income taxes		508			17			525			535			(1	)		534
Income taxes		127			7	(b)		134			146			—	(b),(c)		146
Net income		381			10			391			389			(1	)		388
Preferred security dividends		4			—			4			4			—			4
Net income on common stock	$	377		$	10		$	387		$	385		$	(1	)	$	384

(a) Results reported in accordance with GAAP.

(b) Adjustment to exclude certain costs incurred associated with the merger, including transaction costs, employee-related expenses (e.g. severance, retirement, relocation and retention bonuses) and integration initiatives

(c) Adjustment to exclude a decrease in PECO’s 2011 asset retirement obligation.

14

EXELON CORPORATION

Reconciliation of Adjusted (non-GAAP) Operating Earnings to

GAAP Consolidated Statements of Operations

(unaudited)

(in millions)

	BGE
	Three Months Ended December 31, 2012
	GAAP (a)			Adjustments			Adjusted Non-GAAP
Operating revenues	$	703		$	—		$	703
Operating expenses
Purchased power and fuel		326			—			326
Operating and maintenance		171			(4	)(b)		167
Depreciation and amortization		80			—			80
Taxes other than income		65			—			65
Total operating expenses		642			(4	)		638
Operating income		61			4			65
Other income and deductions
Interest expense		(34	)		—			(34	)
Other, net		5			—			5
Total other income and deductions		(29	)		—			(29	)
Income before income taxes		32			4			36
Income taxes		14			1	(b)		15
Net income		18			3			21
Preference stock dividends		3			—			3
Net income on common stock	$	15		$	3		$	18
	March 12, 2012 through December 31, 2012
	GAAP (a)			Adjustments			Adjusted Non-GAAP
Operating revenues	$	2,091		$	113	(c)	$	2,204
Operating expenses
Purchased power and fuel		1,052			—			1,052
Operating and maintenance		596			(37	)(b),(c)		559
Depreciation and amortization		238			—			238
Taxes other than income		167			2	(c)		169
Total operating expenses		2,053			(35	)		2,018
Operating income		38			148			186
Other income and deductions
Interest expense		(111	)		—			(111	)
Other, net		19			—			19
Total other income and deductions		(92	)		—			(92	)
Income (loss) before income taxes		(54	)		148			94
Income taxes		(23	)		60	(b),(c)		37
Net income (loss)		(31	)		88			57
Preference stock dividends		11			—			11
Net income (loss) on common stock	$	(42	)	$	88		$	46

(a) Results reported in accordance with GAAP.

(b) Adjustment to exclude certain costs incurred associated with the merger, including transaction costs, employee-related expenses (e.g. severance, retirement, relocation and retention bonuses) and integration initiatives.

(c) Adjustment to exclude costs incurred as part of the Maryland order approving the merger transaction.

15

EXELON CORPORATION

Reconciliation of Adjusted (non-GAAP) Operating Earnings to

GAAP Consolidated Statements of Operations

(unaudited)

(in millions)

	Other (a)
	Three Months Ended December 31, 2012 (b)									Three Months Ended December 31, 2011
	GAAP (c)			Adjustments			Adjusted Non- GAAP			GAAP (c)			Adjustments			Adjusted Non- GAAP
Operating revenues	$	(426	)	$	37	(d)	$	(389	)	$	(310	)	$	—		$	(310	)
Operating expenses
Purchased power and fuel		(373	)		—			(373	)		(320	)		—			(320	)
Operating and maintenance		(11	)		(8	)(e)		(19	)		26			(24	)(e)		2
Depreciation and amortization		13			—			13			4			—			4
Taxes other than income		9			—			9			7			—			7
Total operating expenses		(362	)		(8	)		(370	)		(283	)		(24	)		(307	)
Operating loss		(64	)		45			(19	)		(27	)		24			(3	)
Other income and deductions
Interest expense		(12	)		—			(12	)		(19	)		—			(19	)
Other, net		5			—			5			9			—			9
Total other income and deductions		(7	)		—			(7	)		(10	)		—			(10	)
Loss before income taxes		(71	)		45			(26	)		(37	)		24			(13	)
Income taxes		(58	)		29	(d),(e),(f)		(29	)		(3	)		—	(e),(f)		(3	)
Net income (loss)	$	(13	)	$	16		$	3		$	(34	)	$	24		$	(10	)
	Twelve Months Ended December 31, 2012 (b)									Twelve Months Ended December 31, 2011
	GAAP (c)			Adjustments			Adjusted Non- GAAP			GAAP (c)			Adjustments			Adjusted Non- GAAP
Operating revenues	$	(1,668	)	$	7	(d)	$	(1,661	)	$	(1,160	)	$	—		$	(1,160	)
Operating expenses
Purchased power and fuel		(1,638	)		—			(1,638	)		(1,221	)		—			(1,221	)
Operating and maintenance		183			(234	)(e),(g)		(51	)		53			(61	)(e)		(8	)
Depreciation and amortization		48			—			48			21			—			21
Taxes other than income		26			—			26			20			—			20
Total operating expenses		(1,381	)		(234	)		(1,615	)		(1,127	)		(61	)		(1,188	)
Operating income (loss)		(287	)		241			(46	)		(33	)		61			28
Other income and deductions
Interest expense		(86	)		3	(e)		(83	)		(77	)		—			(77	)
Other, net		41			—			41			38			—			38
Total other income and deductions		(45	)		3			(42	)		(39	)		—			(39	)
Loss before income taxes		(332	)		244			(88	)		(72	)		61			(11	)
Income taxes		(216	)		160	(d),(e),(f),(g)		(56	)		5			10	(e),(f)		15
Net loss	$	(116	)	$	84		$	(32	)	$	(77	)	$	51		$	(26	)

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

(b) Includes financial results for Constellation and BGE, beginning on March 12, 2012, the date the merger was completed.

(c) Results reported in accordance with GAAP.

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

(e) Adjustment to exclude certain costs incurred associated with the merger, including transaction costs, employee-related expenses (e.g. severance, retirement, relocation and retention bonuses) and integration initiatives.

(f) Adjustment to exclude the non-cash impacts of the remeasurement of state deferred income taxes, primarily as a result of the merger for 2012 and as a result of revised estimates of state apportionments for 2011.

(g) Adjustment to exclude costs incurred as part of the Maryland order approving the merger transaction.

16

EXELON CORPORATION

Exelon Generation Statistics

	Three Months Ended
	Dec. 31, 2012 (a)			Sep. 30, 2012 (a)		Jun. 30, 2012 (a)		Mar. 31, 2012		Dec. 31, 2011
Supply (in GWhs)
Nuclear Generation (b)
Mid-Atlantic		11,547			11,449		12,277		12,064		11,587
Midwest		23,335			23,132		22,860		23,198		23,306
Total Nuclear Generation		34,882			34,581		35,137		35,262		34,893
Fossil and Renewables (b)
Mid-Atlantic (b)(d)		2,154			2,547		2,316		1,791		1,637
Midwest		300			171		228		272		188
New England		2,368			3,953		2,755		889		—
New York		—			—		—		—		—
ERCOT (e)		755			2,410		2,177		840		457
Other (f)		1,358			1,813		1,923		819		394
Total Fossil and Renewables		6,935			10,894		9,399		4,611		2,676
Purchased Power
Mid-Atlantic (c)		4,332			6,811		7,111		2,577		739
Midwest		2,661			3,035		1,558		2,552		1,143
New England		2,304			1,961		3,905		1,100		—
New York (c)		3,678			4,026		2,818		935		—
ERCOT (e)		6,043			7,741		6,686		2,832		1,150
Other (f)		4,172			5,372		6,012		1,769		482
Total Purchased Power		23,190			28,946		28,090		11,765		3,514
Total Supply/Sales by Region (h)
Mid-Atlantic (g)		18,033			20,807		21,704		16,432		13,963
Midwest (g)		26,296			26,338		24,646		26,022		24,637
New England		4,672			5,914		6,660		1,989		—
New York		3,678			4,026		2,818		935		—
ERCOT		6,798			10,151		8,863		3,672		1,607
Other (f)		5,530			7,185		7,935		2,588		876
Total Supply/Sales by Region		65,007			74,421		72,626		51,638		41,083
	Three Months Ended
	Dec. 31, 2012 (a)			Sep. 30, 2012 (a)		Jun. 30, 2012 (a)		Mar. 31, 2012		Dec. 30, 2011
Average Margin ($/MWh) (i) (j)
Mid-Atlantic (k)	$	48.24		$	43.64	$	40.68	$	46.86	$	56.08
Midwest (k)		26.09			27.68		31.00		31.40		34.18
New England		3.64			13.70		9.01		19.61		n.m.
New York		4.35			3.23		13.84		8.56		n.m.
ERCOT		13.39			15.66		13.43		9.26		(6.02	)
Other (f)		7.96			5.85		4.28		5.41		(4.13	)
Average Margin - Overall Portfolio	$	26.52		$	25.96	$	26.15	$	32.57	$	39.31
Around-the-clock Market Prices ($/MWh) (l)
PJM West Hub	$	35.94		$	38.13	$	30.40	$	31.10	$	35.07
NiHub		28.37			34.29		26.02		27.13		25.97
New England Mass Hub ATC Spark Spread		3.07			12.69		7.77		0.80		6.71
NYPP Zone A		34.70			34.56		27.87		27.18		32.03
ERCOT North Spark Spread		(0.27	)		3.60		6.01		3.46		1.11
	Three Months Ended
	Dec. 31, 2012 (a)			Sep. 30, 2012 (a)		Jun. 30, 2012 (a)		Mar. 31, 2012		Dec. 30, 2011
Outage Days (m)
Refueling		113			43		51		67		103
Non-refueling		1			40		16		16		11
Total Outage Days		114			83		67		83		114

(a) Includes results for Constellation beginning on March 12, 2012, the date the merger was completed.

(b) Includes the proportionate share of output where Generation has an undivided ownership interest in jointly-owned generating plants and does not include ownership through equity method investments (e.g. CENG).

(c) Purchased power includes physical volumes of 3,255 GWhs, 3,126 GWhs, 3,225 GWhs and 319 GWhs in the Mid-Atlantic and 2,814 GWhs, 2,997 GWhs, 2,817 GWhs and 722 GWhs in New York as a result of the PPA with CENG for the three months ended December 31, 2012, September 30, 2012, June 30, 2012 and March 31, 2012, respectively.

(d) Excludes generation under the reliability-must-run rate schedule and generation of Brandon Shores, H.A. Wagner, and C.P. Crane, the generating facilities divested in Q4 2102 as a result of the Exelon and Constellation merger.

(e) Generation from Wolf Hollow is included in purchased power for the period ending June 30, 2011 and through the acquisition date of August 24, 2011, and included within Fossil and Renewables subsequent to the acquisition date.

(f) Other Regions includes South, West and Canada, which are not considered individually significant.

(g) Includes affiliate sales to PECO and BGE in the Mid-Atlantic region and affiliate sales to ComEd in the Midwest region.

(h) Total sales do not include physical proprietary trading volumes of 2,977 GWhs, 4,352 GWhs, 3,873 GWhs, 1,757 GWhs, and 1,235 GWhs for the three months ended December 31, 2012, September 30, 2012, June 30, 2012, March 31, 2012, and December 31, 2011, respectively.

(i) Excludes Generation’s other business activities not allocated to a region, including retail and wholesale gas, upstream natural gas, proprietary trading, energy efficiency, energy management and demand response, and the design, construction and operation of renewable energy facilities. Also excludes Generation’s compensation under the reliability-must-run rate schedule, the financial results of Brandon Shores, H.A. Wagner, and C.P. Crane, the generating facilities divested in Q4 2012 as a result of the merger, amortization of certain intangible assets relating to commodity contracts recorded at fair value as a result of the Exelon and Constellation merger and other miscellaneous revenues not allocated to a region.

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

(k) Includes affiliate sales to PECO and BGE in the Mid-Atlantic region and affiliate sales to ComEd and settlements of the ComEd swap in the Midwest region.

(l) Represents the average for the quarter.

(m) Outage days exclude Salem and CENG.

17

EXELON CORPORATION

Exelon Generation Statistics

Twelve Months Ended December 31, 2012 and 2011

	December 31, 2012 (a)		December 31, 2011
Supply (in GWhs)
Nuclear Generation (b)
Mid-Atlantic		47,337		47,287
Midwest		92,525		92,010
Total Nuclear Generation		139,862		139,297
Fossil and Renewables (b)
Mid-Atlantic (b)(d)		8,808		7,572
Midwest		971		596
New England		9,965		8
ERCOT (e)		6,182		2,030
Other (f)		5,913		1,432
Total Fossil and Renewables		31,839		11,638
Purchased Power
Mid-Atlantic (c)		20,830		2,898
Midwest		9,805		5,970
New England		9,273		—
New York (c)		11,457		—
ERCOT (e)		23,302		7,537
Other (f)		17,327		2,503
Total Purchased Power		91,994		18,908
Total Supply/Sales by Region (h)
Mid-Atlantic (g)		76,975		57,757
Midwest (g)		103,301		98,576
New England		19,238		8
New York		11,457		—
ERCOT		29,484		9,567
Other (f)		23,240		3,935
Total Supply/Sales by Region		263,695		169,843
	December 31, 2012 (a)		December 31, 2011
Average Margin ($/MWh) (i) (j)
Mid-Atlantic (k)	$	44.60	$	58.00
Midwest (k)		29.02		35.99
New England		10.19		n.m.
New York		6.63		n.m.
ERCOT		13.74		8.78
Other (f)		5.64		(3.56	)
Average Margin - Overall Portfolio	$	27.45	$	41.07
Around-the-clock Market Prices ($/MWh) (l)
PJM West Hub	$	33.91	$	43.56
NiHub		28.97		33.07
NEPOOL Mass Hub		6.06		8.71
NYPP Zone A		31.02		36.98
ERCOT North Spark Spread		3.23		11.88

(a) Includes results for Constellation beginning on March 12, 2012, the date the merger was completed.

(b) Includes the proportionate share of output where Generation has an undivided ownership interest in jointly-owned generating plants and does not include ownership through equity method investments (e.g. CENG).

(c) Purchased power includes physical volumes of 9,925 GWhs in the Mid-Atlantic and 9,350 GWhs in New York as a result of the PPA with CENG for the year ended December 31, 2012.

(d) Excludes generation under the reliability-must-run rate schedule and generation of Brandon Shores, H.A. Wagner, and C.P. Crane, the generating facilities divested in Q4 2012 as a result of the Exelon and Constellation merger.

(e) Generation from Wolf Hollow is included in purchased power for the period ending June 30, 2011 and through the acquisition date of August 24, 2011, and included within Fossil and Renewables subsequent to the acquisition date.

(f) Other Regions includes South, West and Canada, which are not considered individually significant.

(g) Includes affiliate sales to PECO and BGE in the Mid-Atlantic region and affiliate sales to ComEd in the Midwest region.

(h) Total sales do not include physical proprietary trading volumes of 12,958 GWhs and 5,742 GWhs for the year ended December 31, 2012 and 2011, respectively.

(i) Excludes Generation’s other business activities not allocated to a region, including retail and wholesale gas, upstream natural gas, proprietary trading, energy efficiency, energy management and demand response, and the design, construction and operation of renewable energy facilities. Also excludes Generation’s compensation under the reliability-must-run rate schedule, the financial results of Brandon Shores, H.A. Wagner, and C.P. Crane, the generating facilities divested in Q4 2012 as a result of the merger, amortization of certain intangible assets relating to commodity contracts recorded at fair value as a result of the Exelon and Constellation merger and other miscellaneous revenues not allocated to a region.

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

(k) Includes affiliate sales to PECO and BGE in the Mid-Atlantic region and affiliate sales to ComEd and settlements of the ComEd swap in the Midwest region.

(l) Represents the average for the quarter.

18

EXELON CORPORATION

ComEd Statistics

	Three Months Ended December 31, 2012 and 2011
	Electric Deliveries (in GWhs)										Revenue (in millions)
								Weather- Normal
	2012		2011		% Change			% Change			2012			2011		% Change
Retail Deliveries and Sales (a)
Residential		6,183		6,166		0.3	%		(1.0	)%	$	665		$	764		(13.0	)%
Small Commercial & Industrial		7,792		7,632		2.1	%		1.8	%		342			340		0.6	%
Large Commercial & Industrial		6,595		6,721		(1.9	)%		(1.6	)%		99			95		4.2	%
Public Authorities & Electric Railroads		340		316		7.6	%		7.0	%		13			12		8.3	%
Total Retail		20,910		20,835		0.4	%		(0.1	)%		1,119			1,211		(7.6	)%
Other Revenue (b)												170			151		12.6	%
Total Electric Revenue											$	1,289		$	1,362		(5.4	)%
Purchased Power											$	421		$	599		(29.7	)%
								% Change
Heating and Cooling Degree-Days	2012		2011		Normal			From 2011			From Normal
Heating Degree-Days		2,030		1,832		2,293			10.8	%		(11.5	)%
Cooling Degree-Days		3		14		11			(78.6	)%		(72.7	)%
	Twelve Months Ended December 31, 2012 and 2011
	Electric Deliveries (in GWhs)										Revenue (in millions)
	2012		2011		% Change			Weather- Normal % Change			2012			2011		% Change
Retail Deliveries and Sales (a)
Residential		28,528		28,273		0.9	%		(0.6	)%	$	3,037		$	3,510		(13.5	)%
Small Commercial & Industrial		32,534		32,281		0.8	%		0.2	%		1,339			1,517		(11.7	)%
Large Commercial & Industrial		27,643		27,732		(0.3	)%		(0.3	)%		395			383		3.1	%
Public Authorities & Electric Railroads		1,272		1,235		3.0	%		4.2	%		44			50		(12.0	)%
Total Retail		89,977		89,521		0.5	%		(0.1	)%		4,815			5,460		(11.8	)%
Other Revenue (b)												628			596		5.4	%
Total Electric Revenue											$	5,443		$	6,056		(10.1	)%
Purchased Power											$	2,307		$	3,035		(24.0	)%
								% Change
Heating and Cooling Degree-Days	2012		2011		Normal			From 2011			From Normal
Heating Degree-Days		5,065		6,134		6,341			(17.4	)%		(20.1	)%
Cooling Degree-Days		1,324		1,036		842			27.8	%		57.2	%
Number of Electric Customers	2012		2011
Residential		3,455,546		3,448,481
Small Commercial & Industrial		365,357		365,824
Large Commercial & Industrial		1,980		2,032
Public Authorities & Electric Railroads		4,812		4,797
Total		3,827,695		3,821,134

(a) Reflects delivery volumes and revenues 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 and transmission.

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

19

EXELON CORPORATION

PECO Statistics

	Three Months Ended December 31, 2012 and 2011
	Electric and Gas Deliveries										Revenue (in millions)
	2012		2011		% Change			Weather- Normal % Change			2012			2011		% Change
Electric (in GWhs)
Retail Deliveries and Sales (a)
Residential		3,079		2,937		4.8	%		0.7	%	$	395		$	392		0.8	%
Small Commercial & Industrial		1,908		1,884		1.3	%		(0.5	)%		105			114		(7.9	)%
Large Commercial & Industrial		3,708		3,665		1.2	%		1.4	%		53			47		12.8	%
Public Authorities & Electric Railroads		229		235		(2.6	)%		(2.6	)%		7			9		(22.2	)%
Total Retail		8,924		8,721		2.3	%		0.6	%		560			562		(0.4	)%
Other Revenue (b)												54			61		(11.5	)%
Total Electric Revenue												614			623		(1.4	)%
Gas (in mmcfs)
Retail Deliveries and Sales
Retail Sales (c)		17,466		15,257		14.5	%		(1.3	)%		165			147		12.2	%
Transportation and Other		7,290		6,776		7.6	%		5.7	%		11			8		37.5	%
Total Gas		24,756		22,033		12.4	%		0.6	%		176			155		13.5	%
Total Electric and Gas Revenues											$	790		$	778		1.5	%
Purchased Power and Fuel											$	342		$	358		(4.5	)%
								% Change
Heating and Cooling Degree-Days	2012		2011		Normal			From 2011			From Normal
Heating Degree-Days		1,482		1,302		1,629			13.8	%		(9.0	)%
Cooling Degree-Days		31		14		19			121.4	%		63.2	%

	Twelve Months Ended December 31, 2012 and 2011
	Electric and Gas Deliveries										Revenue (in millions)
	2012		2011		% Change			Weather- Normal % Change			2012			2011		% Change
Electric (in GWhs)
Retail Deliveries and Sales (a)
Residential		13,233		13,687		(3.3	)%		(1.7	)%	$	1,689		$	1,934		(12.7	)%
Small Commercial & Industrial		8,063		8,321		(3.1	)%		(2.3	)%		462			585		(21.0	)%
Large Commercial & Industrial		15,253		15,677		(2.7	)%		(2.7	)%		232			308		(24.7	)%
Public Authorities & Electric Railroads		943		945		(0.2	)%		(0.2	)%		31			38		(18.4	)%
Total Retail		37,492		38,630		(2.9	)%		(2.2	)%		2,414			2,865		(15.7	)%
Other Revenue (b)												226			244		(7.4	)%
Total Electric Revenue												2,640			3,109		(15.1	)%
Gas (in mmcfs)
Retail Deliveries and Sales
Retail Sales (c)		49,767		54,239		(8.2	)%		(0.1	)%		509			576		(11.6	)%
Transportation and Other		26,687		28,204		(5.4	)%		(4.8	)%		37			35		5.7	%
Total Gas		76,454		82,443		(7.3	)%		(1.6	)%		546			611		(10.6	)%
Total Electric and Gas Revenues											$	3,186		$	3,720		(14.4	)%
Purchased Power and Fuel											$	1,375		$	1,864		(26.2	)%
								% Change
Heating and Cooling Degree-Days	2012		2011		Normal			From 2011			From Normal
Heating Degree-Days		3,747		4,157		4,603			(9.9	)%		(18.6	)%
Cooling Degree-Days		1,603		1,617		1,301			(0.9	)%		23.2	%

Number of Electric Customers	2012		2011		Number of Gas Customers	2012		2011
Residential		1,417,773		1,415,681	Residential		454,502		451,382
Small Commercial & Industrial		148,803		148,570	Commercial & Industrial		41,836		41,373
Large Commercial & Industrial		3,111		3,110	Total Retail		496,338		492,755
Public Authorities & Electric Railroads		9,660		9,689	Transportation		903		879
Total		1,579,347		1,577,050	Total		497,241		493,634

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

(c) Reflects delivery volumes and revenues from customers purchasing natural gas directly from PECO and customers purchasing natural gas from a competitive natural gas supplier as all customers are assessed distribution charges. For customers purchasing natural gas from PECO, revenue also reflects the cost of natural gas.

20

EXELON CORPORATION

BGE Statistics

Three Months Ended December 31, 2012

	Electric and Gas Deliveries		Revenue (in millions)
Electric (in GWhs)
Retail Deliveries and Sales (a)
Residential		3,026	$	314
Small Commercial & Industrial		3,686		136
Large Commercial & Industrial		365		9
Public Authorities & Electric Railroads		80		7
Total Retail		7,157		466
Other Revenue (b)				62
Total Electric Revenue				528
Gas (in mmcfs)
Retail Deliveries and Sales (c)
Retail Sales		26,333		160
Transportation and Other (d)		3,145		15
Total Gas		29,478		175
Total Electric and Gas Revenues			$	703
Purchased Power and Fuel			$	326
Heating and Cooling Degree-Days	2012
Heating Degree-Days		1,616
Cooling Degree-Days		25

March 12, 2012 through December 31, 2012

	Electric and Gas Deliveries		Revenue (in millions)
Electric (in GWhs)
Retail Deliveries and Sales (a)
Residential		10,133	$	996
Small Commercial & Industrial		12,322		463
Large Commercial & Industrial		2,307		50
Public Authorities & Electric Railroads		200		25
Total Retail		24,962		1,534
Other Revenue (b)				200
Total Electric Revenue				1,734
Gas (in mmcfs)
Retail Deliveries and Sales (c)
Retail Sales		57,882		313
Transportation and Other (d)		12,220		44
Total Gas		70,102		357
Total Electric and Gas Revenues			$	2,091
Purchased Power and Fuel			$	1,052
Heating and Cooling Degree-Days	2012
Heating Degree-Days		3,804
Cooling Degree-Days		1,012

As of December 31, 2012

Number of Electric Customers	2012		Number of Gas Customers	2012
Residential		1,116,233	Residential		610,827
Small Commercial & Industrial		119,122	Commercial & Industrial		44,228
Large Commercial & Industrial		5,452	Total Retail		655,055
Public Authorities & Electric Railroads		319	Transportation		—
Total		1,241,126	Total		655,055

(a) Reflects delivery volumes and revenues from customers purchasing electricity directly from BGE and customers electing to receive electric generation service from a competitive electric generation supplier as all customers are assessed distribution charges. For customers purchasing electricity from BGE, revenue also reflects the cost of energy and transmission.

(b) Other revenue includes wholesale transmission revenue and late payment charges.

(c) Reflects delivery volumes and revenues from customers purchasing natural gas directly from BGE and customers purchasing natural gas from a competitive natural gas supplier as all customers are assessed distribution charges. For customers purchasing natural gas from BGE, revenue also reflects the cost of natural gas.

(d) Transportation and other gas revenue includes off-system revenue of 3,145 mmcfs ($14 million) for the three months ended December 31, 2012 and off-system revenue of 12,220 mmcfs ($39 million) from March 12, 2012 through December 31, 2012.

21

EX-99.2

Earnings Conference Call

4   Quarter 2012

February 7

,  2013

th

th

Exhibit 99.2

Cautionary Statements Regarding

Forward-Looking Information

1

2012 4Q Earnings Release Slides

This presentation contains certain forward-looking statements within the meaning of the Private Securities

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

results to differ materially from the forward-looking statements made by Exelon Corporation, Commonwealth

Edison Company, PECO Energy Company, Baltimore Gas and Electric Company and Exelon Generation Company,

LLC (Registrants) include those factors discussed herein, as well as the items discussed in (1)  Exelon’s 2011

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) Constellation Energy Group’s 2011 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;

(3)

the

Registrants’

Third

Quarter

2012

Quarterly

Report on Form 10-Q 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 16; and (4) other factors discussed in filings with the

SEC

by

the

Registrants.

Readers

are

cautioned

not

to

place

undue

reliance

on

these

forward-looking

statements,

which apply only as of the date of this presentation. None of the Registrants undertakes any obligation to

publicly release any revision to its forward-looking statements to reflect events or circumstances after the date

of this presentation.

2012 4Q Earnings Release Slides

•

Realized

$170M

of

O&M

synergies

and

on

track

to

achieve

$550M

in

O&M

synergies starting in 2014

•

Closed on Maryland asset divestitures

related to merger commitments in 4Q

2012

•

ICC re-hearing in October granted

recovery on pension asset; ComEd

appeal ongoing for other disallowed

items

•

Worked with PJM and stakeholders to

propose MOPR modifications

•

Rate case progressing at BGE

•

Exemplary storm restoration efforts at

PECO and BGE in response to

Hurricane Sandy

•

2012 nuclear capacity factor of

92.7%

•

Q4 2012 operating EPS of $0.64 per

share

(1)

•

2012 operating EPS of $2.85 per

share

(1)

in line with expectations

•

Challenging power market conditions

2012 4Q Earnings Release Slides

2

2012 In Review

2013 Expectations:

•

Expect

to

deliver

full-year

2013

operating

earnings

within

guidance

range

of

$2.35

-

$2.65/share

(1)

•

Expect

1Q

2013

operating

earnings

within

guidance

range

of

$0.60

-

$0.70/share

(1)

•

Strengthen

credit

metrics

and

balance

sheet

•

Complete

remaining

integration

activities,

primarily

IT

related

Regulatory

Process

Financial

Summary

Merger

Execution

Operating

Excellence

(1)

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

Exelon’s Revised Dividend

•

Continue to believe in $3-$6/MWh

upside in PJM but timing of upside is

difficult to predict

•

Expected heat rate upside from coal

retirements not yet reflected in forward

prices

2012 4Q Earnings Release Slides

3

Power market upside has not yet materialized

Sizing dividend to align with business mix

•

Continue to pay a healthy, sustainable

dividend

•

Provide balance sheet strength to remain

investment-grade through stressed

commodity cycles

•

Provide capacity to invest in growth

•

Provide flexibility to hedging to better

align with market liquidity

Sustainable dividend of $1.24/share on an annualized basis

$0.31

Starting in 2Q 2013

1Q 2013

$0.525

Dividend rate change beginning in 2Q 2013

Dividend per

share payable

on March 8,

2013 to

holders as of

February 19,

2013

Quarterly

dividend

per share

rate

beginning

2Q 2013

(1)

(1)

Dividend declaration is subject to Board of Directors approval.

$44.00

$42.00

$40.00

$38.00

$36.00

$34.00

$32.00

$30.00

2/1/2013

1/1/2013

12/1/2012

11/1/2012

10/1/2012

2015 PJM-W

2015 NiHub

$32.41

$32.66

$39.87

$41.28

Presence across the entire energy value chain

Unique Combination of Scale, Scope and Flexibility to Invest

Across The Value Chain with Metrics Oriented Operational Model

Operational

Excellence

Regulatory

Advocacy

Disciplined Growth

& Investment

Financial

Discipline

Leverage platform to create value through core competencies

2012 4Q Earnings Release Slides

4

Upstream Gas

Downstream Gas

(Pipelines and

Storage)

Wolf Hollow

Navasota

Boston Gen

Nuclear Uprates

AVSR1

~750 MW of John

Deere Wind

Greater than 500

MW of organic build

Smart Grid

Chicago West

Loop Transmission

MX Energy

StarTex

Demand

Response

Energy Efficiency

Rooftop solar

Available cash to be opportunistically invested across the value

chain in

sustainable growth

Track record of successful investment

Fuels

Conventional

Generation

Renewable

Generation

Electric &

Gas Utilities

Retail

Beyond The

Meter

Sizing Exelon’s Dividend to Fit the Business Model

Financial Priorities

#1: Remain

investment grade

•

Maintain key credit metrics above target ranges under both market and

stress conditions to maintain investment grade ratings

•

Shareholder value of maintaining investment grade:

•

Increases ability to participate in commercial business opportunities

•

Lowers collateral requirements

•

Reliable and cost efficient access to the capital markets

•

Increases business and financial flexibility

#2: Creating value for

shareholders

(less)

(less)

equals

Cash from Operations

Base CapEx / Nuclear Fuel

Dividend

Available Cash and Balance Sheet Capacity

Use remaining cash flow and capacity to invest in

growth and return value to shareholders

5

2012 4Q Earnings Release Slides

Dividend sized to satisfy key financial priorities under a range

of market outcomes

2012 4Q Earnings Release Slides

6

Dividend Policy

Enables

Exelon

and

its

operating

companies

to

maintain

investment

grade

credit

ratings

Is

sustainable

through

all

points

in

the

commodity

cycle,

particularly

the

stress

cases

Is

supported

and

funded

by

cash

flows

from

both

the

regulated

utilities

and

unregulated

business

Provides

room

to

grow

the

company

through

investments

in

value-enhancing

growth

opportunities

Provides

opportunities

to

grow

the

dividend

over

time,

supported

largely

by

investments

and

associated

growth

in

the

earnings

power

of

the

regulated

utilities

(subject

to

Board

discretion)

Allows

for

a

competitive

value

proposition

that,

coupled

with

earnings

growth,

delivers

compelling

shareholder returns over time   

(1)

Free cash flow defined as Cash from Operations less Capex and Dividend.

2012 4Q Earnings Release Slides

Stress Scenario Considerations

Dividend Sizing Objectives

•

Constant $3/mmbtu natural gas

o

Power prices at or below those experienced

during August 2012

•

Commercial and new business risks

•

Other one-time significant financial or

operational risks

•

Utilities: Long-term payout target of 65-70%,

which is in-line with regulated utility peers

•

ExGen:

o

Credit metrics supportive of mid to high BBB

rating

o

Free Cash Flow positive

(1)

2013 Operating Earnings Guidance

Key Year-over-Year Drivers

•

2012 Stub Earnings: $0.12

•

Lower ExGen RNF primarily due to

prices, offset by non-power revenue,

capacity revenue and growth projects:

$(0.27)

•

Higher ComEd RNF primarily from DST

revenues due to formula rate: $0.05

•

Higher BGE RNF: $0.06

•

Higher O&M primarily at ExGen driven by

inflation, pension, and non-power cost of

sales, offset by synergies: $(0.10)

•

Higher depreciation primarily at ExGen

due to new projects placed in service:

$(0.08)

•

Share dilution

(3)

: $(0.13)

7

2012 4Q Earnings Release Slides

PECO

BGE

ExGen

ComEd

PECO

BGE

2013 Guidance

$2.35 -

$2.65

(2)

$1.40 -

$1.60

$0.35 -

$0.45

$0.35 -

$0.45

$0.15 -

$0.25

HoldCo

ExGen

ComEd

2012 Actual

$2.85

(1)

1.89

$0.47

$0.47

$0.06

(1)

2012 results include Constellation Energy and BGE earnings for March 12 – December 31. Based on expected 2012 average outstanding shares of 819M.Refer to

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

(2)

2013 earnings guidance based on expected average outstanding shares of 860M. Earnings guidance for OpCos may not add up to consolidated EPS guidance.

(3)

Shares Outstanding (diluted) are 819M in 2012 and 860M in 2013. 2013 represents full-year of shares outstanding resulting from March 2012 merger with

Constellation.

8

Exelon Generation: Gross Margin Update

December 31, 2012

September 30, 2012

Gross Margin Category ($M)

(1) (2)

2013

2014

2015

2013

2014

2015

Open Gross Margin

(3)

(including South, West, Canada hedged gross margin)

$5,550

$5,900

$6,050

$5,750

$6,050

$6,200

Mark-to-Market of Hedges

(3,4)

$1,650

$650

$300

$1,350

$500

$250

Power New Business / To Go

$400

$650

$850

$500

$750

$950

Non-Power Margins Executed

$200

$100

$50

$150

$100

$50

Non-Power New Business / To Go

$400

$500

$550

$450

$500

$550

Total Gross Margin

$8,200

$7,800

$7,800

$8,200

$7,900

$8,000

Key Highlights of 4Q 2012

•

Forward

power

markets

experienced

further

downward

pressure

during

the

4

quarter

–

Forward

power

prices

still

do

not

reflect

the

upside

that

we

are

forecasting

–

Continue

to

optimize

our

hedging

of

the

portfolio

by

falling

behind

ratable

in

the

Midwest

and

utilizing

cross-commodity and option hedges

•

Power New Business To-Go has been lowered by a combination of executing on targets and

further reductions to our retail load volumes and margins, the result of heightened competition

and low market volatility

2012 4Q Earnings Release Slides

1)

Gross margin rounded to nearest $50M.

2)

Gross margin does not include revenue related to decommissioning, gross receipts tax,

Exelon Nuclear Partners and entities consolidated solely as a result of the application of

FIN 46R.

3)

Includes CENG Joint Venture.

4)

Mark to Market of Hedges assumes mid-point of hedge percentages.

th

9

2013 Cash Flow Summary

•

Expect Cash from Operations of ~$6.0B in 2013

–

Includes $550M for pension/OPEB contribution

•

CapEx in line with estimates provided at 2012 EEI Conference

–

Higher nuclear fuel CapEx of $75M in 2013 related to discounted buying

opportunity accelerated from 2014

–

ExGen CapEx includes ~$350M of Fukushima-

related costs for 2013-2017.

Does not include estimate of $15 -

20 million per unit for filtered vents at

eleven mark 1 and 2 units, if required.

•

Financing plan for utilities comprised of debt refinancing

•

ExGen financing plan includes retirement of $450M hybrid security, DOE

loan draws for AVSR1 and project financing for existing wind assets

2012 4Q Earnings Release Slides

10

Exelon Generation Disclosures

December 31, 2012

2012 4Q Earnings Release Slides

11

Portfolio Management Strategy

Protect Balance Sheet

Ensure Earnings Stability

Create Value

Exercising Market Views

Purely ratable

Actual hedge %

Market views on timing, product

allocation and regional spreads

reflected in actual hedge %

High End of Profit

Low End of Profit

% Hedged

Open Generation

with LT Contracts

Portfolio Management &

Optimization

Portfolio Management Over Time

Align Hedging & Financials

Establishing Minimum Hedge Targets

2012 4Q Earnings Release Slides

Strategic Policy Alignment

•Aligns hedging program with

financial policies and financial

outlook

•Establish minimum hedge targets

to meet financial objectives of the

company (dividend, credit rating)

•Hedge enough commodity risk to

meet future cash requirements

under a stress scenario

Three-Year Ratable Hedging

•Ensure stability in near-term cash

flows and earnings

•Disciplined approach to hedging

•Tenor aligns with customer

preferences and market liquidity

•Multiple channels to market that

allow us to maximize margins

•Large open position in outer years

to benefit from price upside

Bull / Bear Program

Ability to exercise fundamental

market views to create value within

the ratable framework

•Modified timing of hedges versus

purely ratable

•Cross-commodity hedging (heat

rate positions, options, etc.)

•Delivery locations, regional and

zonal spread relationships

Credit Rating

Capital &

Operating

Expenditure

Dividend

Capital

Structure

•

12

Components of Gross Margin Categories

Margins move from new business to MtM of hedges over

the course of the year as sales are executed

Margins move from “Non power new business”

to

“Non power executed”

over the course of the year

Gross margin linked to power production and sales

Gross margin from

other business activities

2012 4Q Earnings Release Slides

Open Gross

Margin

•Generation Gross

Margin at current

market prices,

including capacity

& ancillary

revenues, nuclear

fuel amortization

and fossils fuels

expense

•Exploration and

Production

•PPA Costs &

Revenues

•Provided at a

consolidated level

for all regions

(includes hedged

gross margin for

South, West &

Canada

(1)

)

MtM of

Hedges

(2)

•MtM

of power,

capacity and

ancillary hedges,

including cross

commodity, retail

and wholesale load

transactions

•Provided directly at

a consolidated

level for five major

regions. Provided

indirectly for each

of the five major

regions via EREP,

reference price,

hedge %, expected

generation

“Power”

New

Business

•Retail, Wholesale

planned electric

sales

•Portfolio

Management new

business

•Mid marketing new

business

“Non Power”

Executed

•Retail, Wholesale 

executed gas sales

•Load Response

•Energy Efficiency

•BGE Home

•Distributed Solar

“Non Power”

New Business

•Retail, Wholesale

planned gas sales

•Load Response

•Energy Efficiency

•BGE Home

•Distributed Solar

•Portfolio

Management /

origination fuels

new business

•Proprietary

trading

(3)

(1) Hedged gross margins for South, West & Canada region will be included with Open Gross Margin, and no expected generation, hedge %, EREP or reference prices provided for this region.

(2) MtM of hedges provided directly for the five larger regions. MtM of hedges is not provided directly at the regional level but can be easily estimated using EREP, reference price and hedged MWh.

(3) Proprietary trading gross margins will remain within “Non Power” New Business category and not move to “Non Power” Executed category.

13

ExGen Disclosures 

Gross Margin Category ($M)

(1,2)

2013

2014

2015

Open Gross Margin

(including South, West & Canada hedged GM)

(3)

$5,550

$5,900

$6,050

Mark to Market of Hedges

(3,4)

$1,650

$650

$300

Power New Business / To Go

$400

$650

$850

Non-Power Margins Executed

$200

$100

$50

Non-Power New Business / To Go

$400

$500

$550

Total Gross Margin

$8,200

$7,800

$7,800

2012 4Q Earnings Release Slides

(1)

Gross margin does not include revenue related to decommissioning, gross receipt

tax, Exelon Nuclear Partners and entities consolidated solely as a result of the

application of FIN 46R.

(2)

Gross margin rounded to nearest $50M.

(3)

Includes CENG Joint Venture.

(4)

Mark to Market of Hedges assumes mid-point of hedge percentages.

(5)

Based on December 31, 2012 market conditions.

Reference Prices

(5)

2013

2014

2015

Henry Hub Natural Gas ($/MMbtu)

$3.54

$4.03

$4.23

Midwest: NiHub ATC prices ($/MWh)

$30.12

$30.94

$31.87

Mid-Atlantic: PJM-W ATC prices ($/MWh)

$36.88

$38.00

$39.17

ERCOT-N ATC Spark Spread ($/MWh)

HSC Gas, 7.2HR, $2.50 VOM

$6.80

$7.82

$8.05

New York: NY Zone A ($/MWh)

$34.22

$34.96

$35.66

New England: Mass Hub ATC Spark Spread($/MWh)

ALQN Gas, 7.5HR, $0.50 VOM

$4.61

$3.46

$3.18

14

ExGen Disclosures

Generation and Hedges

2013

2014

2015

Exp. Gen (GWh)

(1)

218,000

211,100

207,300

Midwest

97,500

97,400

97,000

Mid-Atlantic

(2)

74,900

72,300

70,600

ERCOT

17,400

16,600

16,600

New York

(2)

14,000

11,000

9,300

New England

14,200

13,800

13,800

% of Expected Generation Hedged

(3)

94-97%

62-65%

27-30%

Midwest

92-95%

61-64%

25-28%

Mid-Atlantic

(2)

97-100%

66-69%

33-36%

ERCOT

90-93%

67-70%

36-39%

New York

(2)

92-95%

57-60%

23-26%

New England

92-95%

53-56%

12-15%

Effective Realized Energy Price ($/MWh)

(4)

Midwest

$38.50

$35.50

$35.00

Mid-Atlantic

(2)

$48.00

$46.00

$48.50

ERCOT

(5)

$10.00

$6.50

$5.50

New York

(2)

$35.00

$35.00

$47.50

New England

(5)

$7.00

$4.50

$3.50

2012 4Q Earnings Release Slides

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

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

assumes 12 refueling outages in 2013 and 14 refueling outages in 2014 and 2015 at Exelon-operated nuclear plants ,Salem  and CENG.  Expected generation assumes capacity factors of 

93.5%, 93.8%, and 93.3% in 2013, 2014 and 2015 at Exelon-operated nuclear plants excluding Salem and CENG. These estimates of expected generation in 2013, 2014 and 2015 do not

represent guidance or a forecast of future results as Exelon has not completed its planning or optimization processes for those years. (2) Includes CENG Joint Venture. (3) Percent of expected

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

expected value on options. (4) 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. (5) Spark spreads shown for ERCOT and New England.

15

ExGen Hedged Gross Margin Sensitivities

Gross Margin Sensitivities (With Existing Hedges) 

(1, 2)

2013

2014

2015

Henry Hub Natural Gas ($/Mmbtu)

$10

$305

$590

$(15)

$(230)

$(520)

NiHub ATC Energy Price

$30

$245

$410

$(30)

$(240)

$(410)

PJM-W ATC Energy Price

$15

$130

$260

$0

$(125)

$(250)

NYPP Zone A ATC Energy Price

$5

$25

$35

$(5)

$(25)

$(35)

Nuclear Capacity Factor

(3)

+/-

$40

+/-

$45

+/-

$45

2012 4Q Earnings Release Slides

+ $1/Mmbtu

+ $5/MWh

-

$5/MWh

+ $5/MWh

-

$5/MWh

+ $5/MWh

-

$5/MWh

+/-

1%

-

$1/Mmbtu

2012 4Q Earnings Release Slides

(1) Based on December 31, 2012 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.  (2) Sensitivities based on commodity exposure which includes open

generation and all committed transactions.  (3) Includes CENG Joint Venture.

16

Exelon Generation Hedged Gross Margin Upside/Risk

2015

$9,700

2014

$8,650

2013

$8,450

2012 4Q Earnings Release Slides

2012 4Q Earnings Release Slides

Note: Due to a clerical error, the top end of the 2015 Exelon Generation Hedge Gross Margin shown in the graph on slide 20 of the 3rd Quarter 2012 Earnings Conference Call presentation

dated November 1, 2012 should have been $10,350M, and is comparable to the $9,700M value in the chart above.  No other values or estimates in the 3rd Quarter 2012 presentation were

impacted as a result of this error.

(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 2014 and 2015 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,

2012 (2) Gross Margin Upside/Risk based on commodity exposure which includes open generation and all committed transactions.

$7,050

$6,000

$6,500

$7,000

$7,500

$8,000

$8,500

$9,000

$9,500

$10,000

$7,900

$6,300

17

Illustrative Example of Modeling Exelon Generation             

2014 Gross Margin

Row

Item

Midwest

Mid-

Atlantic

ERCOT

New

England

New York

South,

West &

Canada

(A)

Start with fleet-wide open gross margin 

$5.9 billion

(B)

Expected Generation (TWh)

97.4

72.3

16.6

13.8

11.0

(C)

Hedge % (assuming mid-point of range)

62.5%

67.5%

68.5%

54.5%

58.5%

(D=B*C)

Hedged Volume (TWh)

60.9

48.8

11.4

7.5

6.4

(E)

Effective Realized Energy Price ($/MWh)

$35.50

$46.00

$6.50

$4.50

$35.00

(F)

Reference Price ($/MWh)

$30.94

$38.00

$7.82

$3.46

$34.96

(G=E-F)

Difference ($/MWh)

$4.56

$8.00

($1.32)

$1.04

$0.04

(H=D*G)

Mark-to-market value of hedges  ($ million)  

$280 million

$390 million

($15) million

$10 million

$0 million

(I=A+H)

Hedged Gross Margin ($ million)

$6,550 million

(J)

Power New Business / To Go ($ million)

$650 million

(K)

Non-Power Margins Executed ($ million)

$100 million

(L)

Non-

Power New Business / To Go ($ million)

$500 million

(N=I+J+K+L)

Total Gross Margin

$7,800 million

(1) Mark-to-market rounded to the nearest $5 million. 

2012 4Q Earnings Release Slides

2012 4Q Earnings Release Slides

(1)

18

Additional Disclosures

December 31, 2012

2012 4Q Earnings Release Slides

2012 4Q Earnings Release Slides

Operating O&M Forecast

•

2013 O&M forecast of $6.9B

–

Includes merger synergies of $355M

–

Excludes costs to achieve which are considered non-operating

•

Expect O&M CAGR of ~0.5% for 2013-2015

$375

2013E

$6,900

(2)

-$75

$4,425

$1,200

$700

$650

2012 Actuals

$6,775

(1) (2)

-$50

$4,050

$1,150

$700

$550

(in $M)

ExGen

ComEd

ComEd

PECO

PECO

BGE

Corp

~0.5% CAGR for 2013-2015

ExGen

BGE

Stub O&M

19

Key Year-over-Year Drivers

•

Merger synergies:

$185M

•

PECO and BGE Storm

Costs:     $80M

•

Inflation:     $150M

•

Pension/OPEB:     $25M

•

ExGen Non-Power Costs,

offset in RNF:     $70M

•

Other ExGen O&M:     $55M

•

Other Utilities O&M, including

BGE Reliability and ComEd

EIMA:     $90M

2012 4Q Earnings Release Slides

(1)

O&M for 2012 includes CEG and BGE costs from merger close date.

(2)

O&M for utilities excludes regulatory O&M that are P&L neutral. ExGen O&M excludes P&L neutral decommissioning  costs and the impact from 

O&M related to entities consolidated solely as a result of the application of FIN 46R.

Capital Expenditure Expectations

275

225

25

100

100

100

50

25

75

100

950

975

175

2013

2,850

1,025

1,000

575

2015

2,500

1,000

975

225

2014

2,275

2012

(1)

3,700

950

1,150

650

600

Base Capex

(3)

Nuclear Fuel

(2)

MD Commitments

Wind

Solar

Upstream Gas

Nuclear Uprates

325

2014

2,575

1,450

525

225

375

2013

2,650

1,425

625

200

2015

2,750

1,550

650

225

400

2012

(1)

2,200

1,425

375

200

200

Electric Distribution

Electric Transmission

Gas Delivery

Smart Grid/Smart Meter

(in $M)

(in $M)

20

2012 4Q Earnings Release Slides

Exelon Utilities

Exelon Generation

(1)

2012 CapEx includes CEG and BGE from merger close date.

(2)

Nuclear fuel is at ownership and includes Salem.

(3)

ExGen base capex includes $350 million of Fukushima response costs for 2013-2017.  Does not include estimate of $15-20 million per unit, at eleven 

Mark 1 and 2 units, cost for filtered vents, if required.

2013 Projected Sources and Uses of Cash

(1)

Exelon beginning cash balance as of  12/31/12. Excludes counterparty collateral activity.

(2)

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

capital expenditures. 

(3)

Dividends are subject to declaration by the Board of Directors.

(4)

Excludes PECO’s $210 million Accounts Receivable (A/R) Agreement with Bank of Tokyo. PECO’s A/R Agreement was extended in accordance with its

terms through August 30, 2013.

(5)

“Other”

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

(6)

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

($ in millions)

2012 4Q Earnings Release Slides

21

Beginning Cash Balance

(1)

$1,575

Cash Flow from Operations

(2)

550

1,225

625

3,600

5,950

CapEx (excluding other items below):

(550)

(1,300)

(400)

(1,025)

(3,325)

Nuclear Fuel

n/a

n/a

n/a

(1,000)

(1,000)

Dividend

(3)

(1,250)

Nuclear Uprates

n/a

n/a

n/a

(225)

(225)

Wind

n/a

n/a

n/a

--

0

Solar

n/a

n/a

n/a

(575)

(575)

Upstream

n/a

n/a

n/a

(25)

(25)

Utility Smart Grid/Smart Meter

(125)

(100)

(175)

n/a

(400)

Net Financing (excluding Dividend):

Debt Issuances

(4)

350

250

250

--

850

Debt Retirements

(400)

(250)

(300)

(450)

(1,400)

Project Finance/Federal Financing Bank

Loan

n/a

n/a

n/a

1,000

1,000

Other

(5)

75

275

--

--

400

Ending Cash Balance

(1)

$1,575

(6)

ExGen Operating EPS Bridge 2012 to 2013

($0.39) Lower Generation RNF primarily due to

prices as well as lower retail unit margins, offset by

growth projects

$0.06 Non-power revenue

$0.05 Capacity revenue

$0.11 Primarily ITC and PTC tax credits

($0.03) 2012 decommissioning realized gains due

to rebalancing

($0.08) Share Dilution

$1.96

$1.89

$0.07

2013

$1.40-$1.60

Other

($0.01)

Interest

$0.00

Depreciation &

Amortization

($0.08)

O&M

($0.10)

RNF

($0.27)

2012

Stub

22

2012 4Q Earnings Release Slides

Note: Drivers add up to mid-point of 2013 EPS range.

RNF = Revenue Net Fuel

(1) Financials exclude P&L neutral items (including decommissioning  costs, gross receipts tax and entities consolidated solely as a result of the application of FIN 46R).

(2) Shares Outstanding (diluted) are 819M in 2012 and 860M in 2013. 2013 represents full-year of shares outstanding resulting from March 2012 merger with Constellation.

($0.07) Inflation

($0.05) Higher cost of sales related to non-power revenue

($0.02) Pension and OPEB

($0.05) Other

$0.09   Synergies

($0.08) Primarily new wind projects, portions of AVSR

and other assets in service

2013

Other

Depreciation &

Amortization

O&M

(1)

($0.03)

RNF

$0.05

2012

ComEd Operating EPS Bridge 2012 to 2013

$0.07    DST Revenue primarily 

due to formula rate

($0.02)  Weather

($0.02)  Depreciation Expense

($0.02)  Share Dilution

(2)

$0.35

-

$0.45

Interest

($0.02)   EIMA O&M

($0.02)   Inflation

$0.02    Synergies

23

2012 4Q Earnings Release Slides

$0.47

Note: Drivers add up to mid-point of 2013 EPS range.

RNF = Revenue Net Fuel

(1) Financials exclude regulatory items that are P&L neutral.

(2) Shares Outstanding (diluted) are 819M in 2012 and 860M in 2013. 2013 represents full-year of shares outstanding resulting from March 2012 merger with Constellation.

($0.01) Effective Tax Rate Change

($0.02)

($0.05)

($0.02)

$0.47

2013

$0.35 -

$0.45

Other

($0.09)

Interest

$0.01

O&M

$0.01

RNF

$0.00

2012

PECO Operating EPS Bridge 2012 to 2013

$0.02   Weather

($0.01)  Load Growth/Customer mix

($0.01)  Transmission

$0.01 Storm

$0.01 Synergies

($0.01) Inflation

($0.03)  Electric and Gas Tax Repairs

($0.02)  Share Dilution

(2)

($0.01)  Taxes Other Than Income in 2012

($0.01)  Other Effective Tax Rate Change

24

2012 4Q Earnings Release Slides

Note: Drivers add up to mid-point of 2013 EPS range.

RNF = Revenue Net Fuel

(1) Financials exclude regulatory items that are P&L neutral.

(2)

Shares

Outstanding

(diluted)

are

819M

in

2012

and

860M

in

2013.

2013

represents

full-year

of

shares

outstanding

resulting

from

March

2012

merger

with

Constellation.

2012 4Q Earnings Release Slides

Depreciation &

Amortization

0.01

O&M

0.02

RNF

0.06

2012

$0.11

$0.06

Stub: $0.05

2013

$0.15-

$0.25

Other

0.00

BGE Operating EPS Bridge 2012 to 2013

($0.01) PSC Mandated Reliability Spend

($0.01) Inflation

$0.04  Storm

$0.01  Synergies

($0.01) Share Dilution

(2)

$0.01 Other including  tax rate

changes

$0.06 Higher RNF

25

2012 4Q Earnings Release Slides

2012 4Q Earnings Release Slides

Note: Drivers add up to mid-point of 2013 EPS range.

RNF = Revenue Net Fuel

(1) Financials exclude regulatory items that are P&L neutral.

(2)

Shares

Outstanding

(diluted)

are

819M

in

2012

and

860M

in

2013.

2013

represents

full-year

of

shares

outstanding

resulting

from

March

2012

merger

with

Constellation.

ComEd Load Trends

4Q13

3Q13

2Q13

1Q13

4Q12

3Q12

2Q12

1Q12

Gross Metro Product

Residential

Large C&I

All Customer Classes

Notes: C&I = Commercial & Industrial. ComEd load activity impacts net income to the extent that it does not result in an ROE outside of the collar, which ensures that the earned

ROE is within 0.5% of the allowed ROE.

Weather-Normalized Electric Load Year-over-Year

Key Economic Indicators

Weather-Normalized Electric Load

(1)

Source:  U.S. Dept. of Labor (December 2012) and Illinois Department of

Security (December 2012)

(2)

Source: Global Insight (November 2012)

(3)

Not adjusted for leap year

Chicago

U.S.

Unemployment rate

(1)

8.9%

2012 annualized growth in

gross domestic/metro product

(2)

1.8%

26

2012 4Q Earnings Release Slides

4Q12

2012

(3)

2013E

(3)

Average Customer Growth

0.3%

0.3%

0.4%

Average Use-Per-Customer

(1.3)%

(0.9)%

(1.7)%

Total Residential

(1.0)%

(0.6)%

(1.2)%

Small C&I

1.8%

0.2%

(0.5)%

Large C&I

(1.6)%

(0.3)%

1.6%

All Customer Classes

(0.1)%

(0.1)%

(0.0)%

-3%

-2%

-1%

0%

1%

2%

3%

2.1%

7.8%

27

PECO Load Trends

-5%

-4%

-3%

-2%

-1%

0%

1%

2%

3%

4Q13

3Q13

2Q13

1Q13

4Q12

3Q12

2Q12

1Q12

Gross Metro Product

Residential

Large C&I

All Customer Classes

Note: C&I = Commercial & Industrial.

Weather-Normalized Electric Load Year-over-Year

Key Economic Indicators

Weather-Normalized Electric Load

(1)

Source:

U.S.

Dept.

of

Labor

(December

2012)

-

US

US

Dept

of

Labor

prelim.

data

(October

2012)

-

Philadelphia

(2)

Source: Global Insight (November 2012)

(3)

4Q12 LCI does not include 64 GWh for a change in prior period

estimates.

(4)

Not adjusted for leap year

Philadelphia

U.S.

Unemployment rate

(1)

8.0%

2012 annualized growth in

gross domestic/metro product

(2)

1.9%                    2.1%

2012 4Q Earnings Release Slides

4Q12

(3)

2012

(4)

2013E

(4)

Average Customer Growth

0.2%

0.3%

0.2%

Average Use-Per-Customer

0.5%

(2.0)%

(0.7)%

Total Residential

0.7%

(1.7)%

(0.5)%

Small C&I

(0.5)%

(2.3)%

(1.3)%

Large C&I

(0.3)%

(2.7)%

(0.1)%

All Customer Classes

(0.1)%

(2.2)%

(0.5)%

7.8%

28

BGE Load Trends

-5%

-4%

-3%

-2%

-1%

0%

1%

2%

3%

4Q13

3Q13

2Q13

1Q13

4Q12

3Q12

2Q12

1Q12

Gross Metro Product

Residential

Large C&I

All Customer Classes

Weather-Normalized Electric Load Year-over-Year

Key Economic Indicators

Weather-Normalized Electric Load

(1)

Source:

U.S.

Dept.

of

Labor

(December

2012)

-

US

US

Dept

of

Labor

prelim.

data

(November

2012)

-

Baltimore

(2)

Source:

Global

Insight

(November

2012)

(3)

Not

adjusted

for

leap

year

Baltimore

U.S.

Unemployment rate

(1)

6.8%

2012 annualized growth in

gross domestic/metro product

(2)

1.4%                    2.1%

2012 4Q Earnings Release Slides

4Q12

2012

(3)

2013E

(3)

Average Customer Growth

0.0%

0.0%

0.6%

Average Use-Per-Customer

(1.9)%

(3.4)%

(2.3)%

Total Residential

(1.9)%

(3.4)%

(1.7)%

Small C&I

(0.6)%

(3.0)%

(1.1)%

Large C&I

2.1%

1.5%

1.2%

All Customer Classes

(3.3)%

(2.2)%

(1.7)%

7.8%

Note: C&I = Commercial & Industrial.   2012 quarterly and full year data is adjusted for timing of PJM settlements. Impact of RG Steel is only reflected in “All Customer Classes” and

not in “Large C&I” amounts. 

29

Additional 2013 ExGen and CENG Modeling

P&L Item

2013 Estimate

ExGen

Model

Inputs

(1)

O&M

$4,425M

Taxes Other Than Income (TOTI)

$300M

Depreciation & Amortization

(4)

$825M

Interest Expense

$375M

CENG

Model

Inputs

(at

ownership)

(5)

Gross Margin

Included in ExGen Disclosures

O&M / TOTI

$400M-$450M

Depreciation & Amortization / Accretion

$100M-$150M

2012 4Q Earnings Release Slides

2012 4Q Earnings Release Slides

(1)

ExGen amounts  for O&M, TOTI and Depreciation & Amortization exclude the impacts of CENG. CENG impact is reflected in “Equity earnings of unconsolidated affiliates”

in the Income Statement.

(2)

ExGen O&M excludes P&L neutral decommissioning costs and the impact from O&M related to entities consolidated solely as a result of the application of FIN 46R.

(3)

TOTI excludes gross receipts tax for retail.

(4)

ExGen Depreciation & Amortization excludes the impact of P&L neutral decommissioning.

(5)

CENG has not concluded its financial planning process for 2013. The CENG model inputs are intended to support ExGen’s guidance range and do not represent CENG’s

final estimates.

(3)

(2)

2013 Key Assumptions

Utility Statistics

2013 Estimate

Electric Delivery Growth (%)

(3)

ComEd

(0.0)%

PECO

(0.5)%

BGE

(1.7)%

Effective Tax Rate -

Operating (%)

2013 Estimate

ComEd

40.0%

PECO

31.0%

BGE

38.7%

ExGen

33.4%

Exelon

34.4%

30

(1)

Excludes Salem and CENG.

(2)

Reflects forward market prices as of December 31, 2012.

(3)

Weather-normalized load growth.

(4)

O&M rounded to the nearest $25M.

(5)

ExGen O&M excludes P&L neutral decommissioning  costs and the impact from O&M related to entities consolidated solely as a result of the application of FIN 46R.

.

Generation Statistics

2013 Estimate

(2)

Nuclear Capacity Factor (%)

(1)

93.5%

Total Expected Generation(GWh)

218,000

Henry Hub Natural Gas ($/MMbtu)

$3.54

Midwest: NiHub ATC Price

$30.12

Mid-Atlantic: PJM-W ATC Price

$36.88

ERCOT-N ATC Spark Spread

$6.80

New York: NY Zone A ATC Price

$34.22

New England: Mass Hub Spark Spread

$4.61

2013 O&M

(4)

Reconciliation (in $M)

ExGen

ComEd

PECO

BGE

Other

Exelon

GAAP O&M

$4,550

$1,400

$825

$650

$(75)

$7,350

Decommissioning and FIN 46R O&M

(5)

$(50)

-

-

-

-

$(50)

Regulatory O&M

-

$(200)

$(125)

-

-

$(325)

Merger/Integration costs

$(75)

-

-

-

-

$(75)

Operating O&M (as shown on slide 19)

$4,425

$1,200

$700

$650

$(75)

$6,900

2012 4Q Earnings Release Slides

2012 4Q Earnings Release Slides

Sufficient Liquidity

(1)

Excludes commitments from Exelon’s Community and Minority Bank Credit Facility.

(2)

Available Capacity Under Facilities represents the unused 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.

($ in Millions)

Available Capacity Under Bank Facilities as of January 30, 2013

Exelon Corp, ExGen, PECO and BGE facilities were amended and extended on August 10, 2012

to align maturities of  facilities and secure liquidity and pricing through 2017

31

2012 4Q Earnings Release Slides

Aggregate Bank Commitments

(1)

600

1,000

600

5,675

8,375

Outstanding Facility Draws

–

–

–

–

Outstanding Letters of Credit

(1)

(1,729)

(1,732)

Available Capacity Under Facilities

(2)

600

1,000

599

3,946

6,643

Outstanding Commercial Paper

Available Capacity Less Outstanding

Commercial Paper

600

1,000

599

3,946

6,643

–

–

–

–

–

–

–

–

ComEd Operating EPS Contribution

Key

Drivers

–

4Q12

vs.

4Q11

(1)

Share differential: $(0.04)

Impact of the 2011 allowed recovery of certain

storm costs pursuant to EIMA

(2):

: $(0.04)

Lower distribution revenue primarily due to

lower allowed ROE

(3):

$(0.02)

Lower income tax: $0.01

Lower interest expense primarily due to the

settlement of the 1999-2001 income tax

returns: $0.02

Other impacts of EIMA, primarily related to the

2012 ICC rehearing order for the allowed

recovery of pension asset costs: $0.07

4Q12

Heating Degree-Days

1,832       2,030       2,293

Cooling Degree-Days              14

3            11       

4Q11

Full Year

4Q

2012

2011

32

2012 4Q Earnings Release Slides

2012 4Q Earnings Release Slides

(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)

The Energy Infrastructure Modernization Act.

(3)

Due to the true-up mechanism in the distribution formula rate, the primary driver of year-over-year change in earnings will be due to changes in the allowed ROE,

rate base and capital structure. 

$0.61

$0.18

$0.47

$0.19

Normal

Actual

Actual

PECO Operating EPS Contribution

Key

Drivers

–

4Q12

vs.

4Q11

(1)

Increased storm costs: $(0.04)

Share differential: $(0.02)

Weather: $0.02

Lower income tax primarily due to gas

distribution tax repairs deduction: $0.02

4Q12

Heating Degree-Days      1,302         1,482        1,629

Cooling Degree-Days           14 

31             19         

4Q11

33

2012 4Q Earnings Release Slides

Full Year

4Q

2012

2011

2012 4Q Earnings Release Slides

(1)

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

$0.58

$0.11

$0.47

$0.09

Normal

Actual

Actual

4Q GAAP EPS Reconciliation

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

2012 4Q Earnings Release Slides

34

Three Months Ended December 31, 2012

ExGen

ComEd

PECO

BGE

Other

Exelon

2012 Adjusted (non-GAAP) Operating Earnings Per Share

$0.33

$0.19

$0.09

$0.02

$0.00

$0.64

Mark-to-market impact of economic hedging activities

0.17

-

-

-

(0.03)

0.14

Plant retirements and divestitures

(0.05)

-

-

-

-

(0.05)

Asset retirement obligation

0.01

-

-

-

-

0.01

Constellation merger and integration costs

(0.04)

(0.00)

(0.00)

(0.00)

(0.00)

(0.05)

Amortization of commodity contract intangibles

(0.24)

-

-

-

-

(0.24)

Non-cash remeasurement of deferred income taxes

(0.01)

-

-

-

0.01

0.00

Midwest Generation bankruptcy charges

(0.01)

-

-

-

-

(0.01)

4Q 2012 GAAP Earnings (Loss) Per Share

$0.16

$0.19

$0.09

$0.02

$(0.02)

$0.44

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 impact of economic hedging activities

0.07

-

-

-

0.07

Unrealized gains related to nuclear decommissioning trust funds

0.07

-

-

-

0.07

Plant retirements and divestitures

(0.01)

-

-

-

(0.01)

Constellation merger and integration 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

Full Year GAAP EPS Reconciliation

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

2012 4Q Earnings Release Slides

35

Twelve Months Ended December 31, 2012

ExGen

ComEd

PECO

BGE

Other

Exelon

2012 Adjusted (non-GAAP) Operating Earnings (Loss) Per Share

$1.89

$0.47

$0.47

$0.06

$(0.04)

$2.85

Mark-to-market impact of economic hedging activities

0.38

-

-

-

0.00

0.38

Unrealized gains related to nuclear decommissioning trust funds

0.07

-

-

-

-

0.07

Plant retirements and divestitures

(0.29)

-

-

-

-

(0.29)

Constellation merger and integration costs

(0.20)

(0.00)

(0.01)

(0.01)

(0.09)

(0.31)

Maryland commitments

(0.03)

-

-

(0.10)

(0.15)

(0.28)

Amortization of commodity contract intangibles

(0.93)

-

-

-

-

(0.93)

FERC settlement

(0.21)

-

-

-

-

(0.21)

Reassessment of state deferred income taxes

0.00

-

-

-

0.14

0.14

Amortization of the fair value of certain debt

0.01

-

-

-

-

0.01

Midwest Generation bankruptcy charges

(0.01)

-

-

-

(0.01)

FY 2012 GAAP Earnings (Loss) Per Share

$0.69

$0.46

$0.46

$(0.05)

$(0.14)

$1.42

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 impact of economic hedging activities

(0.27)

-

-

-

(0.27)

Plant retirements and divestitures

(0.05)

-

-

-

(0.05)

Asset retirement obligation

(0.03)

-

0.00

-

(0.02)

Constellation merger and integration costs

(0.01)

-

(0.00)

(0.06)

(0.07)

Other acquisitions costs

(0.01)

-

-

-

(0.01)

Wolf Hollow acquisition

0.03

-

-

-

0.03

Recovery of costs pursuant to the 2011 distribution rate case order

-

0.03

-

-

0.03

Non-cash remeasurement of deferred income taxes

0.01

-

-

(0.02)

(0.01)

Non-cash charge resulting from Illinois tax rate change legislation

(0.03)

(0.01)

-

(0.00)

(0.04)

FY 2011 GAAP Earnings (Loss) Per Share

$2.66

$0.63

$0.58

$(0.12)

$3.75

GAAP to Operating Adjustments

•

Exelon’s 2013 adjusted (non-GAAP) operating earnings outlook excludes the earnings effects of the

following:

–

Mark-to-market adjustments from economic hedging activities

–

Financial impacts associated with the planned retirement of fossil generating units and the sale in the

fourth quarter of 2012 of three generating stations as required by the merger

–

Certain costs incurred related to the Constellation merger and integration initiatives

–

Non-cash amortization of intangible assets, net, related to commodity contracts recorded at fair value at

the merger date

–

Non-cash amortization of certain debt recorded at fair value at the merger date expected to be retired in

2013

–

Significant impairments of assets, including goodwill

–

Other unusual items

–

Significant changes to GAAP

2012 4Q Earnings Release Slides

36