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

Date of Report (Date of earliest event reported) July 31, 2013

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 July 31, 2013, Exelon Corporation (Exelon) announced via press release its results for the second quarter ended June 30, 2013. 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 second quarter 2013 earnings conference call. This Form 8-K and the attached exhibits are provided under Items 2.02, 7.01 and 9.01 of Form 8-K and are furnished to, but not filed with, the Securities and Exchange Commission.

Exelon has scheduled the conference call for 11:00 AM ET (10:00 AM CT) on July 31, 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 14262933. 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 August 14, 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 14262933.

Section 9 – Financial Statements and Exhibits

Item 9.01. Financial Statements and Exhibits.

(d) Exhibits.

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

* * * * *

This combined Form 8-K is being furnished separately by Exelon, Exelon Generation Company, LLC, Commonwealth Edison Company, 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 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 the Registrants include those factors discussed herein, as well as the items discussed in (1) Exelon’s 2012 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 19; (2) Exelon’s First Quarter 2013 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 17; and (3) 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

Senior Vice President, Chief Financial Officer and Treasurer

Baltimore Gas and Electric Company

July 31, 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

News Release

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

EXELON ANNOUNCES SECOND QUARTER 2013 RESULTS,

REAFFIRMS FULL-YEAR GUIDANCE

CHICAGO (July 31, 2013) — Exelon Corporation (NYSE: EXC) announced second quarter 2013 consolidated earnings as follows:

	Second Quarter
	2013		2012
Adjusted (non-GAAP) Operating Results:
Net Income (Loss) ($ millions)	$	454	$	522
Diluted Earnings per Share	$	0.53	$	0.61
GAAP Results:
Net Income (Loss) ($ millions)	$	490	$	286
Diluted Earnings per Share	$	0.57	$	0.33

“Exelon delivered earnings within its guidance range and continued to operate well this quarter, both in the generation and utility businesses,” said Christopher M. Crane, Exelon’s president and CEO. “The nuclear capacity factor for the first six months of the year was nearly 95%. We maintained our constant focus on creating value and our commitment to financial discipline.”

Exelon also reaffirmed its full-year operating earnings guidance of $2.35 - $2.65 per share.

Second Quarter Operating Results

As shown in the table above, Exelon’s adjusted (non-GAAP) operating earnings declined to $0.53 per share in the second quarter of 2013 from $0.61 per share in the second quarter of 2012. Earnings in the second quarter of 2013 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, lower realized energy prices, and a reduction in load volumes;

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• Higher operating and maintenance (O&M) expenses, including increased labor, contracting and materials costs;

• Increased depreciation and amortization expense primarily due to ongoing capital expenditures; and

• The impact of unfavorable weather at ComEd.

These factors were partially offset by:

• Increased distribution revenue at ComEd due to recovery of increased costs and capital investment pursuant to the formula rate under the Energy Infrastructure Modernization Act (EIMA);

• Merger O&M synergies; and

• Favorable income taxes, primarily reflecting an increase in investment tax credit (ITC) benefit related to the AVSR solar project at Generation and a benefit for the gas property repairs deduction at PECO.

Adjusted (non-GAAP) operating earnings for the second quarter of 2013 do not include the following items (after tax) that were included in reported GAAP earnings:

	(in millions)			(per diluted share)
Exelon Adjusted (non-GAAP) Operating Earnings	$	454		$	0.53
Mark-to-Market Impact of Economic Hedging Activities		253			0.30
Unrealized Losses Related to Nuclear Decommissioning Trust (NDT) Fund Investments		(22	)		(0.03	)
Constellation Merger and Integration Costs		(15	)		(0.02	)
Amortization of Commodity Contract Intangibles		(115	)		(0.13	)
Amortization of the Fair Value of Certain Debt		4			—
Long-Lived Asset Impairment		(69	)		(0.08	)
Exelon GAAP Net Income (Loss)	$	490		$	0.57

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

	(in millions)			(per diluted share)
Exelon Adjusted (non-GAAP) Operating Earnings	$	522		$	0.61
Mark-to-Market Impact of Economic Hedging Activities		123			0.15
Unrealized Losses Related to Nuclear Decommissioning Trust (NDT) Fund Investments		(19	)		(0.02	)
Plant Retirements and Divestitures		1			—
Constellation Merger and Integration Costs		(67	)		(0.08	)
Amortization of Commodity Contract Intangibles		(281	)		(0.33	)
Amortization of the Fair Value of Certain Debt		3			—
Non-cash Remeasurement of Deferred Income Taxes		4			—
Exelon GAAP Net Income (Loss)	$	286		$	0.33

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Second Quarter and Recent Highlights

• Nuclear Operations: Generation’s nuclear fleet, including its owned output from the Salem Generating Station, produced 34,601 gigawatt-hours (GWh) in the second quarter of 2013, compared with 35,137 GWh in the second quarter of 2012. 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 92.8 percent capacity factor for the second quarter of 2013, compared with 93.4 percent for the second quarter of 2012. The number of planned refueling outage days totaled 47 in the second quarter of 2013 versus 51 days in the second quarter of 2012. The number of non-refueling outage days totaled 31 days in the second quarter of 2013, compared with 16 days in the second quarter of 2012.

• Fossil and Renewables Operations: The dispatch match rate for Generation’s fossil and hydro fleet was 99.1 percent in the second quarter of 2013, compared with 93.7 percent in the second quarter of 2012. Energy capture for the wind and solar fleet was 92.4 percent in the second quarter of 2013, compared with 95.0 percent in the second quarter of 2012. Energy capture in the second quarter of 2013 was impacted by late season winter weather, outages, transmission constraints and economic dispatch.

• Constellation Energy Nuclear Group (CENG) Operating Services Agreement: On July 29, 2013, Exelon, Generation and subsidiaries of Generation entered into a Master Agreement with Electricité de France, S.A. (EDF), a subsidiary of EDF, Constellation Energy Nuclear Group LLC (CENG), and subsidiaries of CENG. The Master Agreement contemplates that the parties will execute a series of additional agreements at a closing that will occur following the receipt of regulatory approvals and the satisfaction of other customary closing conditions. Exelon currently expects that the closing will occur during the first quarter or early second quarter of 2014.

Under the terms of the agreement, the CENG plant operating licenses will be transferred to Exelon; Exelon will integrate the CENG fleet under its management model; Exelon will lend $400 million to CENG to support a special dividend to EDF; and EDF will retain an option to sell its CENG stake to Exelon at fair market value between 2016 and 2022. For additional information, please see the Form 8-K that Exelon filed on July 30, 2013.

• Nuclear License Renewals: On May 29, 2013, Exelon Generation filed license renewal applications with the Nuclear Regulatory Commission (NRC) for its Braidwood and Byron Generating Stations. The application filings begin a multiyear review by the NRC to extend the stations’ licenses to operate for another 20 years. Braidwood Units 1 and 2 currently are licensed to operate until 2026 and 2027, respectively. Byron Units 1 and 2 are licensed to operate until 2024 and 2026 respectively. A final NRC decision on the applications is expected in 2015.

• Nuclear Uprates: On June 5, 2013, Exelon decided, based on market conditions, to cancel the previously deferred extended power uprate projects at the LaSalle County and Limerick Generating Stations. As a result of this decision, the costs for these projects previously capitalized in property, plant and equipment became impaired, and therefore, Exelon and Exelon Generation recorded in the second quarter of 2013 a pre-tax charge, including early contract termination costs, to operating and maintenance expense of $100 million. Management has excluded these charges from adjusted (non-GAAP) operating earnings.

• Illinois Senate Bill 9: On May 22, 2013, the Illinois General Assembly overrode the governor’s veto of Senate Bill 9, which then became effective immediately. The enacted legislation clarifies that for ComEd’s distribution formula rate structure, a year-end rate base and capital structure should be used, a weighted average cost of capital return should be applied against the reconciliation and a return shall be allowed on the pension asset. These adjustments resulted in an increase in pre-tax earnings of $10 million in the second quarter of 2013. For full year 2013, the expected impact is an increase in pre-tax earnings of approximately $16 million.

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• BGE Gas and Electric Distribution Rate Case: On May 17, 2013, BGE filed an application with the Maryland Public Service Commission (MDPSC) for increases of $101 million and $30 million to its electric and gas base rates, respectively. The requested rate of return on equity in the application is 10.50 percent for electric and 10.35 percent for gas. The MDPSC will determine any increase in rates after a seven-month proceeding with input from all interested parties. The new electric and gas distribution base rates are expected to take effect in mid December 2013.

• Redemption of Junior Subordinated Debentures: On June 15, 2013, Exelon redeemed all of its outstanding Series A Junior Subordinated Debentures at a redemption price equal to 100 percent of the principal amount. The aggregate outstanding principal amount of the Debentures was $450 million and the annual interest rate was 8.625 percent.

• 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 June 30, 2013, is 96 percent to 99 percent for 2013, 78 percent to 81 percent for 2014, and 41 percent to 44 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.

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.

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Second quarter 2013 GAAP net income was $330 million, compared with net income of $166 million in the second quarter of 2012. Adjusted (non-GAAP) operating earnings for the second quarter of 2013 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 (Loss) is in the table below:

($ millions)	2Q13			2Q12
Generation Adjusted (non-GAAP) Operating Earnings	$	273		$	399
Mark-to-Market Impact of Economic Hedging Activities		263			120
Unrealized Losses Related to NDT Fund Investments		(22	)		(19	)
Plant Retirements and Divestitures		—			1
Constellation Merger and Integration Costs		(12	)		(57	)
Amortization of Commodity Contract Intangibles		(115	)		(281	)
Amortization of the Fair Value of Certain Debt		4			3
Long-Lived Asset Impairment		(61	)		—
Generation GAAP Net Income (Loss)	$	330		$	166

Generation’s Adjusted (non-GAAP) Operating Earnings in the second quarter of 2013 decreased $126 million compared with the same quarter in 2012. 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, lower realized market prices, and a reduction in load volumes; and

• Increased depreciation and amortization expense due to ongoing capital expenditures and the completion of wind and solar facilities placed in service in the second half of 2012 and in 2013.

These items were partially offset by favorable O&M expense. primarily driven by merger synergies and favorable income taxes driven by an increase in ITC benefits related to the AVSR solar project.

Generation’s average realized margin on all electric sales, including sales to affiliates and excluding trading activity, was $27.34 per megawatt-hour (MWh) in the second quarter of 2013, compared with $26.15 per MWh in the second quarter of 2012.

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

ComEd recorded GAAP net income of $96 million in the second quarter of 2013, compared with net income of $42 million in the second quarter of 2012. ComEd’s Adjusted (non-GAAP) Operating Earnings in the second quarter of 2013 were up $54 million from the same quarter in 2012, primarily due to the discrete impacts of the 2012 Distribution Formula Rate Order recorded in the second quarter of 2012 and increased distribution revenue due to recovery of increased costs and capital investment pursuant to the formula rate under EIMA.

For the second quarter of 2013, heating degree-days in the ComEd service territory were up 43.0 percent relative to the same period in 2012 and were 1.7 percent above normal. For the second quarter of 2013, cooling degree-days in the ComEd service territory were down 43.3 percent relative to the same period in 2012 and were 10.1 percent above normal. Total retail electric deliveries decreased 3.5 percent quarter over quarter.

Weather-normalized retail electric deliveries increased 1.0 percent in the second quarter of 2013 relative to 2012, reflecting increases in deliveries to small commercial and industrial

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(C&I) and residential customers offset by a decrease in deliveries to large C&I customers. For ComEd, weather had an unfavorable after-tax effect of $13 million on second quarter 2013 earnings relative to 2012 and a favorable after-tax effect of $1 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 second quarter of 2013 was $72 million, compared with $79 million in the second quarter of 2012. Adjusted (non-GAAP) Operating Earnings for the second quarter of 2013 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)	2Q13			2Q12
PECO Adjusted (non-GAAP) Operating Earnings	$	74		$	81
Constellation Merger and Integration Costs		(2	)		(2	)
PECO GAAP Net Income (Loss)	$	72		$	79

PECO’s Adjusted (non-GAAP) Operating Earnings in the second quarter of 2013 decreased $7 million from the same quarter in 2012, primarily due to higher operating and maintenance expense offset by favorable income taxes driven by benefit for the gas property repairs deduction.

For the second quarter of 2013, heating degree-days in the PECO service territory were up 24.9 percent relative to the same period in 2013 and were 9.1 percent below normal. For the second quarter of 2013, cooling degree-days in the PECO service territory were down 2.8 percent relative to the same period in 2012 and were 20.1 percent above normal. Total retail electric deliveries were flat quarter over quarter. On the gas side, deliveries in the second quarter of 2013 were up 6.7 percent from the second quarter of 2012.

Weather-normalized retail electric deliveries increased 0.8 percent in the second quarter of 2013 relative to 2012, reflecting an increase in deliveries to both small and large C&I customers offset by a decrease in deliveries to residential customers. Weather-normalized gas deliveries were up 1.8 percent in the second quarter of 2013. For PECO, weather had no impact on second quarter 2013 earnings relative to 2012 and a favorable after-tax effect of $2 million relative to normal weather.

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

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BGE’s GAAP net income in the second quarter of 2013 was $22 million, compared with $13 million in the second quarter of 2012. Adjusted (non-GAAP) Operating Earnings for the second quarter of 2013 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)	2Q13			2Q12
BGE Adjusted (non-GAAP) Operating Earnings	$	23		$	14
Constellation Merger and Integration Costs		(1	)		(1	)
BGE GAAP Net Income (Loss)	$	22		$	13

BGE’s Adjusted (non-GAAP) Operating Earnings in the second quarter of 2013 increased $9 million from the same quarter in 2012, primarily due to higher electric and gas distribution rates. Due to revenue decoupling, BGE is not affected by actual weather with the exception of major storms.

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 July 31, 2013.

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 2012 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 19; (2) Exelon’s First Quarter 2013 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 17; and (3) 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 news 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 approximately 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).

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Earnings Release Attachments

Table of Contents

Consolidating Statements of Operations - Three Months Ended June 30, 2013 and 2012	1
Consolidating Statements of Operations - Six Months Ended June 30, 2013 and 2012	2
Business Segment Comparative Statements of Operations - Generation and ComEd - Three and Six Months Ended June 30, 2013 and 2012	3
Business Segment Comparative Statements of Operations - PECO and BGE - Three and Six Months Ended June 30, 2013 and 2012	4
Business Segment Comparative Statements of Operations - Other - Three and Six Months Ended June 30, 2013 and 2012	5
Consolidated Balance Sheets - June 30, 2013 and December 31, 2012	6
Consolidated Statements of Cash Flows - Six Months Ended June 30, 2013 and 2012	7
Reconciliation of Adjusted (non-GAAP) Operating Earnings to GAAP Consolidated Statements of Operations - Exelon - Three Months Ended June 30, 2013 and 2012	8
Reconciliation of Adjusted (non-GAAP) Operating Earnings to GAAP Consolidated Statements of Operations - Exelon - Six Months Ended June 30, 2013 and 2012	9
Reconciliation of Adjusted (non-GAAP) Operating Earnings to GAAP Earnings By Business Segment - Three Months Ended June 30, 2013 and 2012	10
Reconciliation of Adjusted (non-GAAP) Operating Earnings to GAAP Earnings By Business Segment - Six Months Ended June 30, 2013 and 2012	11
Reconciliation of Adjusted (non-GAAP) Operating Earnings to GAAP Consolidated Statements of Operations - Generation - Three and Six Months Ended June 30, 2013 and 2012	12
Reconciliation of Adjusted (non-GAAP) Operating Earnings to GAAP Consolidated Statements of Operations - ComEd - Three and Six Months Ended June 30, 2013 and 2012	13
Reconciliation of Adjusted (non-GAAP) Operating Earnings to GAAP Consolidated Statements of Operations - PECO - Three and Six Months Ended June 30, 2013 and 2012	14
Reconciliation of Adjusted (non-GAAP) Operating Earnings to GAAP Consolidated Statements of Operations - BGE - Three Months Ended June 30, 2013 and 2012, and Six Months Ended and March 12, 2012 through June 30, 2013 and 2012, respectively.	15
Reconciliation of Adjusted (non-GAAP) Operating Earnings to GAAP Consolidated Statements of Operations - Other - Three and Six Months Ended June 30, 2013 and 2012	16
Exelon Generation Statistics - Three Months Ended June 30, 2013, March 31, 2013, December 31, 2012, September 30, 2012 and June 30, 2012	17
Exelon Generation Statistics - Six Months Ended June 30, 2013 and 2012	18
ComEd Statistics - Three and Six Months Ended June 30, 2013 and 2012	19
PECO Statistics - Three and Six Months Ended June 30, 2013 and 2012	20
BGE Statistics - Three and Six Months Ended June 30, 2013 and 2012	21

EXELON CORPORATION

Consolidating Statements of Operations

(unaudited)

(in millions)

	Three Months Ended June 30, 2013
	Generation			ComEd			PECO			BGE			Other (a)			Exelon Consolidated
Operating revenues	$	4,070		$	1,080		$	672		$	653		$	(334	)	$	6,141
Operating expenses
Purchased power and fuel		1,946			248			258			288			(321	)		2,419
Operating and maintenance		1,189			359			181			160			3			1,892
Depreciation, amortization, accretion and depletion		210			170			56			82			15			533
Taxes other than income		101			71			39			54			6			271
Total operating expenses		3,446			848			534			584			(297	)		5,115
Equity in loss of unconsolidated affiliates		(21	)		—			—			—			—			(21	)
Operating income (loss)		603			232			138			69			(37	)		1,005
Other income and deductions
Interest expense		(93	)		(76	)		(28	)		(32	)		(23	)		(252	)
Other, net		(33	)		6			—			4			6			(17	)
Total other income and deductions		(126	)		(70	)		(28	)		(28	)		(17	)		(269	)
Income (loss) before income taxes		477			162			110			41			(54	)		736
Income taxes		149			66			32			16			(24	)		239
Net income (loss)		328			96			78			25			(30	)		497
Net income (loss) attributable to noncontrolling interests, preferred security dividends and redemption and preference stock dividends		(2	)		—			6			3			—			7
Net income (loss) on common stock	$	330		$	96		$	72		$	22		$	(30	)	$	490
	Three Months Ended June 30, 2012
	Generation			ComEd			PECO			BGE			Other (a)			Exelon Consolidated
Operating revenues	$	3,765		$	1,281		$	715		$	616		$	(411	)	$	5,966
Operating expenses
Purchased power and fuel		1,852			587			296			285			(414	)		2,606
Operating and maintenance		1,178			331			172			161			(1	)		1,841
Depreciation, amortization, accretion and depletion		204			152			54			71			13			494
Taxes other than income		90			69			42			47			6			254
Total operating expenses		3,324			1,139			564			564			(396	)		5,195
Equity in loss of unconsolidated affiliates		(57	)		—			—			—			—			(57	)
Operating income (loss)		384			142			151			52			(15	)		714
Other income and deductions
Interest expense		(85	)		(74	)		(31	)		(34	)		(32	)		(256	)
Other, net		(76	)		3			2			7			21			(43	)
Total other income and deductions		(161	)		(71	)		(29	)		(27	)		(11	)		(299	)
Income (loss) before income taxes		223			71			122			25			(26	)		415
Income taxes		58			29			42			9			(12	)		126
Net income (loss)		165			42			80			16			(14	)		289
Net income (loss) attributable to noncontrolling interests, preferred security dividends and preference stock dividends		(1	)		—			1			3			—			3
Net income (loss) on common stock	$	166		$	42		$	79		$	13		$	(14	)	$	286

(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)

	Six Months Ended June 30, 2013
	Generation			ComEd			PECO			BGE			Other (b)			Exelon Consolidated
Operating revenues	$	7,603		$	2,239		$	1,567		$	1,533		$	(719	)	$	12,223
Operating expenses
Purchased power and fuel		4,114			630			664			713			(721	)		5,400
Operating and maintenance		2,302			687			369			303			(5	)		3,656
Depreciation, amortization, accretion and depletion		424			337			113			175			27			1,076
Taxes other than income		194			145			80			109			20			548
Total operating expenses		7,034			1,799			1,226			1,300			(679	)		10,680
Equity in loss of unconsolidated affiliates		(30	)		—			—			—			—			(30	)
Operating income (loss)		539			440			341			233			(40	)		1,513
Other income and deductions
Interest expense		(176	)		(429	)		(57	)		(66	)		(148	)		(876	)
Other, net		95			11			3			9			37			155
Total other income and deductions		(81	)		(418	)		(54	)		(57	)		(111	)		(721	)
Income (loss) before income taxes		458			22			287			176			(151	)		792
Income taxes		148			8			87			70			(19	)		294
Net income (loss)		310			14			200			106			(132	)		498
Net income (loss) attributable to noncontrolling interests, preferred security dividends and redemption and preference stock dividends		(1	)		—			7			6			—			12
Net income (loss) on common stock	$	311		$	14		$	193		$	100		$	(132	)	$	486
	Six Months Ended June 30, 2012 (a)
	Generation			ComEd			PECO			BGE			Other (b)			Exelon Consolidated
Operating revenues	$	6,508		$	2,670		$	1,590		$	668		$	(780	)	$	10,656
Operating expenses
Purchased power and fuel		2,896			1,208			707			352			(792	)		4,371
Operating and maintenance		2,356			650			375			222			206			3,809
Depreciation, amortization, accretion and depletion		357			300			107			90			22			876
Taxes other than income		164			144			74			57			9			448
Total operating expenses		5,773			2,302			1,263			721			(555	)		9,504
Equity in loss of unconsolidated affiliates		(79	)		—			—			—			—			(79	)
Operating income (loss)		656			368			327			(53	)		(225	)		1,073
Other income and deductions
Interest expense		(138	)		(156	)		(62	)		(42	)		(53	)		(451	)
Other, net		103			7			5			8			29			152
Total other income and deductions		(35	)		(149	)		(57	)		(34	)		(24	)		(299	)
Income (loss) before income taxes		621			219			270			(87	)		(249	)		774
Income taxes		289			90			93			(38	)		(150	)		284
Net income (loss)		332			129			177			(49	)		(99	)		490
Net income (loss) attributable to noncontrolling interests, preferred security dividends and preference stock dividends		(2	)		—			2			4			—			4
Net income (loss) on common stock	$	334		$	129		$	175		$	(53	)	$	(99	)	$	486

(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 June 30,									Six Months Ended June 30,
	2013			2012			Variance			2013			2012 (a)			Variance
Operating revenues	$	4,070		$	3,765		$	305		$	7,603		$	6,508		$	1,095
Operating expenses
Purchased power and fuel		1,946			1,852			94			4,114			2,896			1,218
Operating and maintenance		1,189			1,178			11			2,302			2,356			(54	)
Depreciation, amortization, accretion and depletion		210			204			6			424			357			67
Taxes other than income		101			90			11			194			164			30
Total operating expenses		3,446			3,324			122			7,034			5,773			1,261
Equity in loss of unconsolidated affiliates		(21	)		(57	)		36			(30	)		(79	)		49
Operating income		603			384			219			539			656			(117	)
Other income and deductions
Interest expense		(93	)		(85	)		(8	)		(176	)		(138	)		(38	)
Other, net		(33	)		(76	)		43			95			103			(8	)
Total other income and deductions		(126	)		(161	)		35			(81	)		(35	)		(46	)
Income before income taxes		477			223			254			458			621			(163	)
Income taxes		149			58			91			148			289			(141	)
Net income		328			165			163			310			332			(22	)
Net loss attributable to noncontrolling interests		(2	)		(1	)		(1	)		(1	)		(2	)		1
Net income on common stock	$	330		$	166		$	164		$	311		$	334		$	(23	)

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

	ComEd
	Three Months Ended June 30,									Six Months Ended June 30,
	2013			2012			Variance			2013			2012			Variance
Operating revenues	$	1,080		$	1,281		$	(201	)	$	2,239		$	2,670		$	(431	)
Operating expenses
Purchased power		248			587			(339	)		630			1,208			(578	)
Operating and maintenance		359			331			28			687			650			37
Depreciation and amortization		170			152			18			337			300			37
Taxes other than income		71			69			2			145			144			1
Total operating expenses		848			1,139			(291	)		1,799			2,302			(503	)
Operating income		232			142			90			440			368			72
Other income and deductions
Interest expense		(76	)		(74	)		(2	)		(429	)		(156	)		(273	)
Other, net		6			3			3			11			7			4
Total other income and deductions		(70	)		(71	)		1			(418	)		(149	)		(269	)
Income before income taxes		162			71			91			22			219			(197	)
Income taxes		66			29			37			8			90			(82	)
Net income	$	96		$	42		$	54		$	14		$	129		$	(115	)

3

EXELON CORPORATION

Business Segment Comparative Statements of Operations

(unaudited)

(in millions)

	PECO
	Three Months Ended June 30,									Six Months Ended June 30,
	2013			2012			Variance			2013			2012			Variance
Operating revenues	$	672		$	715		$	(43	)	$	1,567		$	1,590		$	(23	)
Operating expenses
Purchased power and fuel		258			296			(38	)		664			707			(43	)
Operating and maintenance		181			172			9			369			375			(6	)
Depreciation and amortization		56			54			2			113			107			6
Taxes other than income		39			42			(3	)		80			74			6
Total operating expenses		534			564			(30	)		1,226			1,263			(37	)
Operating income		138			151			(13	)		341			327			14
Other income and deductions
Interest expense		(28	)		(31	)		3			(57	)		(62	)		5
Other, net		—			2			(2	)		3			5			(2	)
Total other income and deductions		(28	)		(29	)		1			(54	)		(57	)		3
Income before income taxes		110			122			(12	)		287			270			17
Income taxes		32			42			(10	)		87			93			(6	)
Net income		78			80			(2	)		200			177			23
Preferred security dividends and redemption		6			1			5			7			2			5
Net income on common stock	$	72		$	79		$	(7	)	$	193		$	175		$	18
	BGE
	Three Months Ended June 30,									Six Months Ended June 30,
	2013			2012			Variance			2013			2012 (a)			Variance
Operating revenues	$	653		$	616		$	37		$	1,533		$	668		$	865
Operating expenses
Purchased power and fuel		288			285			3			713			352			361
Operating and maintenance		160			161			(1	)		303			222			81
Depreciation and amortization		82			71			11			175			90			85
Taxes other than income		54			47			7			109			57			52
Total operating expenses		584			564			20			1,300			721			579
Operating income (loss)		69			52			17			233			(53	)		286
Other income and deductions
Interest expense		(32	)		(34	)		2			(66	)		(42	)		(24	)
Other, net		4			7			(3	)		9			8			1
Total other income and deductions		(28	)		(27	)		(1	)		(57	)		(34	)		(23	)
Income (loss) before income taxes		41			25			16			176			(87	)		263
Income taxes		16			9			7			70			(38	)		108
Net income (loss)		25			16			9			106			(49	)		155
Preference stock dividends		3			3			—			6			4			2
Net income (loss) on common stock	$	22		$	13		$	9		$	100		$	(53	)	$	153

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

4

EXELON CORPORATION

Business Segment Comparative Statements of Operations

(unaudited)

(in millions)

	Other (a)
	Three Months Ended June 30,									Six Months Ended June 30,
	2013			2012			Variance			2013			2012 (b)			Variance
Operating revenues	$	(334	)	$	(411	)	$	77		$	(719	)	$	(780	)	$	61
Operating expenses
Purchased power and fuel		(321	)		(414	)		93			(721	)		(792	)		71
Operating and maintenance		3			(1	)		4			(5	)		206			(211	)
Depreciation and amortization		15			13			2			27			22			5
Taxes other than income		6			6			—			20			9			11
Total operating expenses		(297	)		(396	)		99			(679	)		(555	)		(124	)
Operating loss		(37	)		(15	)		(22	)		(40	)		(225	)		185
Other income and deductions
Interest expense		(23	)		(32	)		9			(148	)		(53	)		(95	)
Other, net		6			21			(15	)		37			29			8
Total other income and deductions		(17	)		(11	)		(6	)		(111	)		(24	)		(87	)
Loss before income taxes		(54	)		(26	)		(28	)		(151	)		(249	)		98
Income taxes		(24	)		(12	)		(12	)		(19	)		(150	)		131
Net loss	$	(30	)	$	(14	)	$	(16	)	$	(132	)	$	(99	)	$	(33	)

(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

(in millions)

	June 30, 2013			December 31, 2012
	(unaudited)
ASSETS
Current assets
Cash and cash equivalents	$	956		$	1,411
Cash and cash equivalents of variable interest entities		35			75
Restricted cash and investments		61			86
Restricted cash and investments of variable interest entities		53			47
Accounts receivable, net
Customer		2,609			2,795
Other		1,224			1,141
Accounts receivable, net, variable interest entities		252			292
Mark-to-market derivative assets		845			938
Unamortized energy contract assets		573			886
Inventories, net
Fossil fuel		214			246
Materials and supplies		805			768
Deferred income taxes		288			131
Regulatory assets		804			764
Other		690			560
Total current assets		9,409			10,140
Property, plant and equipment, net		45,994			45,186
Deferred debits and other assets
Regulatory assets		6,519			6,497
Nuclear decommissioning trust funds		7,463			7,248
Investments		1,171			1,184
Investments in affiliates		22			22
Investment in CENG		1,876			1,849
Goodwill		2,625			2,625
Mark-to-market derivative assets		772			937
Unamortized energy contracts assets		856			1,073
Pledged assets for Zion Station decommissioning		538			614
Other		1,175			1,186
Total deferred debits and other assets		23,017			23,235
Total assets	$	78,420		$	78,561
Liabilities and shareholders’ equity
Current liabilities
Short-term borrowings	$	662		$	—
Short-term notes payable - accounts receivable agreement		210			210
Long-term debt due within one year		1,944			975
Long-term debt due within one year of variable interest entities		87			72
Accounts payable		2,210			2,446
Accounts payable of variable interest entities		147			202
Accrued expenses		1,382			1,800
Deferred income taxes		45			58
Regulatory liabilities		357			368
Mark-to-market derivative liabilities		147			352
Unamortized energy contract liabilities		360			455
Other		823			853
Total current liabilities		8,374			7,791
Long-term debt		16,121			17,190
Long-term debt to financing trusts		648			648
Long-term debt of variable interest entities		449			508
Deferred credits and other liabilities
Deferred income taxes and unamortized investment tax credits		11,519			11,551
Asset retirement obligations		5,202			5,074
Pension obligations		3,164			3,428
Non-pension postretirement benefit obligations		2,706			2,662
Spent nuclear fuel obligation		1,020			1,020
Regulatory liabilities		4,044			3,981
Mark-to-market derivative liabilities		178			281
Unamortized energy contract liabilities		399			528
Payable for Zion Station decommissioning		373			432
Other		2,635			1,650
Total deferred credits and other liabilities		31,240			30,607
Total liabilities		56,832			56,744
Commitments and contingencies
Preferred securities of subsidiary		—			87
Shareholders’ equity
Common stock		16,693			16,632
Treasury stock, at cost		(2,327	)		(2,327	)
Retained earnings		9,660			9,893
Accumulated other comprehensive loss, net		(2,673	)		(2,767	)
Total shareholders’ equity		21,353			21,431
BGE preference stock not subject to mandatory redemption		193			193
Noncontrolling interest		42			106
Total equity		21,588			21,730
Total liabilities and shareholders’ equity	$	78,420		$	78,561

6

EXELON CORPORATION

Consolidated Statements of Cash Flows

(unaudited)

(in millions)

	Six Months Ended
	June 30,
	2013			2012 (a)
Cash flows from operating activities
Net income	$	498			490
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation, amortization, depletion and accretion, including nuclear fuel and energy contract amortization		1,972			1,895
Deferred income taxes and amortization of investment tax credits		(468	)		227
Net fair value changes related to derivatives		(28	)		(323	)
Net realized and unrealized gains on nuclear decommissioning trust fund investments		(27	)		(70	)
Other non-cash operating activities		576			959
Changes in assets and liabilities:
Accounts receivable		131			414
Inventories		(18	)		45
Accounts payable, accrued expenses and other current liabilities		(583	)		(1,063	)
Option premiums paid, net		(10	)		(108	)
Counterparty collateral (posted) received, net		(259	)		451
Income taxes		705			259
Pension and non-pension postretirement benefit contributions		(284	)		(90	)
Other assets and liabilities		133			(373	)
Net cash flows provided by operating activities		2,338			2,713
Cash flows from investing activities
Capital expenditures		(2,518	)		(2,800	)
Proceeds from nuclear decommissioning trust fund sales		1,448			5,371
Investment in nuclear decommissioning trust funds		(1,565	)		(5,483	)
Cash and restricted cash acquired from Constellation		—			964
Proceeds from sales of investments		4			12
Purchases of investments		(3	)		(5	)
Change in restricted cash		22			(15	)
Other investing activities		63			(12	)
Net cash flows used in investing activities		(2,549	)		(1,968	)
Cash flows from financing activities
Changes in short-term debt		662			179
Issuance of long-term debt		509			850
Retirement of long-term debt		(616	)		(649	)
Redemption of preferred securities		(93	)		—
Dividends paid on common stock		(716	)		(773	)
Dividends paid to former Constellation shareholders		—			(51	)
Proceeds from employee stock plans		32			42
Other financing activities		(62	)		(10	)
Net cash flows used in financing activities		(284	)		(412	)
(Decrease) increase in cash and cash equivalents		(495	)		333
Cash and cash equivalents at beginning of period		1,486			1,016
Cash and cash equivalents at end of period	$	991		$	1,349

(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 June 30, 2013									Three Months Ended June 30, 2012
							Adjusted									Adjusted
	GAAP (a)			Adjustments			Non-GAAP			GAAP (a)			Adjustments			Non-GAAP
Operating revenues	$	6,141		$	(259	)(b),(c)	$	5,882		$	5,966		$	412	(b),(c),(h)	$	6,378
Operating expenses
Purchased power and fuel		2,419			(9	)(b),(c)		2,410			2,606			262	(b),(c),(h)		2,868
Operating and maintenance		1,892			(133	)(d),(e)		1,759			1,841			(101	)(d),(h)		1,740
Depreciation, amortization, accretion and depletion		533			(1	)(d)		532			494			(14	)(d),(h)		480
Taxes other than income		271			—			271			254			(2	)(h)		252
Total operating expenses		5,115			(143	)		4,972			5,195			145			5,340
Equity in loss of unconsolidated affiliates		(21	)		21	(c)		—			(57	)		52	(c),(d)		(5	)
Operating income		1,005			(95	)		910			714			319			1,033
Other income and deductions
Interest expense		(252	)		4	(e),(f)		(248	)		(256	)		(5	)(f)		(261	)
Other, net		(17	)		57	(d),(f),(g)		40			(43	)		105	(d),(g),(h)		62
Total other income and deductions		(269	)		61			(208	)		(299	)		100			(199	)
Income before income taxes		736			(34	)		702			415			419			834
Income taxes		239			2	(b),(c),(d),(e),(f),(g)		241			126			183	(b),(c),(d),(f),(g),(h),(i)		309
Net income		497			(36	)		461			289			236			525
Net income attributable to noncontrolling interests, preferred security dividends and redemption and preference stock dividends		7			—			7			3			—			3
Net income on common stock	$	490		$	(36	)	$	454		$	286		$	236		$	522
Effective tax rate		32.5	%					34.3	%		30.4	%					37.1	%
Earnings per average common share
Basic	$	0.57		$	(0.04	)	$	0.53		$	0.34		$	0.28		$	0.62
Diluted	$	0.57		$	(0.04	)	$	0.53		$	0.33		$	0.28		$	0.61
Average common shares outstanding
Basic		856						856			853						853
Diluted		860						860			856						856
Effect of adjustments on earnings per average diluted common share recorded in accordance with GAAP:
Mark-to-market impact of economic hedging activities (b)				$	(0.30	)							$	(0.15	)
Amortization of commodity contract intangibles (c)					0.13									0.33
Constellation merger and integration costs (d)					0.02									0.08
Long-lived asset impairment (e)					0.08									—
Amortization of the fair value of certain debt (f)					—									—
Unrealized losses related to NDT fund investments (g)					0.03									0.02
Plant retirements and divestitures (h)					—									—
Non-cash remeasurement of deferred income taxes (i)					—									—
Total adjustments				$	(0.04	)							$	0.28

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

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

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

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

(e) Adjustment to exclude a 2013 charge to earnings primarily related to Generation’s cancellation of previously capitalized nuclear uprate projects.

(f) Adjustment to exclude the non-cash amortization of certain debt recorded at fair value at the merger date, which was retired in the second quarter of 2013.

(g) Adjustment to exclude the unrealized losses on NDT fund investments to the extent not offset by contractual accounting as described in the notes to the consolidated financial statements.

(h) Adjustment to exclude the impacts associated with the sale or retirement of generating stations.

(i) Adjustment to exclude the non-cash impacts of the remeasurement of state deferred income taxes as a result of the merger.

8

EXELON CORPORATION

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

(unaudited)

(in millions, except per share data)

	Six Months Ended June 30, 2013									Six Months Ended June 30, 2012 (a)
							Adjusted									Adjusted
	GAAP (b)			Adjustments			Non-GAAP			GAAP (b)			Adjustments			Non-GAAP
Operating revenues	$	12,223		$	552	(c),(d)	$	12,775		$	10,656		$	559	(c),(d),(e),(k)	$	11,215
Operating expenses
Purchased power and fuel		5,400			244	(c),(d)		5,644			4,371			262	(c),(d),(e),(f)		4,633
Operating and maintenance		3,656			(170	)(e),(f),(g)		3,486			3,809			(673	)(d),(e),(f),(k),(l),(m)		3,136
Depreciation, amortization, accretion and depletion		1,076			(2	)(f)		1,074			876			(30	)(e),(f)		846
Taxes other than income		548			—			548			448			(1	)(e),(k)		447
Total operating expenses		10,680			72			10,752			9,504			(442	)		9,062
Equity in earnings (loss) of unconsolidated affiliates		(30	)		39	(d)		9			(79	)		60	(d),(f)		(19	)
Operating income		1,513			519			2,032			1,073			1,061			2,134
Other income and deductions
Interest expense		(876	)		371	(f),(g),(h),(i)		(505	)		(451	)		(6	)(i)		(457	)
Other, net		155			(53	)(e),(f),(j),(i)		102			152			(14	)(e),(f),(j)		138
Total other income and deductions		(721	)		318			(403	)		(299	)		(20	)		(319	)
Income before income taxes		792			837			1,629			774			1,041			1,815
Income taxes		294			267	(c),(d),(e),(f),(g),(h),(i),(j)		561			284			402	(c),(d),(e),(f),(i),(j),(k),(l),(m),(n)		686
Net income		498			570			1,068			490			639			1,129
Net income attributable to noncontrolling interests, preferred security dividends and redemption and preference stock dividends		12			—			12			4			—			4
Net income on common stock	$	486		$	570		$	1,056		$	486		$	639		$	1,125
Effective tax rate		37.1	%					34.4	%		36.7	%					37.8	%
Earnings per average common share
Basic	$	0.57		$	0.67		$	1.24		$	0.62		$	0.82		$	1.44
Diluted	$	0.57		$	0.66		$	1.23		$	0.62		$	0.82		$	1.44
Average common shares outstanding
Basic		856						856			779						779
Diluted		859						859			781						781
Effect of adjustments on earnings per average diluted common share recorded in accordance with GAAP:
Mark-to-market impact of economic hedging activities (c)				$	(0.02	)							$	(0.21	)
Amortization of commodity contract intangibles (d)					0.27									0.46
Plant retirements and divestitures (e)					(0.02	)								0.01
Constellation merger and integration costs (f)					0.05									0.23
Long-lived asset impairment (g)					0.10									—
Remeasurement of like-kind exchange tax position (h)					0.31									—
Amortization of the fair value of certain debt (i)					(0.01	)								—
Unrealized (gains) related to NDT fund investments (j)					(0.02	)								(0.02	)
Maryland commitments (k)					—									0.29
FERC settlement (l)					—									0.22
Other acquisition costs (m)					—									—
Non-cash remeasurement of deferred income taxes (n)					—									(0.16	)
Total adjustments				$	0.66								$	0.82

(a) For the six months ended June 31, 2012, 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 the mark-to-market impact of Exelon’s economic hedging activities, net of intercompany eliminations.

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

(e) Adjustment to exclude the impacts associated with the sale or retirement of generating stations.

(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) integration initiatives and certain pre-acquisition contingencies, partially offset in 2013 by a one-time benefit pursuant to the February 22, 2013 order for BGE’s 2012 Maryland electric and natural gas distribution rates case for the recovery of previously incurred integration costs.

(g) Adjustment to exclude a 2013 charge to earnings primarily related to Generation’s cancellation of previously capitalized nuclear uprate projects.

(h) Adjustment to exclude a non-cash charge to earnings resulting from the first quarter 2013 remeasurement of a like-kind exchange tax position taken on ComEd’s 1999 sale of fossil generating assets.

(i) Adjustment to exclude the non-cash amortization of certain debt recorded at fair value at the merger date, which was retired in the second quarter of 2013.

(j) Adjustment to exclude the unrealized gains on NDT fund investments to the extent not offset by contractual accounting as described in the notes to the consolidated financial statements.

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

(l) Adjustment to exclude costs associated with a March 2012 settlement with the FERC to resolve a dispute related to Constellation’s prior period hedging and risk management transactions.

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

(n) Adjustment to exclude the non-cash impacts of the remeasurement of state deferred income taxes as a result of the merger.

9

EXELON CORPORATION

Reconciliation of Adjusted (non-GAAP) Operating

Earnings to GAAP Earnings (in millions)

Three Months Ended June 30, 2013 and 2012

	Exelon
	Earnings per
	Diluted Share			Generation			ComEd			PECO			BGE			Other (a)			Exelon
2012 GAAP Earnings (Loss)	$	0.33		$	166		$	42		$	79		$	13		$	(14	)	$	286
2012 Adjusted (non-GAAP) Operating Earnings (Loss) Adjustments:
Mark-to-Market Impact of Economic Hedging Activities		(0.15	)		(120	)		—			—			—			(3	)		(123	)
Unrealized Losses Related to NDT Fund Investments (1)		0.02			19			—			—			—			—			19
Plant Retirements and Divestitures (2)		—			(1	)		—			—			—			—			(1	)
Constellation Merger and Integration Costs (3)		0.08			57			—			2			1			7			67
Amortization of Commodity Contract Intangibles (4)		0.33			281			—			—			—			—			281
Amortization of the Fair Value of Certain Debt (5)		—			(3	)		—			—			—			—			(3	)
Non-Cash Remeasurement of Deferred Income Taxes (6)		—			—			—			—			—			(4	)		(4	)
2012 Adjusted (non-GAAP) Operating Earnings (Loss)		0.61			399			42			81			14			(14	)		522
Year Over Year Effects on Earnings:
Generation Energy Margins, Excluding Mark-to-Market:
Nuclear Volume (7)		(0.01	)		(9	)		—			—			—			—			(9	)
Nuclear Fuel Costs (8)		(0.01	)		(7	)		—			—			—			—			(7	)
Capacity Pricing (9)		(0.02	)		(13	)		—			—			—			—			(13	)
Market and Portfolio Conditions (10)		(0.11	)		(101	)		—			—			—			—			(101	)
ComEd, PECO and BGE Margins:
Weather		(0.02	)		—			(13	)		—			—	(b)		—			(13	)
Load		—			—			3			(2	)		—	(b)		—			1
Discrete Impacts of the 2012 Distribution Formula Rate Order (11)		0.07			—			59			—			—			—			59
Other Energy Delivery (12)		0.06			—			33			(2	)		21			—			52
Operating and Maintenance Expense:
Labor, Contracting and Materials (13)		(0.02	)		3			(6	)		(9	)		(5	)		—			(17	)
Planned Nuclear Refueling Outages		—			(1	)		—			—			—			—			(1	)
Pension and Non-Pension Postretirement Benefits (14)		—			—			(3	)		2			(1	)		1			(1	)
Other Operating and Maintenance (15)		0.01			8			(8	)		—			5			—			5
Depreciation and Amortization Expense (16)		(0.04	)		(13	)		(11	)		(1	)		(7	)		—			(32	)
Equity in Earnings of Unconsolidated Affiliates (17)		—			3			—			—			—			—			3
Income Taxes (18)		0.03			12			—			7			—			5			24
Interest Expense, Net		—			—			(1	)		1			1			(1	)		—
Other (19)		(0.01	)		(8	)		1			3			(5	)		(3	)		(12	)
Preferred Securities Redemption (20)		(0.01	)		—			—			(6	)		—			—			(6	)
2013 Adjusted (non-GAAP) Operating Earnings (Loss)		0.53			273			96			74			23			(12	)		454
2013 Adjusted (non-GAAP) Operating Earnings (Loss) Adjustments:
Mark-to-Market Impact of Economic Hedging Activities		0.30			263			—			—			—			(10	)		253
Unrealized Losses Related to NDT Fund Investments (1)		(0.03	)		(22	)		—			—			—			—			(22	)
Constellation Merger and Integration Costs (3)		(0.02	)		(12	)		—			(2	)		(1	)		—			(15	)
Amortization of Commodity Contract Intangibles (4)		(0.13	)		(115	)		—			—			—			—			(115	)
Amortization of the Fair Value of Certain Debt (5)		—			4			—			—			—			—			4
Long-Lived Asset Impairment (21)		(0.08	)		(61	)		—			—			—			(8	)		(69	)
2013 GAAP Earnings (Loss)	$	0.57		$	330		$	96		$	72		$	22		$	(30	)	$	490

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

(b) 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 on NDT fund investments to the extent not offset by contractual accounting as described in the notes to the consolidated financial statements.

(2) Reflects the impacts associated with the sale or retirement of generating stations.

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

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

(5) Represents the non-cash amortization of certain debt recorded at fair value at the merger date, which was retired in the second quarter of 2013.

(6) Reflects the non-cash impacts of the remeasurement of state deferred income taxes as a result of the merger.

(7) Primarily reflects the impact of increased planned and unplanned nuclear outage days in 2013, including Salem but excluding Constellation Energy Nuclear Group, LLC (CENG).

(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 Reliability Pricing Model (RPM) for the PJM Interconnection, LLC (PJM) market.

(10) Primarily reflects the impact of decreased realized energy prices and decreased load served.

(11) Reflects the impacts on distribution revenues recorded prior to March 31, 2012, pursuant to the May 2012 order issued by the Illinois Commerce Commission (ICC) on the 2011 performance based formula rate proceeding under the Energy Infrastructure Modernization Act (EIMA).

(12) For ComEd, primarily reflects increased distribution revenue due to recovery of increased costs and capital investment pursuant to the formula rate under EIMA and increased distribution revenue as a result of the May 2013 enactment of Senate Bill 9. For BGE, includes increased distribution revenue pursuant to the February 22, 2013 order for BGE’s 2012 Maryland electric and natural gas distribution rates case and increased cost recovery for energy efficiency and demand response programs (primarily offset in depreciation and amortization expense).

(13) Primarily reflects the impacts of inflation across all operating companies, increased EIMA contracting costs at ComEd, offset in part by realized merger synergies at Generation.

(14) Primarily reflects the impact of lower actuarially assumed discount rates for 2013, partially offset by favorable 2012 asset return experience relative to expectations, and certain 2012 OPEB plan design changes and positive claims experience in 2012. At PECO, also reflects the end of OPEB transition cost amortization in 2012.

(15) Primarily reflects the impact of merger synergy savings for Exelon’s corporate operations and shared service entities, offset in part by the timing of nuclear refueling outage costs related to Generation’s ownership interest in Salem and increased storm costs in the ComEd service territory.

(16) Primarily reflects increased depreciation expense across the operating companies for ongoing capital expenditures. For Generation, also reflects the completion of wind and solar facilities placed in service in the second half of 2012 and in 2013. For ComEd and BGE, also reflects increased regulatory asset amortization related to higher manufactured gas plant (MGP) remediation expenditures and higher costs for energy efficiency and demand response programs (primarily offset by increased other energy delivery revenues), respectively.

(17) 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.

(18) At Generation, primarily reflects an increase in investment tax credit benefits related to the AVSR solar project. At PECO, primarily reflects a benefit for the gas property repairs deduction.

(19) For Generation, primarily reflects increased real estate taxes and higher realized NDT fund gains in 2012.

(20) Reflects the impact of the preferred securities redemption at PECO in the second quarter of 2013.

(21) Reflects a 2013 charge to earnings primarily related to the cancellation of previously capitalized nuclear uprate projects.

10

EXELON CORPORATION (a)

Reconciliation of Adjusted (non-GAAP) Operating

Earnings to GAAP Earnings (in millions)

Six Months Ended June 30, 2013 and 2012

	Exelon
	Earnings per
	Diluted Share			Generation			ComEd			PECO			BGE			Other (b)			Exelon
2012 GAAP Earnings (Loss)	$	0.62		$	334		$	129		$	175		$	(53	)	$	(99	)	$	486
2012 Adjusted (non-GAAP) Operating Earnings (Loss) Adjustments:
Mark-to-Market Impact of Economic Hedging Activities		(0.21	)		(157	)		—			—			—			(10	)		(167	)
Unrealized Gains Related to NDT Fund Investments (1)		(0.02	)		(17	)		—			—			—			—			(17	)
Plant Retirements and Divestitures (2)		0.01			7			—			—			—			—			7
Constellation Merger and Integration Costs (3)		0.23			102			1			7			2			68			180
Maryland Commitments (4)		0.29			22			—			—			83			122			227
Amortization of Commodity Contract Intangibles (5)		0.46			358			—			—			—			—			358
Amortization of the Fair Value of Certain Debt (6)		—			(3	)		—			—			—			—			(3	)
FERC Settlement (7)		0.22			172			—			—			—			—			172
Non-Cash Remeasurement of Deferred Income Taxes (8)		(0.16	)		(13	)		—			—			—			(108	)		(121	)
Other Acquisition Costs		—			3			—			—			—			—			3
2012 Adjusted (non-GAAP) Operating Earnings (Loss)		1.44			808			130			182			32			(27	)		1,125
Year Over Year Effects on Earnings:
Generation Energy Margins, Excluding Mark-to-Market:
Nuclear Volume		—			3			—			—			—			—			3
Nuclear Fuel Costs (9)		(0.03	)		(23	)		—			—			—			—			(23	)
Capacity Pricing (10)		(0.05	)		(42	)		—			—			—			—			(42	)
Market and Portfolio Conditions (11)		0.07			56			—			—			—			—			56
ComEd, PECO and BGE Margins:
Weather		0.03			—			(2	)		29			—	(c)		—			27
Load		—			—			1			(4	)		—	(c)		—			(3	)
Discrete Impacts of the 2012 Distribution Formula Rate Order (12)		0.06			—			52			—			—			—			52
Other Energy Delivery (13)		0.30			—			36			(13	)		234			—			257
Operating and Maintenance Expense:
Labor, Contracting and Materials (14)		(0.19	)		(95	)		(15	)		(6	)		(45	)		—			(161	)
Planned Nuclear Refueling Outages (15)		0.02			15			—			—			—			—			15
Pension and Non-Pension Postretirement Benefits (16)		(0.01	)		(4	)		(7	)		4			(5	)		2			(10	)
Other Operating and Maintenance (17)		(0.07	)		(46	)		(1	)		3			(21	)		1			(64	)
Depreciation and Amortization Expense (18)		(0.16	)		(62	)		(22	)		(4	)		(51	)		(2	)		(141	)
Equity in Earnings of Unconsolidated Affiliates (19)		0.02			18			—			—			—			—			18
Income Taxes (20)		0.07			43			2			12			(3	)		7			61
Interest Expense, Net (21)		(0.03	)		(21	)		8			3			(14	)		(5	)		(29	)
Other (22)		(0.10	)		(41	)		3			(4	)		(31	)		(6	)		(79	)
Preferred Securities Redemption (23)		(0.01	)		—			—			(6	)		—			—			(6	)
Share Differential (24)		(0.13	)		—			—			—			—			—			—
2013 Adjusted (non-GAAP) Operating Earnings (Loss)		1.23			609			185			196			96			(30	)		1,056
2013 Adjusted (non-GAAP) Operating Earnings (Loss) Adjustments:
Mark-to-Market Impact of Economic Hedging Activities		0.02			16			—			—			—			2			18
Unrealized Gains Related to NDT Fund Investments (1)		0.02			14			—			—			—			—			14
Plant Retirements and Divestitures (2)		0.02			13			—			—			—			—			13
Constellation Merger and Integration Costs (3)		(0.05	)		(41	)		—			(3	)		4			(3	)		(43	)
Amortization of Commodity Contract Intangibles (5)		(0.27	)		(232	)		—			—			—			—			(232	)
Amortization of the Fair Value of Certain Debt (6)		0.01			7			—			—			—			—			7
Remeasurement of Like-Kind Exchange Tax Position (25)		(0.31	)		—			(171	)		—			—			(94	)		(265	)
Long-Lived Asset Impairment (26)		(0.10	)		(75	)		—			—			—			(7	)		(82	)
2013 GAAP Earnings (Loss)	$	0.57		$	311		$	14		$	193		$	100		$	(132	)	$	486

(a) For the six months ended June 30, 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 2013 and 2012 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) Reflects the impacts associated with the sale or retirement of generating stations.

(3) Reflects certain costs incurred associated with the merger, including transaction costs, employee-related expenses (e.g. severance, retirement, relocation and retention bonuses) integration initiatives and certain pre-acquisition contingencies, partially offset in 2013 by a one-time benefit pursuant to the February 22, 2013 order for BGE’s 2012 Maryland electric and natural gas distribution rates case for the recovery of previously incurred integration costs.

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

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

(6) Represents the non-cash amortization of certain debt recorded at fair value at the merger date, which was retired in the second quarter of 2013.

(7) 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.

(8) Reflects the non-cash impacts of the remeasurement of state deferred income taxes, primarily as a result of the merger.

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

(10) Primarily reflects the impact of decreased capacity prices related to the RPM for the PJM market, partially offset by the inclusion of Constellation’s financial results for the full period in 2013.

(11) Primarily reflects the inclusion of Constellation’s financial results for the full period in 2013, partially offset by the impact of decreased realized energy prices and decreased load served.

(12) Reflects the impacts on distribution revenues recorded prior to December 31, 2011, pursuant to the May 2012 order issued by the ICC on the 2011 performance based formula rate proceeding under EIMA.

(13) For ComEd, primarily reflects increased distribution revenue due to recovery of increased costs and capital investment pursuant to the formula rate under EIMA and increased distribution revenue as a result of the May 2013 enactment of Senate Bill 9. For PECO, primarily reflects the customer refund in 2013 of the tax cash benefit related to gas property distribution repairs (completely offset in income taxes) and a decrease in gross receipts tax revenue (completely offset in taxes other than income). For BGE, primarily reflects the inclusion of results for the full period in 2013, which includes increased distribution revenue pursuant to the February 22, 2013 order for BGE’s 2012 Maryland electric and natural gas distribution rates case and increased cost recovery for energy efficiency and demand response programs (primarily offset in depreciation and amortization expense).

(14) Primarily reflects the inclusion of Constellation and BGE’s results for the full period in 2013, the impacts of inflation across all operating companies and increased EIMA contracting costs at ComEd, offset in part by the impact of realized merger synergies at Generation.

(15) Primarily reflects the impact of decreased planned nuclear refueling outage days in 2013, excluding Salem and CENG.

(16) Primarily reflects the impact of lower actuarially assumed discount rates for 2013, partially offset by favorable 2012 asset return experience relative to expectations, and certain 2012 OPEB plan design changes and positive claims experience in 2012. At PECO, also reflects the end of OPEB transition cost amortization in 2012.

(17) Primarily reflects the inclusion of Constellation and BGE’s results for the full period in 2013. Also reflects the impact of timing of nuclear refueling outage costs related to Generation’s ownership interest in Salem.

(18) Primarily reflects the inclusion of Constellation and BGE’s results for the full period in 2013 and increased depreciation expense across the operating companies for ongoing capital expenditures. For Generation, also reflects the completion of wind and solar facilities placed in service in the second half of 2012 and in 2013, and the non-cash amortization of intangible assets primarily related to the trade name and retail relationships recorded at fair value at the merger date. For ComEd and BGE, also reflects increased regulatory asset amortization related to higher MGP remediation expenditures and higher costs for energy efficiency and demand response programs (primarily offset by increased other energy delivery revenues), respectively.

(19) 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.

(20) At Generation, primarily reflects an increase in investment tax credit benefits related to the AVSR solar project. At PECO, primarily reflects a benefit for the gas property repairs deduction.

(21) Primarily reflects the inclusion of Constellation and BGE’s results for the full period in 2013. For Generation, also reflects the impact of higher interest expense due to higher outstanding debt during 2013. For ComEd, primarily reflects lower interest expense related to the 1999-2001 IRS settlement.

(22) Primarily reflects the inclusion of Constellation and BGE’s results for the full period in 2013. For PECO, primarily reflects the impact of a 2012 sales and use tax reserve reduction resulting from an audit.

(23) Reflects the impact of the preferred securities redemption at PECO in the second quarter of 2013.

(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) Represents a non-cash charge to earnings resulting from the first quarter 2013 remeasurement of a like-kind exchange tax position taken on ComEd’s 1999 sale of fossil generating assets.

(26) Reflects a 2013 charge to earnings primarily related to the cancellation of previously capitalized nuclear uprate projects.

11

EXELON CORPORATION

Reconciliation of Adjusted (non-GAAP) Operating Earnings to

GAAP Consolidated Statements of Operations

(unaudited)

(in millions)

	Generation
	Three Months Ended June 30, 2013									Three Months Ended June 30, 2012
	GAAP (b)			Adjustments			Adjusted Non-GAAP			GAAP (b)			Adjustments			Adjusted Non-GAAP
Operating revenues	$	4,070		$	(270	)(c),(d)	$	3,800		$	3,765		$	417	(c),(d),(i)	$	4,182
Operating expenses
Purchased power and fuel		1,946			(9	)(c),(d)		1,937			1,852			262	(c),(d),(i)		2,114
Operating and maintenance		1,189			(113	)(e),(f)		1,076			1,178			(83	)(e),(i)		1,095
Depreciation, amortization, accretion and depletion		210			(1	)(e)		209			204			(14	)(e),(i)		190
Taxes other than income		101			—			101			90			(2	)(i)		88
Total operating expenses		3,446			(123	)		3,323			3,324			163			3,487
Equity in loss of unconsolidated affiliates		(21	)		21	(d)		—			(57	)		52	(d),(e)		(5	)
Operating income		603			(126	)		477			384			306			690
Other income and deductions
Interest expense		(93	)		4	(f),(g)		(89	)		(85	)		(5	)(g)		(90	)
Other, net		(33	)		57	(e),(g),(h)		24			(76	)		105	(e),(h),(i)		29
Total other income and deductions		(126	)		61			(65	)		(161	)		100			(61	)
Income before income taxes		477			(65	)		412			223			406			629
Income taxes		149			(8	)(c),(d),(e),(f),(g),(h)		141			58			173	(c),(d),(e),(g),(h),(i)		231
Net income		328			(57	)		271			165			233			398
Net loss attributable to noncontrolling interests		(2	)		—			(2	)		(1	)		—			(1	)
Net income on common stock	$	330		$	(57	)	$	273		$	166		$	233		$	399
	Six Months Ended June 30, 2013									Six Months Ended June 30, 2012 (a)
	GAAP (b)			Adjustments			Adjusted Non-GAAP			GAAP (b)			Adjustments			Adjusted Non-GAAP
Operating revenues	$	7,603		$	558	(c),(d)	$	8,161		$	6,508		$	462	(c),(d),(i)	$	6,970
Operating expenses
Purchased power and fuel		4,114			244	(c),(d)		4,358			2,896			262	(c),(d),(e),(i)		3,158
Operating and maintenance		2,302			(154	)(e),(f),(i)		2,148			2,356			(404	)(d),(e),(i),(j),(k),(l)		1,952
Depreciation, amortization, accretion and depletion		424			(2	)(e)		422			357			(30	)(e),(i)		327
Taxes other than income		194			—			194			164			(3	)(i)		161
Total operating expenses		7,034			88			7,122			5,773			(175	)		5,598
Equity in earnings (loss) of unconsolidated affiliates		(30	)		39	(d)		9			(79	)		60	(d),(e)		(19	)
Operating income		539			509			1,048			656			697			1,353
Other income and deductions
Interest expense		(176	)		2	(e),(f),(g)		(174	)		(138	)		(6	)(g)		(144	)
Other, net		95			(53	)(e),(g),(h),(i)		42			103			(14	)(e),(h),(i)		89
Total other income and deductions		(81	)		(51	)		(132	)		(35	)		(20	)		(55	)
Income before income taxes		458			458			916			621			677			1,298
Income taxes		148			160	(c),(d),(e),(f),(g),(h),(i)		308			289			203	(c),(d),(e),(g),(h),(i),(j),(k),(l),(m)		492
Net income		310			298			608			332			474			806
Net loss attributable to noncontrolling interests		(1	)		—			(1	)		(2	)		—			(2	)
Net income on common stock	$	311		$	298		$	609		$	334		$	474		$	808

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

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

(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) integration initiatives and certain pre-acquisition contingencies.

(f) Adjustment to exclude a 2013 charge to earnings related to Generation’s cancellation of previously capitalized nuclear uprate projects.

(g) Adjustment to exclude the non-cash amortization of certain debt recorded at fair value at the merger date, which was retired in the second quarter of 2013.

(h) Adjustment to exclude the unrealized (gains) losses on NDT fund investments to the extent not offset by contractual accounting as described in the notes to the consolidated financial statements.

(i) Adjustment to exclude the impacts associated with the sale or retirement of generating stations.

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

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

(l) Adjustment to exclude 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.

(m) Adjustment to exclude the non-cash impacts of the remeasurement of state deferred income taxes as a result of the merger.

12

EXELON CORPORATION

Reconciliation of Adjusted (non-GAAP) Operating Earnings to

GAAP Consolidated Statements of Operations

(unaudited)

(in millions)

	ComEd
	Three Months Ended June 30, 2013									Three Months Ended June 30, 2012
	GAAP (a)			Adjustments			Adjusted Non- GAAP			GAAP (a)			Adjustments			Adjusted Non- GAAP
Operating revenues	$	1,080		$	—		$	1,080		$	1,281		$	—		$	1,281
Operating expenses
Purchased power		248			—			248			587			—			587
Operating and maintenance		359			—			359			331			—			331
Depreciation and amortization		170			—			170			152			—			152
Taxes other than income		71			—			71			69			—			69
Total operating expenses		848			—			848			1,139			—			1,139
Operating income		232			—			232			142			—			142
Other income and deductions
Interest expense		(76	)		—			(76	)		(74	)		—			(74	)
Other, net		6			—			6			3			—			3
Total other income and deductions		(70	)		—			(70	)		(71	)		—			(71	)
Income before income taxes		162			—			162			71			—			71
Income taxes		66			—			66			29			—			29
Net income	$	96		$	—		$	96		$	42		$	—		$	42
	Six Months Ended June 30, 2013									Six Months Ended June 30, 2012
	GAAP (a)			Adjustments			Adjusted Non- GAAP			GAAP (a)			Adjustments			Adjusted Non- GAAP
Operating revenues	$	2,239		$	—		$	2,239		$	2,670		$	—		$	2,670
Operating expenses
Purchased power		630			—			630			1,208			—			1,208
Operating and maintenance		687			—			687			650			(2	)(c)		648
Depreciation and amortization		337			—			337			300			—			300
Taxes other than income		145			—			145			144			—			144
Total operating expenses		1,799			—			1,799			2,302			(2	)		2,300
Operating income		440			—			440			368			2			370
Other income and deductions
Interest expense		(429	)		288	(b)		(141	)		(156	)		—			(156	)
Other, net		11			—			11			7			—			7
Total other income and deductions		(418	)		288			(130	)		(149	)		—			(149	)
Income before income taxes		22			288			310			219			2			221
Income taxes		8			117	(b)		125			90			1	(c)		91
Net income	$	14		$	171		$	185		$	129		$	1		$	130

(a) Results reported in accordance with GAAP.

(b) Adjustment to exclude a non-cash charge to earnings resulting from the first quarter 2013 remeasurement of a like-kind exchange tax position taken on ComEd’s 1999 sale of fossil generating assets.

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

13

EXELON CORPORATION

Reconciliation of Adjusted (non-GAAP) Operating Earnings to

GAAP Consolidated Statements of Operations

(unaudited)

(in millions)

	PECO
	Three Months Ended June 30, 2013									Three Months Ended June 30, 2012
	GAAP (a)			Adjustments			Adjusted Non- GAAP			GAAP (a)			Adjustments			Adjusted Non- GAAP
Operating revenues	$	672		$	—		$	672		$	715		$	—		$	715
Operating expenses
Purchased power and fuel		258			—			258			296			—			296
Operating and maintenance		181			(3	)(b)		178			172			(4	)(b)		168
Depreciation and amortization		56			—			56			54			—			54
Taxes other than income		39			—			39			42			—			42
Total operating expenses		534			(3	)		531			564			(4	)		560
Operating income		138			3			141			151			4			155
Other income and deductions
Interest expense		(28	)		—			(28	)		(31	)		—			(31	)
Other, net		—			—			—			2			—			2
Total other income and deductions		(28	)		—			(28	)		(29	)		—			(29	)
Income before income taxes		110			3			113			122			4			126
Income taxes		32			1	(b)		33			42			2	(b)		44
Net income		78			2			80			80			2			82
Preferred security dividends and redemption		6			—			6			1			—			1
Net income on common stock	$	72		$	2		$	74		$	79		$	2		$	81
	Six Months Ended June 30, 2013									Six Months Ended June 30, 2012
	GAAP (a)			Adjustments			Adjusted Non- GAAP			GAAP (a)			Adjustments			Adjusted Non- GAAP
Operating revenues	$	1,567		$	—		$	1,567		$	1,590		$	—		$	1,590
Operating expenses
Purchased power and fuel		664			—			664			707			—			707
Operating and maintenance		369			(5	)(b)		364			375			(10	)(b)		365
Depreciation and amortization		113			—			113			107			—			107
Taxes other than income		80			—			80			74			—			74
Total operating expenses		1,226			(5	)		1,221			1,263			(10	)		1,253
Operating income		341			5			346			327			10			337
Other income and deductions
Interest expense		(57	)		—			(57	)		(62	)		—			(62	)
Other, net		3			—			3			5			—			5
Total other income and deductions		(54	)		—			(54	)		(57	)		—			(57	)
Income before income taxes		287			5			292			270			10			280
Income taxes		87			2	(b)		89			93			3	(b)		96
Net income		200			3			203			177			7			184
Preferred security dividends and redemption		7			—			7			2			—			2
Net income on common stock	$	193		$	3		$	196		$	175		$	7		$	182

(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) integration initiatives and certain pre-acquisition contingencies.

14

EXELON CORPORATION

Reconciliation of Adjusted (non-GAAP) Operating Earnings to

GAAP Consolidated Statements of Operations

(unaudited)

(in millions)

	BGE
	Three Months Ended June 30, 2013									Three Months Ended June 30, 2012
	GAAP (a)			Adjustments			Adjusted Non- GAAP			GAAP (a)			Adjustments			Adjusted Non- GAAP
Operating revenues	$	653		$	—		$	653		$	616		$	—		$	616
Operating expenses
Purchased power and fuel		288			—			288			285			—			285
Operating and maintenance		160			(1	)(b)		159			161			(3	)(b)		158
Depreciation and amortization		82			—			82			71			—			71
Taxes other than income		54			—			54			47			—			47
Total operating expenses		584			(1	)		583			564			(3	)		561
Operating income		69			1			70			52			3			55
Other income and deductions
Interest expense		(32	)		—			(32	)		(34	)		—			(34	)
Other, net		4			—			4			7			—			7
Total other income and deductions		(28	)		—			(28	)		(27	)		—			(27	)
Income before income taxes		41			1			42			25			3			28
Income taxes		16			—	(b)		16			9			2	(b)		11
Net income		25			1			26			16			1			17
Preference stock dividends		3			—			3			3			—			3
Net income on common stock	$	22		$	1		$	23		$	13		$	1		$	14
	Six Months Ended June 30, 2013									March 12, 2012 through June 30, 2012
	GAAP (a)			Adjustments			Adjusted Non- GAAP			GAAP (a)			Adjustments			Adjusted Non- GAAP
Operating revenues	$	1,533		$	—		$	1,533		$	668		$	113	(c)	$	781
Operating expenses
Purchased power and fuel		713			—			713			352			—			352
Operating and maintenance		303			6	(b)		309			222			(32	)(b),(c)		190
Depreciation and amortization		175			—			175			90			—			90
Taxes other than income		109			—			109			57			2	(c)		59
Total operating expenses		1,300			6			1,306			721			(30	)		691
Operating income (loss)		233			(6	)		227			(53	)		143			90
Other income and deductions
Interest expense		(66	)		—			(66	)		(42	)		—			(42	)
Other, net		9			—			9			8			—			8
Total other income and deductions		(57	)		—			(57	)		(34	)		—			(34	)
Income (loss) before income taxes		176			(6	)		170			(87	)		143			56
Income taxes		70			(2	)(b)		68			(38	)		58	(b),(c)		20
Net income (loss)		106			(4	)		102			(49	)		85			36
Preference stock dividends		6			—			6			4			—			4
Net income (loss) on common stock	$	100		$	(4	)	$	96		$	(53	)	$	85		$	32

(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) integration initiatives and certain pre-acquisition contingencies, partially offset in 2013 by a one-time benefit pursuant to the February 22, 2013 order for BGE’s 2012 Maryland electric and natural gas distribution rates case for the recovery of previously incurred integration costs.

(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 June 30, 2013									Three Months Ended June 30, 2012
	GAAP (c)			Adjustments			Adjusted Non- GAAP			GAAP (c)			Adjustments			Adjusted Non- GAAP
Operating revenues	$	(334	)	$	11	(d)	$	(323	)	$	(411	)	$	(5	)(d)	$	(416	)
Operating expenses
Purchased power and fuel		(321	)		—			(321	)		(414	)		—			(414	)
Operating and maintenance		3			(16	)(e),(f)		(13	)		(2	)		(11	)(e)		(13	)
Depreciation and amortization		15			—			15			13			—			13
Taxes other than income		6			—			6			6			—			6
Total operating expenses		(297	)		(16	)		(313	)		(397	)		(11	)		(408	)
Operating loss		(37	)		27			(10	)		(14	)		6			(8	)
Other income and deductions
Interest expense		(23	)		—			(23	)		(32	)		—			(32	)
Other, net		6			—			6			20			—			20
Total other income and deductions		(17	)		—			(17	)		(12	)		—			(12	)
Loss before income taxes		(54	)		27			(27	)		(26	)		6			(20	)
Income taxes		(24	)		9	(d),(e),(f)		(15	)		(12	)		6	(d),(e),(h)		(6	)
Net loss	$	(30	)	$	18		$	(12	)	$	(14	)	$	—		$	(14	)
	Six Months Ended June 30, 2013									Six Months Ended June 30, 2012 (b)
	GAAP (c)			Adjustments			Adjusted Non- GAAP			GAAP (c)			Adjustments			Adjusted Non- GAAP
Operating revenues	$	(719	)	$	(6	)(d)	$	(725	)	$	(780	)	$	(16	)(d)	$	(796	)
Operating expenses
Purchased power and fuel		(721	)		—			(721	)		(792	)		—			(792	)
Operating and maintenance		(5	)		(17	)(e),(f)		(22	)		206			(225	)(e),(i)		(19	)
Depreciation and amortization		27			—			27			22			—			22
Taxes other than income		20			—			20			9			—			9
Total operating expenses		(679	)		(17	)		(696	)		(555	)		(225	)		(780	)
Operating loss		(40	)		11			(29	)		(225	)		209			(16	)
Other income and deductions
Interest expense		(148	)		81	(g)		(67	)		(53	)		—			(53	)
Other, net		37			—			37			29			—			29
Total other income and deductions		(111	)		81			(30	)		(24	)		—			(24	)
Loss before income taxes		(151	)		92			(59	)		(249	)		209			(40	)
Income taxes		(19	)		(10	)(d),(e),(f),(g)		(29	)		(150	)		137	(d),(e),(h),(i)		(13	)
Net loss	$	(132	)	$	102		$	(30	)	$	(99	)	$	72		$	(27	)

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

(b) For the six months ended June 30, 2012, 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) integration initiatives and certain pre-acquisition contingencies.

(f) Adjustment to exclude a 2013 charge to earnings related to the impairment of investment in long-term leases.

(g) Adjustment to exclude a non-cash charge to earnings resulting from the first quarter 2013 remeasurement of a like-kind exchange tax position taken on ComEd’s 1999 sale of fossil generating assets.

(h) Adjustment to exclude the non-cash impacts of the remeasurement of state deferred income taxes as a result of the merger.

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

16

EXELON CORPORATION

Exelon Generation Statistics

	Three Months Ended
	Jun. 30, 2013			Mar. 31, 2013			Dec. 31, 2012			Sep. 30, 2012		Jun. 30, 2012
Supply (in GWhs)
Nuclear Generation (a)
Mid-Atlantic		11,794			12,762			11,547			11,449		12,277
Midwest		22,807			23,269			23,335			23,132		22,860
Total Nuclear Generation		34,601			36,031			34,882			34,581		35,137
Fossil and Renewables (a)
Mid-Atlantic (a)(c)		2,796			3,160			2,154			2,547		2,316
Midwest		318			581			300			171		228
New England		3,132			2,392			2,368			3,953		2,755
ERCOT		1,617			733			755			2,410		2,177
Other (d)		1,431			2,254			1,358			1,813		1,923
Total Fossil and Renewables		9,294			9,120			6,935			10,894		9,399
Purchased Power
Mid-Atlantic (b)		2,616			3,233			4,332			6,811		7,111
Midwest		1,503			1,700			2,661			3,035		1,558
New England		1,365			1,507			2,304			1,961		3,905
New York (b)		3,073			3,511			3,678			4,026		2,818
ERCOT		4,269			4,199			6,043			7,741		6,686
Other (d)		4,998			3,703			4,172			5,372		6,012
Total Purchased Power		17,824			17,853			23,190			28,946		28,090
Total Supply/Sales by Region (f)
Mid-Atlantic (e)		17,206			19,155			18,033			20,807		21,704
Midwest (e)		24,628			25,550			26,296			26,338		24,646
New England		4,497			3,899			4,672			5,914		6,660
New York		3,073			3,511			3,678			4,026		2,818
ERCOT		5,886			4,932			6,798			10,151		8,863
Other (d)		6,429			5,957			5,530			7,185		7,935
Total Supply/Sales by Region		61,719			63,004			65,007			74,421		72,626
	Three Months Ended
	Jun. 30, 2013			Mar. 31, 2013			Dec. 31, 2012			Sep. 30, 2012		Jun. 30, 2012
Average Margin ($/MWh) (g) (h)
Mid-Atlantic (i)	$	44.64		$	44.04		$	48.24		$	43.64	$	40.68
Midwest (i)		27.77			28.08			26.09			27.68		31.00
New England		11.12			7.63			3.64			13.70		9.01
New York		4.56			(6.27	)		4.35			3.23		13.84
ERCOT		19.03			20.54			13.39			15.66		13.43
Other (d)		9.18			7.61			7.96			5.85		4.28
Average Margin - Overall Portfolio	$	27.33		$	27.23		$	26.52		$	25.96	$	26.15
Around-the-clock Market Prices ($/MWh) (j)
PJM West Hub	$	37.63		$	37.53		$	35.94		$	38.13	$	30.40
NiHub		31.77			30.93			28.37			34.29		26.02
New England Mass Hub ATC Spark Spread		4.96			(6.63	)		3.07			12.69		7.77
NYPP Zone A		34.38			40.23			34.70			34.56		27.87
ERCOT North Spark Spread		(0.20	)		(0.66	)		(0.27	)		3.60		6.01
	Three Months Ended
	Jun. 30, 2013			Mar. 31, 2013			Dec. 31, 2012			Sep. 30, 2012		Jun. 30, 2012
Outage Days (k)
Refueling		47			49			113			43		51
Non-refueling		31			6			1			40		16
Total Outage Days		78			55			114			83		67

(a) 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).

(b) Purchased power includes physical volumes of 3,114 GWhs, 2,588 GWhs, 3,255 GWhs, 3,126 GWhs and 3,225 GWhs in the Mid-Atlantic and 2,655 GWhs, 3,213 GWhs, 2,814 GWhs, 2,997 GWhs and 2,817 GWhs in New York as a result of the PPA with CENG for the three months ended June 30, 2013, March 31, 2013, December 31, 2012, September, 30, 2012 and June 30, 2012, respectively.

(c) 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.

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

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

(f) Total sales do not include physical trading volumes of 1,995 GWhs, 1,572 GWhs, 2,977 GWhs, 4,352 GWhs and 4,248 GWhs for the three months ended June 30, 2013, March 31, 2013, December 31, 2012, September 30, 2012 and June 30, 2012, respectively.

(g) 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.

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

(i) 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.

(j) Represents the average for the quarter.

(k) Outage days exclude Salem and CENG.

17

EXELON CORPORATION

Exelon Generation Statistics

Six Months Ended June 30, 2013 and 2012

	June 30, 2013			June 30, 2012 (a)
Supply (in GWhs)
Nuclear Generation (b)
Mid-Atlantic		24,556			24,341
Midwest		46,076			46,058
Total Nuclear Generation		70,632			70,399
Fossil and Renewables (b)
Mid-Atlantic (b)(d)		5,956			4,107
Midwest		899			500
New England		5,524			3,644
ERCOT		2,350			3,017
Other (e)		3,685			2,742
Total Fossil and Renewables		18,414			14,010
Purchased Power
Mid-Atlantic (c)		5,849			9,688
Midwest		3,203			4,110
New England		2,872			5,005
New York (c)		6,584			3,753
ERCOT		8,468			9,518
Other (e)		8,701			7,781
Total Purchased Power		35,677			39,855
Total Supply/Sales by Region (g)
Mid-Atlantic (f)		36,361			38,136
Midwest (f)		50,178			50,668
New England		8,396			8,649
New York		6,584			3,753
ERCOT		10,818			12,535
Other (e)		12,386			10,523
Total Supply/Sales by Region		124,723			124,264
	June 30, 2013			June 30, 2012 (a)
Average Margin ($/MWh) (h) (i)
Mid-Atlantic (j)	$	44.33		$	43.35
Midwest (j)		27.92			31.20
New England		9.53			11.45
New York		(1.22	)		12.52
ERCOT		19.69			12.21
Other (e)		8.48			4.56
Average Margin - Overall Portfolio	$	27.28		$	28.82
Around-the-clock Market Prices ($/MWh) (k)
PJM West Hub	$	37.41		$	30.75
NiHub		31.31			26.57
NEPOOL Mass Hub		(1.36	)		6.17
NYPP Zone A		37.08			29.55
ERCOT North Spark Spread		(0.46	)		4.78

(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 5,702 GWhs and 3,544 GWhs in the Mid-Atlantic, and 5,868 GWhs and 3,539 GWhs in New York as a result of the PPA with CENG for the six months ended June 30, 2013 and 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 2012 as a result of the Exelon and Constellation merger.

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

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

(g) Total sales do not include physical proprietary trading volumes of 3,567 GWhs and 6,077 GWhs for the six months ended June 30, 2013 and 2012, respectively.

(h) 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.

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

(j) 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.

(k) Represents the average for the six months ended June 30, 2013 and 2012

18

EXELON CORPORATION

ComEd Statistics

Three Months Ended June 30, 2013 and 2012

	Electric Deliveries (in GWhs)										Revenue (in millions)
	2013		2012		% Change			Weather- Normal %  Change			2013		2012		% Change
Retail Deliveries and Sales (a)
Residential		6,090		6,674		(8.8	)%		1.1	%	$	476	$	720		(33.9	)%
Small Commercial & Industrial		7,832		7,888		(0.7	)%		2.2	%		315		306		2.9	%
Large Commercial & Industrial		6,711		6,839		(1.9	)%		(0.6	)%		113		94		20.2	%
Public Authorities & Electric Railroads		294		293		0.3	%		4.0	%		12		9		33.3	%
Total Retail		20,927		21,694		(3.5	)%		1.0	%		916		1,129		(18.9	)%
Other Revenue (b)												164		152		7.9	%
Total Electric Revenue											$	1,080	$	1,281		(15.7	)%
Purchased Power											$	248	$	587		(57.8	)%

							% Change
Heating and Cooling Degree-Days	2013		2012		Normal		From 2012			From Normal
Heating Degree-Days		778		544		765		43.0	%		1.7	%
Cooling Degree-Days		240		423		218		(43.3	)%		10.1	%

Six Months Ended June 30, 2013 and 2012

	Electric Deliveries (in GWhs)										Revenue (in millions)
	2013		2012		% Change			Weather- Normal % Change			2013		2012		% Change
Retail Deliveries and Sales (a)
Residential		12,966		13,080		(0.9	)%		0.5	%	$	1,060	$	1,496		(29.1	)%
Small Commercial & Industrial		15,705		15,804		(0.6	)%		(0.6	)%		623		654		(4.7	)%
Large Commercial & Industrial		13,551		13,542		0.1	%		(0.5	)%		215		194		10.8	%
Public Authorities & Electric Railroads		667		617		8.1	%		11.6	%		24		21		14.3	%
Total Retail		42,889		43,043		(0.4	)%		(0.2	)%		1,922		2,365		(18.7	)%
Other Revenue (b)												317		305		3.9	%
Total Electric Revenue											$	2,239	$	2,670		(16.1	)%
Purchased Power											$	630	$	1,208		(47.8	)%

							% Change
Heating and Cooling Degree-Days	2013		2012		Normal		From 2012			From Normal
Heating Degree-Days		4,037		2,928		3,929		37.9	%		2.7	%
Cooling Degree-Days		240		462		218		(48.1	)%		10.1	%

Number of Electric Customers	2013		2012
Residential		3,465,712		3,456,312
Small Commercial & Industrial		366,153		365,474
Large Commercial & Industrial		2,006		1,990
Public Authorities & Electric Railroads		4,852		4,793
Total		3,838,723		3,828,569

(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 rental revenues, revenues related to late payment charges, assistance provided to other utilities through mutual assistance programs, and recoveries of environmental costs associated with MGP sites.

19

EXELON CORPORATION

PECO Statistics

Three Months Ended June 30, 2013 and 2012

	Electric and Gas Deliveries										Revenue (in millions)
	2013		2012		% Change			Weather- Normal % Change			2013		2012		% Change
Electric (in GWhs)
Retail Deliveries and Sales (a)
Residential		2,888		2,929		(1.4	)%		(0.8	)%	$	354	$	393		(9.9	)%
Small Commercial & Industrial		1,960		1,959		0.1	%		0.9	%		109		119		(8.4	)%
Large Commercial & Industrial		3,784		3,743		1.1	%		1.9	%		61		59		3.4	%
Public Authorities & Electric Railroads		238		237		0.4	%		0.4	%		8		8		0.0	%
Total Retail		8,870		8,868		0.0	%		0.8	%		532		579		(8.1	)%
Other Revenue (b)												53		56		(5.4	)%
Total Electric Revenue												585		635		(7.9	)%
Gas (in mmcfs)
Retail Deliveries and Sales
Retail Sales (c)		6,919		6,228		11.1	%		0.6	%		78		73		6.8	%
Transportation and Other		5,956		5,835		2.1	%		3.5	%		9		7		28.6	%
Total Gas		12,875		12,063		6.7	%		1.8	%		87		80		8.8	%
Total Electric and Gas Revenues											$	672	$	715		(6.0	)%
Purchased Power and Fuel											$	258	$	296		(12.8	)%

							% Change
Heating and Cooling Degree-Days	2013		2012		Normal		From 2012			From Normal
Heating Degree-Days		421		337		463		24.9	%		(9.1	)%
Cooling Degree-Days		418		430		348		(2.8	)%		20.1	%

Six Months Ended June 30, 2013 and 2012

	Electric and Gas Deliveries										Revenue (in millions)
	2013		2012		% Change			Weather- Normal % Change			2013		2012		% Change
Electric (in GWhs)
Retail Deliveries and Sales (a)
Residential		6,353		6,095		4.2	%		(0.1	)%	$	749	$	800		(6.4	)%
Small Commercial & Industrial		3,969		3,910		1.5	%		(1.9	)%		215		237		(9.3	)%
Large Commercial & Industrial		7,430		7,380		0.7	%		1.7	%		120		113		6.2	%
Public Authorities & Electric Railroads		493		474		4.0	%		4.0	%		16		16		0.0	%
Total Retail		18,245		17,859		2.2	%		0.4	%		1,100		1,166		(5.7	)%
Other Revenue (b)												108		112		(3.6	)%
Total Electric Revenue												1,208		1,278		(5.5	)%
Gas (in mmcfs)
Retail Deliveries and Sales
Retail Sales (c)		35,357		28,655		23.4	%		(0.2	)%		338		295		14.6	%
Transportation and Other		14,839		13,601		9.1	%		2.3	%		21		17		23.5	%
Total Gas		50,196		42,256		18.8	%		0.5	%		359		312		15.1	%
Total Electric and Gas Revenues											$	1,567	$	1,590		(1.4	)%
Purchased Power and Fuel											$	664	$	707		(6.1	)%

							% Change
Heating and Cooling Degree-Days	2013		2012		Normal		From 2012			From Normal
Heating Degree-Days		2,861		2,251		2,939		27.1	%		(2.7	)%
Cooling Degree-Days		418		434		348		(3.7	)%		20.1	%

Number of Electric Customers	2013		2012		Number of Gas Customers	2013		2012
Residential		1,419,977		1,417,346	Residential		455,518		452,478
Small Commercial & Industrial		148,723		148,837	Commercial & Industrial		41,648		41,383
Large Commercial & Industrial		3,109		3,107	Total Retail		497,166		493,861
Public Authorities & Electric Railroads		9,672		9,680	Transportation		903		888
Total		1,581,481		1,578,970	Total		498,069		494,749

(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 June 30, 2013 and 2012

	Electric and Gas Deliveries							Revenue (in millions)
	2013		2012		% Change			2013		2012		% Change
Electric (in GWhs)
Retail Deliveries and Sales (a)
Residential		2,757		2,664		3.5	%	$	302	$	295		2.4	%
Small Commercial & Industrial		716		706		1.4	%		60		60		0.0	%
Large Commercial & Industrial		3,610		3,942		(8.4	)%		112		99		13.1	%
Public Authorities & Electric Railroads		80		71		12.7	%		8		7		14.3	%
Total Retail		7,163		7,383		(3.0	)%		482		461		4.6	%
Other Revenue (b)									61		57		7.0	%
Total Electric Revenue									543		518		4.8	%
Gas (in mmcfs)
Retail Deliveries and Sales (c)
Retail Sales		14,951		15,535		(3.8	)%		100		84		19.0	%
Transportation and Other (d)		1,545		4,854		(68.2	)%		10		14		(28.6	)%
Total Gas		16,496		20,389		(19.1	)%		110		98		12.2	%
Total Electric and Gas Revenues								$	653	$	616		6.0	%
Purchased Power and Fuel								$	288	$	285		1.1	%

							% Change
Heating and Cooling Degree-Days	2013		2012		Normal		From 2012			From Normal
Heating Degree-Days		492		402		517		22.4	%		(4.8	)%
Cooling Degree-Days		263		289		250		(9.0	)%		5.2	%

Six Months Ended June 30, 2013 and March 12, 2012 Through June 30, 2012

	Electric and Gas Deliveries						Revenue (in millions)
	2013		2012		% Change		2013		2012		% Change
Electric (in GWhs)
Retail Deliveries and Sales (a)
Residential		6,293		3,279		n.m.	$	667	$	282		n.m.
Small Commercial & Industrial		1,492		849		n.m.		125		72		n.m.
Large Commercial & Industrial		7,164		4,785		n.m.		217		120		n.m.
Public Authorities & Electric Railroads		161		96		n.m.		15		10		n.m.
Total Retail		15,110		9,009		n.m.		1,024		484		n.m.
Other Revenue (b)								124		74		n.m.
Total Electric Revenue								1,148		558		n.m.
Gas (in mmcfs)
Retail Deliveries and Sales (c)
Retail Sales		55,212		20,402		n.m.		345		90		n.m.
Transportation and Other (d)		7,195		6,764		n.m.		40		20		n.m.
Total Gas		62,407		27,166		n.m.		385		110		n.m.
Total Electric and Gas Revenues							$	1,533	$	668		n.m.
Purchased Power and Fuel							$	713	$	352		n.m.

							% Change
Heating and Cooling Degree-Days	2013		2012		Normal		From 2012		From Normal
Heating Degree-Days		2,943		2,119		2,902		n.m.		1.4	%
Cooling Degree-Days		264		289		250		n.m.		5.6	%

Number of Electric Customers	2013		2012		Number of Gas Customers	2013		2012
Residential		1,117,569		1,115,107	Residential		611,146		610,073
Small Commercial & Industrial		113,009		113,232	Commercial & Industrial		44,059		44,011
Large Commercial & Industrial		11,612		11,537	Total Retail		655,205		654,084
Public Authorities & Electric Railroads		294		297	Transportation		—		—
Total		1,242,484		1,240,173	Total		655,205		654,084

(a) Reflects delivery volumes and revenues from customers purchasing electricity directly from BGE and customers purchasing electricity 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 1,545 mmcfs ($8 million) and 4,854 mmcfs ($12 million) for the three months ended June 30, 2013 and 2012, respectively, and 7,195 mmcfs ($32 million) and 6,764 mmcfs ($17 million) for the six months ended June 30, 2013 and from March 12, 2012 through June 30, 2012, respectively.

21

EX-99.2

Earnings Conference Call

2  

Quarter 2013

July

31  ,

2013

Exhibit 99.2

nd

st

Cautionary Statements Regarding

Forward-Looking Information

1

2013 2Q 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 2012 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 19; (2) Exelon’s First Quarter 2013 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 17; and (3) 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 press 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 presentation.

2013 2Q Earnings Release Slides

•

Current 5-year plan includes $16B of 

growth CapEx (~$13.5B at Utilities)

•

Installed 99 MW at AVSR YTD with 

another 102 MW to come on line in 2013

•

Adding 46 MW to wind portfolio in 2014 

with the Beebe 1B project

•

Continued smart meter installation at 

PECO, BGE and ComEd

•

2Q13 nuclear capacity factor of 92.8%

and YTD 2013 capacity factor of 94.6%

•

Entered into agreement with EDF to

operate the CENG plants

•

Dispatch match rate for fossil and hydro

fleet of 99.1% and energy capture rate

for wind and solar fleet of 92.4%

•

Top decile safety performance for

ComEd, PECO and BGE

•

SB9 was enacted clarifying language in

EIMA.  ComEd made annual filing for

distribution with ICC

•

BGE filed a rate case in May with the

MDPSC

•

Engaged in PJM stakeholder process

around RPM

•

Delivered 2Q earnings within our

guidance range

•

Canceled LaSalle and Limerick EPU

projects

•

On track to achieve $550M of annual

run-rate merger synergies by 2014

•

Identified additional O&M savings at

ExGen

2013 2Q Earnings Release Slides

2

2Q13 In Review

2013 Expectations:

•

Deliver

3Q13

operating

earnings

within

guidance

range

of

$0.60

-

$0.70/share

(1)

•

On-track

to

achieve

full-year

operating

earnings

within

guidance

range

of

$2.35

-

$2.65/share

(1)

as

disclosed on 4Q12 earnings call

(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.

Financial

Discipline

Operational

Excellence

Opportunistic

Growth &

Investment

Regulatory

Advocacy

AVSR = Antelope Valley Solar Ranch.  EIMA = Energy Infrastructure Modernization Act.   EPU = Extended Power Uprate.  ICC = Illinois Commerce Commission.  MDPSC = Maryland Public Service 

Commission. O&M = Operating  & Maintenance.  RPM = Reliability Pricing Model.

RPM Results

3

Coal

Fired

Gen-BRA

Offers

(2)

(GW)

%

of

Unforced

Capacity

Procured

by

Type

(1)

16/17

59

49

15/16

59

54

14/15

65

56

13/14

67

65

2

Cleared

Uncleared

RPM Clearing Trends

(1)

Sources: (1) PJM RPM Base Residual Auction Results Reports (2) RPM Commitments by Fuel

Type by DY

(2)

Estimated

based

on

PY

16/17

PJM

Base

Residual

Auction

Results.

Includes

imports.

For

comparability, PJM geographical additions included by adding initial BRA offered and cleared

quantities to previous years.

Total

GW

•

Decrease in existing coal-fired

generation

•

6.3 GW of coal retirements in 2012

alone

•

10 GW in the PJM deactivation queue

for 2013 -

2015

•

Internal estimate: ~ 22 GW for 2012 -

2016

•

Increase in planned gas-fired

generation

•

Increase in cleared GW of Energy

Efficiency (EE), Demand Response

(DR), and Imports

95%

85%

90%

100%

80%

0%

169

79%

9%

12%

15/16

165

84%

16/17

14/15

150

87%

1%

5%

153

90%

1%

9%

13/14

Existing Gen as of 13/14 (incl. Wind)

Cumulative New/Gen Uprates since 13/14

Cleared EE, DR and Imports Combined

Recommended Reserve Margin (~15.6%)

12%

12%

9

5

10

2013 2Q Earnings Release Slides

BRA = Base Residual Auction. RPM = Reliability Pricing Model. PY = Plan Year.

Notes: (1) PY 13/14 includes ATSI (2) PY 14/15 includes Duke  (3) PY 15/16 includes significant portion

of AEP and DEOK zone load previously under FRR alternative  (4) PY 16/17 includes EKPC (5) PY 13/14

is base year for cumulative New Gen and Uprates

Hedging Activity and Market Fundamentals

4

2013 2Q Earnings Release Slides

Fundamental

View

vs.

Market

-

2015

%

of

Expected

Generation

Hedged

(1)

-

Total

Portfolio

(1)

Mid-point of disclosed hedge % range was used

$60

$55

$50

$45

$40

$35

$15

1Q13

3Q12

1Q12

3Q11

1Q11

2Q13

1Q13

4Q12

3Q12

2015-Ratable

2015-Actual

2015-Actual (excl NG hedges)

Market PJMW

Fundamental View PJMW

Market NiHub

Fundamental View NiHub

50%

45%

40%

35%

30%

25%

15%

20%

•

Structural changes in the stack are expected to increase volatility in the spot energy market and drive prices

higher than current market

•

Continue to see a disconnect in forward heat rates compared to our fundamental forecast given current

natural gas prices, expected retirements, new generation resources, and load assumptions

•

We align our hedging  strategies with our fundamental views

•

We have widened our deviation from ratable across our entire portfolio over the past 6 months to

approximately 8%

•

Use of natural gas as a cross-commodity hedge leaves more upside to heat rate expansion

Market Fundamentals

Impacts of our view on our hedging activity

2013 2Q Earnings Release Slides

Exelon Generation: Gross Margin Update

June 30, 2013

Delta to March 31, 2013

Gross

Margin

Category

($M)

(1)

(2)

2013

2014

2015

2013

2014

2015

Open Gross Margin

(3)

(including South, West, Canada hedged gross margin)

5,750

5,700

5,900

(250)

(650)

(500)

Mark-to-Market

of

Hedges

(3,4)

1,450

850

400

250

450

150

Power New Business / To Go

200

550

750

(150)

(50)

(50)

Non-Power Margins Executed

350

150

50

50

50

0

Non-Power

New

Business

/

To

Go

(5)

250

450

550

(50)

(50)

0

Total Gross Margin

8,000

7,700

7,650

(150)

(250)

(400)

Key Changes in 2Q 2013

•

2013:

AVSR delays; $50M due to FTR under collection; and $50M due to

lower power new business targets

•

2014:

power new business targets

•

2015:

power new business targets

•

Reducing 2013 ExGen O&M by $100M ($50M at Constellation to

offset lower new business targets) and targeting reductions in

2014 and 2015 to result in a roughly flat O&M CAGR for 2013 -

2015

2013 2Q Earnings Release Slides

Retail & Wholesale Load (TWh)

30-40%

60-70%

150

155

2013E

25-35%

155

2015E

2014E

25-35%

Wholesale Load

Total Contracted

Retail Load

65-75%

65-75%

Numbers and percentages are rounded to the nearest 5.

Index load expected to be 20% to 30% of total forecasted retail load.

5

Reduction of $50M due to unplanned nuclear outages and

$350M reduction due to prices and $50M reduction in

$200M reduction due to prices and $50M reduction in

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.

5)

Any changes to new business estimates for our non-power business are presented as

revenue less costs of sales.

200

150

100

50

0

FTR = Financial Transmission Rights.

CAGR = Compound Annual Growth Rate.

Key Financial Messages

6

2013 2Q Earnings Release Slides

•

Delivered non-GAAP operating earnings   

in 2Q

of $0.53/share within guidance range

provided of $0.50 -

$0.60/share

2Q 2013 vs. Guidance

•

Reduction of wholesale new business targets

and unplanned nuclear outages

•

Favorable impacts of SB9 at ComEd

Full Year 2013 vs. Guidance

•

Reduction of wholesale new business targets

•

Reduction of 2013 ExGen O&M by $100M

•

Favorable load at ComEd and PECO

•

Lower ExGen effective tax rate

•

Favorable interest related to tax positions

•

Favorable impacts of SB9 at ComEd

•

Lower depreciation and other favorable items at

ExGen

$0.32

$0.11

$0.09

$0.53

($0.01)

$0.03

HoldCo

ExGen

ComEd

PECO

BGE

2013 2Q Results

Expect 3Q 2013 earnings of $0.60 -

$0.70/share and re-affirm full year guidance

range of $2.35-$2.65/share

2013 2Q Earnings Release Slides

(1)

(1)

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

Numbers may not add due to rounding. SB9 = Senate Bill 9.

ExGen Operating EPS Contribution

7

2013 2Q Earnings Release Slides

$0.47

$0.32

2Q

2013

2012

(excludes Salem and CENG)

2Q12

Actual

2Q13

Actual

Planned Refueling Outage Days

51

47

Non-refueling Outage Days

16

31

Nuclear Capacity Factor

93.4%

92.8%

Lower RNF, primarily due to lower realized

energy prices, lower capacity pricing and

decreased load volumes: $(0.15)

Increased depreciation expense related to

ongoing capital expenditures: $(0.01)

Lower O&M costs, primarily due to merger

synergies, offset in part by timing of Salem

nuclear refueling outage costs: $0.01

Lower income tax, primarily driven by AVSR

investment tax credit benefits: $0.01

(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.

Key

Drivers

–

2Q13

vs.

2Q12

(1)

RNF = Revenue Net Fuel.

Exelon Utilities Operating EPS Contribution

8

2013 2Q Earnings Release Slides

2Q 2013

2Q 2012

$0.05

$0.11

$0.09

$0.16

$0.10

$0.02

$0.03

$0.22

BGE

PECO

ComEd

Weather

(2)

: $(0.02)

Higher distribution revenue due to higher allowed

ROE

(2)

: $0.01

Impact of Senate Bill 9: $0.01

Discrete impacts of the May 2012 distribution formula

rate order under EIMA

(3)

: $0.07

Higher O&M costs, primarily due to inflation: $(0.01)

Preferred securities redemption: $(0.01)

Lower income tax, primarily due to gas distribution tax

repairs deduction: $0.01

Electric and gas distribution rates: $0.02

PECO

(-0.01):

BGE

(+0.01):

ComEd: (+0.06)

Key

Drivers

–

2Q13

vs.

2Q12

(1):

Numbers may not add due to rounding.

(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)

Due to the distribution formula rate, changes in ComEd’s earnings are driven primarily by changes in 30-year U.S. Treasury rates (allowed ROE), rate base and capital structure in

addition to weather, load and changes in customer mix.

(3)

Energy Infrastructure Modernization Act

2013 Projected Sources and Uses of Cash

(1)

Exelon beginning cash balance as of  1/1/13. 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)

Includes PECO’s $210 million Accounts Receivable (A/R) Agreement with Bank of Tokyo and excludes BGE’s current portion of its rate stabilization

bonds

(5)

“Other”

includes proceeds from options, redemption of PECO preferred stock and expected changes in short-term debt.

(6)

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

9

2013 2Q Earnings Release Slides

10

Exelon Generation Disclosures

June 30, 2013

2013 2Q Earnings Release Slides

2013 2Q 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

2013 2Q Earnings Release Slides

•

Aligns hedging program with

financial policies and financial

outlook

•

Establish minimum hedge targets

•

Hedge enough commodity risk to

•

Ensure stability in near-term cash

•

Disciplined approach to hedging

•

Tenor aligns with customer

•

Multiple channels to market that

•

Large open position in outer years

•

Ability to exercise fundamental

market views to create value within

the ratable framework

•

Modified timing of hedges versus

•

Cross-commodity hedging (heat

•

Delivery locations, regional and

Strategic Policy Alignment

Three-Year Ratable Hedging

Bull / Bear Program

Credit Rating

Capital

Structure

Capital &

Operating

Expenditure

Dividend

to meet financial objectives of the

company (dividend, credit rating)

meet future cash requirements

under a stress scenario

flows and earnings

preferences and market liquidity

allow us to maximize margins

to benefit from price upside

purely ratable

rate positions, options, etc.)

zonal spread relationships

2013 2Q Earnings Release Slides

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

2013 2Q Earnings Release Slides

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

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

(1)

(2)

(3)

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.

Open Gross

Margin

MtM of

Hedges

(2)

“Power”

New

Business

“Non Power”

Executed

“Non Power”

New Business

•Generation Gross

Margin at current

market prices,

including capacity

and ancillary

revenues, nuclear

fuel amortization

and fossils fuels

expense

•Exploration and

Production

•Power Purchase

Agreement (PPA)

Costs and

Revenues

•Provided at a

consolidated level

for all regions

(includes hedged

gross margin for

South, West and

Canada

(1)

)

•Mark to Market

(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

Effective Realized

Energy Price

(EREP), reference

price, hedge %,

expected

generation

•Retail, Wholesale

planned electric

sales

•Portfolio

Management new

business

•Mid marketing new

business

•Retail, Wholesale 

executed gas sales

•Load Response

•Energy Efficiency

•BGE Home

•Distributed Solar

•Retail, Wholesale

planned gas sales

•Load Response

•Energy Efficiency

•BGE Home

•Distributed Solar

•Portfolio

Management /

origination fuels

new business

•Proprietary

trading

(3)

2013 2Q Earnings Release Slides

ExGen Disclosures 

Gross Margin Category ($M)

(1,2)

2013

2014

2015

Open Gross Margin

(including South, West & Canada hedged GM)

(3)

$5,750

$5,700

$5,900

Mark to Market of Hedges

(3,4)

$1,450

$850

$400

Power New Business / To Go

$200

$550

$750

Non-Power Margins Executed

$350

$150

$50

Non-Power New Business / To Go

(5)

$250

$450

$550

Total Gross Margin

$8,000

$7,700

$7,650

Reference Prices

(6)

2013

2014

2015

Henry Hub Natural Gas ($/MMbtu)

$3.68

$3.91

$4.14

Midwest: NiHub ATC prices ($/MWh)

$31.00

$29.90

$31.04

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

$37.76

$37.26

$38.53

ERCOT-N ATC Spark Spread ($/MWh)

HSC Gas, 7.2HR, $2.50 VOM

$4.93

$7.90

$8.76

New York: NY Zone A ($/MWh)

$36.82

$35.40

$36.22

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

ALQN Gas, 7.5HR, $0.50 VOM

$3.03

$4.59

$3.02

2013 2Q Earnings Release Slides

13

(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.

(5)

Any changes to new business estimates for our non-power business are presented as

revenue less costs of sales.

(6)

Based on June 30, 2013 market conditions.

14

ExGen Disclosures

Generation and Hedges

2013

2014

2015

Exp. Gen (GWh)

(1)

215,500

214,400

207,600

Midwest

97,200

97,100

96,400

Mid-Atlantic

(2)

74,200

72,600

69,900

ERCOT

14,600

17,800

18,500

New York

(2)

14,100

12,100

9,300

New England

15,400

14,800

13,500

% of Expected Generation Hedged

(3)

96-99%

78-81%

41-44%

Midwest

95-98%

77-80%

38-41%

Mid-Atlantic

(2)

97-100%

82-85%

48-51%

ERCOT

102-105%

77-80%

34-37%

New York

(2)

96-99%

81-84%

45-48%

New England

97-100%

71-74%

23-26%

Effective Realized Energy Price ($/MWh)

(4)

Midwest

$37.00

$34.00

$34.00

Mid-Atlantic

(2)

$49.00

$46.00

$46.50

ERCOT

(5)

$11.50

$9.00

$7.50

New York

(2)

$32.00

$37.00

$44.00

New England

(5)

$5.50

$3.50

$3.50

2013 2Q 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  93.8%, 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 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.

2013 2Q Earnings Release Slides

15

ExGen Hedged Gross Margin Sensitivities

Gross Margin Sensitivities (With Existing Hedges) 

(1, 2)

2013

2014

2015

Henry Hub Natural Gas ($/Mmbtu)

$35

$190

$430

$(20)

$(130)

$(370)

NiHub ATC Energy Price

$10

$130

$355

$(5)

$(125)

$(350)

PJM-W ATC Energy Price

$0

$75

$205

$5

$(75)

$(200)

NYPP Zone A ATC Energy Price

$0

$10

$25

$0

$(10)

$(25)

Nuclear Capacity Factor

(3)

+/-

1%

+/-

$20

+/-

$40

+/-

$45

2013 2Q Earnings Release Slides

(1) Based on June 30, 2013 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.

+ $1/Mmbtu

-

$1/Mmbtu

+ $5/MWh

-

$5/MWh

+ $5/MWh

-

$5/MWh

+ $5/MWh

-

$5/MWh

2013 2Q Earnings Release Slides

16

Exelon Generation Hedged Gross Margin Upside/Risk

$6,000

$6,500

$7,000

$7,500

$8,000

$8,500

$9,000

$9,500

$10,000

2015

$8,700

2014

$8,150

2013

$8,150

$7,850

$7,250

$6,750

(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 June 30, 2013

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

2013 2Q Earnings Release Slides

17

Illustrative Example of Modeling Exelon Generation             

2014 Gross Margin

Row

Item

Midwest

Mid-

Atlantic

ERCOT

New York

New

England

South,

West &

Canada

(A)

Start with fleet-wide open gross margin 

$5.70 billion

(B)

Expected Generation (TWh)

97.1

72.6

17.8

12.1

14.8

(C)

Hedge % (assuming mid-point of range)

78.5%

83.5%

78.5%

82.5%

72.5%

(D=B*C)

Hedged Volume (TWh)

76.2

60.6

14.0

10.0

10.7

(E)

Effective Realized Energy Price ($/MWh)

$34.00

$46.00

$9.00

$37.00

$3.50

(F)

Reference Price ($/MWh)

$29.90

$37.26

$7.90

$35.40

$4.59

(G=E-F)

Difference ($/MWh)

$4.10

$8.74

$1.10

$1.60

$(1.09)

(H=D*G)

Mark-to-market

value

of

hedges

($

million)

(1)

$315 million

$530 million

$15 million

$15 million

$(10) million

(I=A+H)

Hedged Gross Margin ($ million)

$6,550 million

(J)

Power New Business / To Go ($ million)

$550 million

(K)

Non-Power Margins Executed ($ million)

$150 million

(L)

Non-

Power New Business / To Go ($ million)

$450 million

(N=I+J+K+L)

Total Gross Margin

$7,700 million

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

2013 2Q Earnings Release Slides

18

Additional Disclosures

2013 2Q Earnings Release Slides

BGE

2013 load growth largely

driven by the idling of RG Steel

and

energy efficiency partially

offset by improving economic

conditions

19

Exelon Utilities Weather-Normalized Load

2013E

0.4%

0.2%

2012

0.2%

-0.6%

-0.1%

Large C&I

Small C&I

Residential

All Customers

Notes: Data is not adjusted for leap year.  Source of 2013 economic outlook data is Global Insight (May 2013).    Assumes 2013 GDP of 1.8% and U.S unemployment of 7.6%.

ComEd has the ROE collar as part of the distribution formula rate and BGE is decoupled which mitigates the load risk.  QTD and YTD actual data can be found in earnings release tables.

BGE  amounts have been adjusted for unbilled / true-up load from prior quarters.

ComEd

2013 load growth is similar to

2012, driven by improving

economic conditions & positive

residential load growth partially

offset by energy efficiency

2013E

1.7%

0.5%

2012

-2.3%

-2.2%

PECO

2013 load growth driven by oil

refinery and economic

conditions & customer growth,

offset by energy efficiency

2013E

-2.5%

-1.0%

2012

-2.8%

-1.5%

Chicago GMP

1.7%

Chicago Unemployment

9.4%

Philadelphia GMP

1.7%

Philadelphia Unemployment

7.9%

Baltimore GMP

1.8%

Baltimore Unemployment

7.3%

2013 2Q Earnings Release Slides

0.8%

-0.3%

-0.6%

0.4%

-1.7%

-2.7%

-2.3%

-2.1%

-0.2%

0.4%

0.9%

20

Exelon Utilities Rate Base and ROE Targets

2013E

Long-Term Target

Equity Ratio

~50%

~53%

(3)

Earned ROE

7-8%

2013E

Long-Term Target

Equity Ratio

~46%

~53%

(1)

Earned ROE

8 -9%

Continued investment in Utilities will provide stable earnings growth

Based on 30-yr.

US Treasury

(2)

($ in billions)

$1.1

$0.7

$1.1

2012

$5.1

$3.3

$0.7

$5.9

$3.9

2015E

$1.3

$0.7

$1.2

2013E

$5.3

$3.5

2014E

$5.7

$3.8

$0.7

Electric Distribution

Electric Transmission

Gas Delivery

$2.1

$7.6

$2.7

2014E

$8.7

$7.1

$2.3

2013E

$9.4

$6.6

$10.3

$6.4

2015E

$8.5

$2.1

2012

Transmission

Distribution

$5.1

$3.2

$0.6

$4.4

$0.7

$1.1

$1.2

2013E

$3.0

2014E

$0.6

$1.0

$2.8

$4.7

2012

$5.3

2015E

$1.2

$3.3

$0.8

Electric Distribution

Gas Delivery

Electric Transmission

10%

All rate base amounts are presented as year-end rate base.

(1)

Exelon Utilities sets first quartile goals. The timing of the achievement of each goal will

depend upon specific jurisdictional nuances to each company and how they impact the

desired structure. The current distribution equity ratio for ComEd is ~46% and ComEd

will look to grow this ratio over time.   Currently, ComEd's Transmission capital ratio is

limited to 55%.

(2)

Earned ROE will reflect the weighted average of 11.5% allowed transmission ROE

and distribution ROE resulting from 30-year Treasury plus 580 basis points for each

calendar year.

(3)

Per MDPSC merger commitment, BGE is precluded from paying dividends through

2014. Per MDPSC orders, BGE cannot pay out a dividend to its parent company if

said dividend would cause BGE’s equity ratio to fall below 48% or if BGE is

downgraded by two of three rating agencies.

2013E

Long-Term Target

Equity Ratio

~55%

~53%

Earned ROE

11.5 –

12.5%

10%

2013 2Q Earnings Release Slides

2013 2Q Earnings Release Slides

21

ComEd May 2013 Distribution Formula Rate Updated Filing

Note:  Disallowance of any items in the 2013 distribution formula rate filing could impact 2013 earnings in the form of a regulatory asset adjustment.

Docket #

13-0318

Filing Year

Reconciliation Year

Common Equity Ratio

ROE

Rate Base

Revenue Requirement

Increase

Timeline

The 2013 distribution formula rate filing  establishes the net revenue requirement used to set the rates that will take effect in January 2014 after the

ICC’s review.  The filing was updated to reflect the impact of Senate Bill 9. There are two components to the annual distribution formula rate filing:

Filing Year:   Based on prior year costs (2012) and current year (2013) projected plant additions.

Annual Reconciliation:  For the prior calendar year (2012), this amount reconciles the revenue requirement reflected in rates during the prior year (2012)

in effect to the actual costs for that year. The annual reconciliation impacts cash flow in the following year (2014) but the earnings impact has been

recorded in the prior year (2012) as a regulatory asset.

04/29/13 Filing Date

240 Day Proceeding

ICC order by year end; rates effective January 2014

2012 Calendar Year Actual Costs and 2013 Projected Net Plant Additions

are used to set the rates for

calendar year 2014. Rates currently in effect (docket 12-0321) for calendar year 2013 were based on 2011 actual

costs and 2012 projected net plant additions.

Reconciles

Revenue

Requirement

reflected

in

rates

during

2012

to

2012

Actual

Costs

Incurred.

Revenue

Requirement for  2012 is based on dockets 10-0467, 11-0721 May Order and 11-0721 October Re-hearing Order.

~ 45%

for both the filing and reconciliation year

8.27%

for both the filing and reconciliation  year (2012 30-yr Treasury Yield of 2.92% + 580 basis point risk premium). 

For 2013 and 2014, the actual allowed ROE reflected in net income will ultimately be based on the average of the

30-year Treasury Yield during the respective years plus 580 basis point spread.

~7%

For the both the filing and reconciliation Year

$6,717 million

$359M

capital additions).  2013 and  2014 earnings will reflect 2013 and 2014 year-end rate base respectively.

-

Reconciliation year (represents year-end ate base for 2012)

$6,390 million

($165M is due to the 2012 reconciliation, $194M relates to the filing year). The 2012 reconciliation impact on

net income was recorded in 2012 as a regulatory asset. This increase also reflects the decrease in 2013 rates as

a result of Senate Bill 9.

Filing year (represents projected year-end rate base using 2012 actual plus 2013 projected

Requested Rate of Return

Given the retroactive ratemaking provision in the EIMA legislation, ComEd net income during the 

year will be based on actual costs with a regulatory asset/liability recorded to reflect any 

under/over recovery reflected in rates.  Revenue Requirement in rate filings impacts cash flow.

22

BGE Rate Case

Rate Case Request

Electric

Gas

Docket #

9326

Test Year

August 2012 –

July 2013

Common Equity Ratio

49.8%

Requested Returns

ROE: 10.5%; ROR: 7.75%

ROE: 10.35%; ROR: 7.67%

Rate Base (adjusted)

$2.8B

$1.1B

Revenue Requirement Increase

$101.5M

$29.7M

Proposed Distribution Increase as

% of overall bill

3%

4%

Timeline

•5/17/13: BGE filed application with the MDPSC seeking increases in gas & electric distribution base rates

•8/5/13: Staff/Intervenors file direct testimony

•8/23/13: Update 8 months actual/4 month estimated test period data with actuals for last 4 months

(March -

July 2013)

•9/17/13: BGE and staff/intervenors file rebuttal testimony

•10/3/13: Staff/Intervenors  and BGE file surrebuttal testimony

•10/15/13 –

10/29/13: Hearings

•11/12/13: Initial Briefs

•11/22/13: Reply Briefs

•12/13/13: Final Order

•New rates are in effect shortly after the final order

2013 2Q Earnings Release Slides

2Q GAAP EPS Reconciliation

Three

Months

Ended

June

30,

2013

ExGen

ComEd

PECO

BGE

Other

Exelon

2013 Adjusted (non-GAAP) Operating Earnings (Loss) Per Share

$0.32

$0.11

$0.09

$0.03

$(0.01)

$0.53

Mark-to-market impact of economic hedging activities

0.30

-

-

-

(0.01)

0.30

Unrealized gains related to NDT fund investments

(0.03)

-

-

-

-

(0.03)

Constellation merger and integration costs

(0.01)

-

(0.00)

(0.00)

-

(0.02)

Amortization of commodity contract intangibles

(0.13)

-

-

-

-

(0.13)

Amortization of the fair value of certain debt

0.00

-

-

-

-

0.00

Long-lived asset impairment

(0.07)

-

-

-

(0.01)

(0.08)

2Q 2013 GAAP Earnings (Loss) Per Share

$0.38

$0.11

$0.08

$0.03

$(0.03)

$0.57

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

Three

Months

Ended

June

30,

2012

ExGen

ComEd

PECO

BGE

Other

Exelon

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

$0.47

$0.05

$0.10

$0.02

$(0.02)

$0.61

Mark-to-market impact of economic hedging activities

0.14

-

-

-

0.00

0.15

Unrealized losses related to NDT fund investments

(0.02)

-

-

-

-

(0.02)

Plant retirements and divestitures

0.00

-

-

-

-

0.00

Constellation merger and integration costs

(0.07)

-

(0.00)

(0.00)

(0.01)

(0.08)

Amortization of commodity contract intangibles

(0.33)

-

-

-

-

(0.33)

Amortization of the fair value of certain debt

0.00

-

-

-

-

0.00

Non-cash remeasurement of deferred income taxes

-

-

-

-

0.00

0.00

2Q 2012 GAAP Earnings (Loss) Per Share

$0.19

$0.05

$0.09

$0.01

$(0.02)

$0.33

2013 2Q Earnings Release Slides

23

2Q YTD GAAP EPS Reconciliation

Six Months Ended June 30, 2013

ExGen

ComEd

PECO

BGE

Other

Exelon

2013 Adjusted (non-GAAP) Operating Earnings (Loss) Per Share

$0.71

$0.22

$0.23

$0.11

$(0.03)

$1.23

Mark-to-market impact of economic hedging activities

0.02

-

-

-

0.00

0.02

Unrealized gains related to NDT fund investments

0.02

-

-

-

-

0.02

Plant retirements and divestitures

0.02

-

-

-

-

0.02

Constellation merger and integration costs

(0.05)

-

(0.00)

0.00

(0.00)

(0.05)

Amortization of commodity contract intangibles

(0.28)

-

-

-

-

(0.27)

Amortization of the fair value of certain debt

0.01

-

-

-

-

0.01

Remeasurement of like kind exchange tax position

-

(0.20)

-

-

(0.11)

(0.31)

Long lived asset impairment

(0.09)

-

-

-

(0.01)

(0.10)

YTD 2013 GAAP Earnings (Loss) Per Share

$0.36

$0.02

$0.23

$0.12

$(0.15)

$0.57

Six Months Ended June 30, 2012

ExGen

ComEd

PECO

BGE

Other

Exelon

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

$1.03

$0.17

$0.23

$0.04

$(0.03)

$1.44

Mark-to-market impact of economic hedging activities

0.20

-

-

-

0.01

0.21

Unrealized gains related to NDT fund investments

0.02

-

-

-

-

0.02

Plant retirements and divestitures

(0.01)

-

-

-

-

(0.01)

Constellation merger and integration costs

(0.13)

(0.00)

(0.01)

(0.00)

(0.09)

(0.23)

Maryland commitments

(0.03)

-

(0.11)

(0.16)

(0.29)

Amortization of commodity contract intangibles

(0.46)

-

-

-

-

(0.46)

Amortization of the fair value of certain debt

0.00

-

-

-

-

0.00

FERC Settlement

(0.22)

-

-

-

-

(0.22)

Non-cash remeasurement of deferred income taxes

0.02

-

-

-

0.14

0.16

Other acquisition costs

(0.00)

-

-

-

-

(0.00)

YTD 2012 GAAP Earnings (Loss) Per Share

$0.43

$0.17

$0.22

(0.07)

$(0.13)

$0.62

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

2013 2Q Earnings Release Slides

24

GAAP to Operating Adjustments

2013 2Q Earnings Release Slides

•

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

Mark-to-market adjustments from economic hedging activities

Unrealized gains and losses from NDT fund investments to the extent not offset by contractual

accounting as described in the notes to the consolidated financial statements

Financial impacts associated with the sale or retirement of generating stations

Certain costs incurred associated with 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, which was retired in the

second quarter of 2013

Non-cash charge to earnings resulting from the remeasurement of Exelon’s like-kind exchange tax

position

Non-cash charge to earnings related to the cancellation of previously capitalized nuclear uprate projects

and the impairment of an investment in a long term lease.

Other unusual items

25