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

May 1, 2013

Date of Report (Date of earliest event reported)

Commission File Number	Exact Name of Registrant as Specified in Its Charter; State of Incorporation; Address of Principal Executive Offices; and Telephone Number	IRS Employer Identification Number
1-16169	EXELON CORPORATION (a Pennsylvania corporation) 10 South Dearborn Street P.O. Box 805379 Chicago, Illinois 60680-5379 (312) 394-7398	23-2990190
333-85496	EXELON GENERATION COMPANY, LLC (a Pennsylvania limited liability company) 300 Exelon Way Kennett Square, Pennsylvania 19348-2473 (610) 765-5959	23-3064219
1-1839	COMMONWEALTH EDISON COMPANY (an Illinois corporation) 440 South LaSalle Street Chicago, Illinois 60605-1028 (312) 394-4321	36-0938600
000-16844	PECO ENERGY COMPANY (a Pennsylvania corporation) P.O. Box 8699 2301 Market Street Philadelphia, Pennsylvania 19101-8699 (215) 841-4000	23-0970240
1-1910	BALTIMORE GAS AND ELECTRIC COMPANY (a Maryland corporation) 2 Center Plaza 110 West Fayette Street Baltimore, Maryland 21201 (410) 234-5000	52-0280210

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

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

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

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

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

Section 2 – Financial Information

Item 2.02. Results of Operations and Financial Condition.

Section 7 – Regulation FD

Item 7.01. Regulation FD Disclosure.

On May 1, 2013, Exelon Corporation (Exelon) announced via press release its results for the first quarter ended March 31, 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 first 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 May 1, 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 30841403. Media representatives are invited to participate on a listen-only basis. The call will be web-cast and archived on Exelon’s Web site: www.exeloncorp.com. (Please select the Investors page.)

Telephone replays will be available until May 15, 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 33703408.

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 includes forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995 that are subject to risks and uncertainties. The factors that could cause actual results to differ materially from these forward-looking statements include those discussed herein as well as those discussed in (1) Exelon’s 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; and (2) other factors discussed in filings with the Securities and Exchange Commission by the Registrants. Readers are cautioned not to place undue reliance on these forward-looking statements, which apply only as of the date of this Current Report. None of the Registrants undertakes any obligation to publicly release any revision to its forward-looking statements to reflect events or circumstances after the date of this Current Report.

SIGNATURES

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

EXELON CORPORATION

/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

May 1, 2013

EXHIBIT INDEX

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

EX-99.1

		Exhibit 99.1
Contact:	Ravi Ganti Investor Relations 312-394-2348 Paul Adams Corporate Communications 410-470-4167	FOR IMMEDIATE RELEASE

EXELON ANNOUNCES FIRST QUARTER 2013 RESULTS

CHICAGO (May 1, 2013) — Exelon Corporation (NYSE: EXC) announced first quarter 2013 consolidated earnings as follows:

	First Quarter
	2013			2012
Adjusted (non-GAAP) Operating Results:
Net Income (Loss) ($ millions)	$	602		$	603
Diluted Earnings per Share	$	0.70		$	0.85
GAAP Results:
Net Income (Loss) ($ millions)	$	(4	)	$	200
Diluted Earnings per Share	$	(0.01	)	$	0.28

“Exelon delivered earnings at the top end of our guidance range and our nuclear fleet achieved a 96.4 percent capacity factor this quarter, highlighting our commitment to financial discipline and operational excellence,” said Christopher M. Crane, Exelon’s president and CEO.

First Quarter Operating Results

First quarter 2013 earnings include financial results for Constellation Energy and Baltimore Gas and Electric Company (BGE) while first quarter 2012 earnings only contains the financial results for those companies from March 12, 2012 to March 31, 2012. Therefore, the composition of results of operations from 2013 and 2012 are not comparable for Exelon Generation Company, LLC (Generation), BGE and Exelon.

As shown in the table above, Exelon’s adjusted (non-GAAP) operating earnings declined to $0.70 per share in the first quarter of 2013 from $0.85 per share in the first quarter of 2012. Earnings in first quarter 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 and lower realized market prices for the sale of energy across all regions;

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• Higher operating and maintenance expenses, including increased labor, contracting and materials costs;

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

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

These factors were partially offset by:

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

• The addition of a full quarter of BGE’s financial results;

• Higher nuclear volume due to fewer planned and unplanned outage days; and

• Impact of favorable weather in the ComEd and PECO territories.

Adjusted (non-GAAP) operating earnings for the first 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	$	602		$	0.70
Mark-to-Market Impact of Economic Hedging Activities		(235	)		(0.27	)
Unrealized Gains Related to NDT (Nuclear Decommissioning Trust) Fund Investments		35			0.04
Plant Retirements and Divestitures		13			0.02
Constellation Merger and Integration Costs		(27	)		(0.03	)
Amortization of Commodity Contract Intangibles		(117	)		(0.14	)
Amortization of the Fair Value of Certain Debt		3			—
Re-measurement of Like-Kind Exchange Tax Position		(265	)		(0.31	)
Nuclear Uprate Project Cancellation		(13	)		(0.02	)
Exelon GAAP Net Income (Loss)	$	(4	)	$	(0.01	)

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Adjusted (non-GAAP) operating earnings for the first 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	$	603		$	0.85
Mark-to-Market Impact of Economic Hedging Activities		43			0.06
Unrealized Gains Related to NDT Fund Investments		36			0.05
Plant Retirements and Divestitures		(6	)		(0.01	)
Constellation Merger and Integration Costs		(113	)		(0.16	)
Maryland Commitments		(227	)		(0.32	)
Amortization of Commodity Contract Intangibles		(78	)		(0.11	)
FERC Settlement		(172	)		(0.25	)
Non-Cash Re-measurement of Deferred Income Taxes		117			0.17
Other Acquisition Costs		(3	)		—
Exelon GAAP Net Income (Loss)	$	200		$	0.28

First Quarter and Recent Highlights

• Nuclear Operations: Generation’s nuclear fleet, including its owned output from the Salem Generating Station, produced 36,031 gigawatt-hours (GWh) in the first quarter of 2013, compared with 35,262 GWh in the first 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 96.4 percent capacity factor for the first quarter of 2013, compared with 93.6 percent for the first quarter of 2012. The number of planned refueling outage days totaled 49 in the first quarter of 2013 versus 67 days in the first quarter of 2012. The number of non-refueling outage days totaled six days in the first quarter of 2013, compared with 16 days in the first quarter of 2012.

• Fossil and Renewables Operations: The dispatch match rate for Generation’s fossil and hydro fleet was 98.4 percent in the first quarter of 2013, compared with 87.8 percent in the first quarter of 2012. The 2013 results include former Constellation plants and Exelon hydro plants, whereas the 2012 data includes only legacy Exelon fossil plants. The performance in 2012 was driven by an outage at one of the peaking units in Texas. Energy capture for the wind and solar fleet was 94.9 percent in the first quarter of 2013, compared with 94.4 percent in the first quarter of 2012.

Dispatch match is used to measure market responsiveness. Expressed as a percentage, it reflects the unit’s revenue capture when it is called upon for generation. Factors that impact dispatch match adversely include forced outages, derates and failure to operate to the desired generation signal.

• Illinois Senate Bill 9: During March 2013, the Illinois House and Senate each passed Senate Bill 9 (SB9) with supermajority votes to clarify the intent of the Energy Infrastructure Modernization Act (EIMA) on three major issues: average versus year-end rate base and capital structure, return on pension asset, and a weighted average

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cost of capital interest rate on the prior year reconciliation. In addition, SB9 provides for accelerated advanced metering infrastructure (AMI) deployment that would commence earlier than 2015.

On March 21, 2013, SB9 was sent to the governor for his consideration. The governor has 60 days to approve or veto the legislation. If the governor does nothing, the bill becomes law after 60 days. If he vetoes the bill, the legislature will have the opportunity to override the veto with supermajority votes in each house, at which time it becomes law. If the legislation becomes law by June 15, 2013, ComEd will update certain elements of its AMI deployment schedule to provide for an accelerated deployment as called for by SB9.

• ComEd Distribution Formula Rate Case: On April 29, 2013, ComEd filed its 2013 annual distribution formula rate update, which establishes the net revenue requirement used to set the rates that will take effect in January 2014 after review by the Illinois Commerce Commission (ICC). The revenue requirement requested in the filing is based on 2012 actual costs and forecasted 2013 capital additions as well as an annual reconciliation of the revenue requirement in effect in 2012 to the actual costs incurred for that year. ComEd requested a total increase to the net revenue requirement of $311 million, reflecting an increase of $169 million for the initial revenue requirement for 2013 and an increase of $142 million for the annual reconciliation for 2012.

Rates effective in 2013 as a result of the 2012 distribution formula rate update are subject to a reconciliation to actual 2013 costs, which will be filed with the ICC in 2014. This reconciliation will be reflected in customer rates beginning in January 2015. Throughout each year, ComEd records regulatory assets or regulatory liabilities and corresponding increases or decreases to revenue for any differences between the revenue requirement in effect and its best estimate of the probable increase or decrease in the revenue requirement expected to ultimately be approved by the ICC in that year’s reconciliation proceedings based on the year’s actual costs incurred.

The filing does not reflect the SB9 legislation. If that legislation becomes law, an update to the distribution formula will be filed with the ICC shortly thereafter to reflect the passage of such legislation.

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• BGE Gas and Electric Distribution Rate Case: On Feb. 22, 2013, the Maryland Public Service Commission (MDPSC) issued Order No. 85374 related to the application filed by BGE on July 27, 2012 seeking an increase in electric and gas base rates. Under the MDPSC’s Order, BGE is authorized to increase annual electric base rates by $81 million, which is approximately 62 percent of the $131 million requested in the application and annual gas base rates by $32 million, which is approximately 71 percent of the $45 million requested. The electric distribution rate increase was set using an allowed return on equity of 9.75 percent and the gas distribution rate increase was set using an allowed return on equity of 9.60 percent. The new electric and natural gas distribution rates took effect for services rendered on or after Feb. 23, 2013.

• PECO Preferred Stock Redemption: On March 25, 2013, PECO announced that it issued a notice of redemption for all of the following series of preferred stock:

Series	CUSIP No.		Redemption Price Per Share
$3.80 Series A (NYSE: PEPRA)		693304206	$	106.00
$4.30 Series B (NYSE: PEPRB)		693304305	$	102.00
$4.40 Series C (NYSE: PEPRC)		693304404	$	112.50
$4.68 Series D (NYSE: PEPRD)		693304503	$	104.00

The redemption date for each of the above series of preferred stock is May 1, 2013. The total amount of preferred stock being redeemed is $87 million in stated value. The redemption price per share of each series of preferred stock shown above equals the stated value per share plus a premium, if applicable, plus accrued and unpaid dividends to, but excluding, the redemption date, less the previously announced quarterly dividend that will be paid separately on May 1, 2013, to shareholders of record as of the close of business on March 28, 2013. No dividends on the preferred stock being redeemed will accrue on or after the redemption date, nor will any interest accrue on amounts held to pay the redemption price.

• Antelope Valley Solar Ranch One Project: Three additional blocks of the Antelope Valley Solar Ranch One Project totaling 69 megawatts (MW) became operational in the first quarter of 2013, bringing the total capacity in operation to 98 MW. The remaining phases of the project are on track to be completed by the original planned commercial operation date of December 2013.

• Hedging Update: Exelon’s hedging program involves the hedging of commodity risk for Exelon’s expected generation, typically on a ratable basis over a three-year period. Expected generation represents the amount of energy estimated to be generated or purchased through owned or contracted-for capacity. The proportion of expected generation hedged as of March 31, 2013, is 98 to 101 percent for 2013, 70 to 73 percent for 2014, and 33 to 36 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.

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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.

First quarter 2013 GAAP net loss was $18 million, compared with net income of $168 million in the first quarter of 2012. Adjusted (non-GAAP) operating earnings for the first 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)	1Q13			1Q12
Generation Adjusted (non-GAAP) Operating Earnings	$	336		$	409
Mark-to-Market Impact of Economic Hedging Activities		(246	)		36
Unrealized Gains Related to NDT Fund Investments		35			36
Plant Retirements and Divestitures		13			(6	)
Constellation Merger and Integration Costs		(29	)		(45	)
Maryland Commitments		—			(22	)
Amortization of Commodity Contract Intangibles		(117	)		(78	)
FERC Settlement		—			(172	)
Non-Cash Re-measurement of Deferred Income Taxes		—			13
Other Acquisition Costs		—			(3	)
Amortization of the Fair Value of Certain Debt		3			—
Nuclear Uprate Project Cancellation		(13	)		—
Generation GAAP Net Income (Loss)	$	(18	)	$	168

Generation’s Adjusted (non-GAAP) Operating Earnings in the first quarter of 2013 decreased $73 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 and lower realized market prices for the sale of energy across all regions;

• Higher operating and maintenance expenses; and

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

These items were partially offset by contribution to Generation’s energy margins from the addition of Constellation Energy to Generation’s operations and higher nuclear volume due to fewer planned and unplanned outage days.

Generation’s average realized margin on all electric sales, including sales to affiliates and excluding trading activity, was $27.23 per megawatt-hour (MWh) in the first quarter of 2013, compared with $32.57 per MWh in the first quarter of 2012.

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

ComEd recorded GAAP net loss of $81 million in the first quarter of 2013, compared with net income of $87 million in the first quarter of 2012. Adjusted (non-GAAP) operating earnings for the first 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)	1Q13			1Q12
ComEd Adjusted (non-GAAP) Operating Earnings	$	89		$	88
Re-measurement of Like-Kind Exchange Tax Position		(170	)		—
Constellation Merger and Integration Costs		—			(1	)
ComEd GAAP Net Income (Loss)	$	(81	)	$	87

ComEd’s Adjusted (non-GAAP) Operating Earnings in the first quarter of 2013 were up $1 million from the same quarter in 2012, primarily due to favorable weather in ComEd’s service territory partially offset by lower realized prices resulting from changes in customer mix.

For the first quarter of 2013, heating degree-days in the ComEd service territory were up 36.7 percent relative to the same period in 2012 and were 3.0 percent above normal. Total retail electric deliveries increased 2.9 percent quarter over quarter.

Weather-normalized retail electric deliveries decreased 1.2 percent in the first quarter of 2013 relative to 2012, reflecting decreases in deliveries to both small and large commercial and industrial (C&I) customers. For ComEd, weather had favorable after-tax effect of $10 million on first quarter 2013 earnings relative to 2012 and a favorable after-tax effect of $2 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 first quarter of 2013 was $121 million, compared with $96 million in the first quarter of 2012. Adjusted (non-GAAP) Operating Earnings for the first 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)	1Q13			1Q12
PECO Adjusted (non-GAAP) Operating Earnings	$	123		$	100
Constellation Merger and Integration Costs		(2	)		(4	)
PECO GAAP Net Income (Loss)	$	121		$	96

PECO’s Adjusted (non-GAAP) Operating Earnings in the first quarter of 2013 increased $23 million from the same quarter in 2012, primarily due to favorable weather in PECO’s service territory.

For the first quarter of 2013, heating degree-days in the PECO service territory were up 27.5 percent relative to the same period in 2013 and were 1.5 percent below normal. Total retail electric deliveries were up 4.3 percent quarter over quarter. On the gas side, deliveries in the first quarter of 2013 were up 23.6 percent from the first quarter of 2012.

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Weather-normalized retail electric deliveries were flat in the first quarter of 2013 relative to 2012, reflecting declines in deliveries to small C&I customers offset by increases in deliveries to large C&I and residential customers. Weather-normalized gas deliveries were up 2.0 percent in the first quarter of 2013. For PECO, weather had favorable after-tax effect of $27 million on first quarter 2013 earnings relative to 2012 and an unfavorable after-tax effect of $4 million relative to normal weather.

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

For the first quarter of 2013, BGE’s GAAP net income was $77 million and adjusted (non-GAAP) Operating Earnings were $74 million.

Adjusted (non-GAAP) Operating Earnings

Adjusted (non-GAAP) operating earnings, which generally exclude significant one-time charges or credits that are not normally associated with ongoing operations, mark-to-market adjustments from economic hedging activities and unrealized gains and losses from NDT fund investments, are provided as a supplement to results reported in accordance with GAAP. Management uses such adjusted (non-GAAP) operating earnings measures internally to evaluate the company’s performance and manage its operations. Reconciliation of GAAP to adjusted (non-GAAP) operating earnings for historical periods is attached. Additional earnings release attachments, which include the reconciliation on page 8 are posted on Exelon’s Web site: www.exeloncorp.com and have been furnished to the Securities and Exchange Commission on Form 8-K on May 1, 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; and (2) other factors discussed in filings with the SEC by the Registrants. Readers are cautioned not to place undue reliance on these forward-looking statements, which apply only as of the date of this presentation. None of the Registrants undertakes any obligation to publicly release any revision to its forward-looking statements to reflect events or circumstances after the date of this news release.

# # #

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

EXELON CORPORATION

Consolidating Statements of Operations

(unaudited)

(in millions)

	Three Months Ended March 31, 2013
	Generation			ComEd			PECO			BGE			Other (a)			Exelon Consolidated
Operating revenues	$	3,533		$	1,160		$	895		$	880		$	(386	)	$	6,082
Operating expenses
Purchased power and fuel		2,169			382			406			426			(402	)		2,981
Operating and maintenance		1,112			328			188			143			(7	)		1,764
Depreciation, amortization, accretion and depletion		214			167			57			93			12			543
Taxes other than income		93			74			41			55			14			277
Total operating expenses		3,588			951			692			717			(383	)		5,565
Equity in losses of unconsolidated affiliates		(9	)		—			—			—			—			(9	)
Operating income (loss)		(64	)		209			203			163			(3	)		508
Other income and deductions
Interest expense		(82	)		(353	)		(29	)		(33	)		(126	)		(623	)
Other, net		128			5			3			5			31			172
Total other income and deductions		46			(348	)		(26	)		(28	)		(95	)		(451	)
Income (loss) before income taxes		(18	)		(139	)		177			135			(98	)		57
Income taxes		(1	)		(58	)		55			55			5			56
Net income (loss)		(17	)		(81	)		122			80			(103	)		1
Net income attributable to noncontrolling interests, preferred security dividends and preference stock dividends		1			—			1			3			—			5
Net income (loss) on common stock	$	(18	)	$	(81	)	$	121		$	77		$	(103	)	$	(4	)

	Three Months Ended March 31, 2012 (b)
	Generation			ComEd			PECO			BGE			Other (a)			Exelon Consolidated
Operating revenues	$	2,743		$	1,388		$	875		$	52		$	(368	)	$	4,690
Operating expenses
Purchased power and fuel		1,044			620			411			68			(378	)		1,765
Operating and maintenance		1,179			318			203			60			208			1,968
Depreciation, amortization, accretion and depletion		153			149			53			19			8			382
Taxes other than income		73			75			31			9			6			194
Total operating expenses		2,449			1,162			698			156			(156	)		4,309
Equity in losses of unconsolidated affiliates		(22	)		—			—			—			—			(22	)
Operating income (loss)		272			226			177			(104	)		(212	)		359
Other income and deductions
Interest expense		(54	)		(82	)		(31	)		(8	)		(20	)		(195	)
Other, net		178			4			2			1			9			194
Total other income and deductions		124			(78	)		(29	)		(7	)		(11	)		(1	)
Income (loss) before income taxes		396			148			148			(111	)		(223	)		358
Income taxes		230			61			51			(46	)		(138	)		158
Net income (loss)		166			87			97			(65	)		(85	)		200
Net income (loss) attributable to noncontrolling interests, preferred security dividends and preference stock dividends		(2	)		—			1			1			—			—
Net income (loss) on common stock	$	168		$	87		$	96		$	(66	)	$	(85	)	$	200

(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.

1

EXELON CORPORATION

Business Segment Comparative Statements of Operations

(unaudited)

(in millions)

	Generation
	Three Months Ended March 31,
	2013			2012 (a)			Variance
Operating revenues	$	3,533		$	2,743		$	790
Operating expenses
Purchased power and fuel		2,169			1,044			1,125
Operating and maintenance		1,112			1,179			(67	)
Depreciation, amortization, accretion and depletion		214			153			61
Taxes other than income		93			73			20
Total operating expenses		3,588			2,449			1,139
Equity in losses of unconsolidated affiliates		(9	)		(22	)		13
Operating income (loss)		(64	)		272			(336	)
Other income and deductions
Interest expense		(82	)		(54	)		(28	)
Other, net		128			178			(50	)
Total other income and deductions		46			124			(78	)
Income (loss) before income taxes		(18	)		396			(414	)
Income taxes		(1	)		230			(231	)
Net income (loss)		(17	)		166			(183	)
Net income (loss) attributable to noncontrolling interests		1			(2	)		3
Net income (loss) on common stock	$	(18	)	$	168		$	(186	)

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

	ComEd
	Three Months Ended March 31,
	2013			2012			Variance
Operating revenues	$	1,160		$	1,388		$	(228	)
Operating expenses
Purchased power		382			620			(238	)
Operating and maintenance		328			318			10
Depreciation and amortization		167			149			18
Taxes other than income		74			75			(1	)
Total operating expenses		951			1,162			(211	)
Operating income		209			226			(17	)
Other income and deductions
Interest expense		(353	)		(82	)		(271	)
Other, net		5			4			1
Total other income and deductions		(348	)		(78	)		(270	)
Income (loss) before income taxes		(139	)		148			(287	)
Income taxes		(58	)		61			(119	)
Net income (loss)	$	(81	)	$	87		$	(168	)

2

EXELON CORPORATION

Business Segment Comparative Statements of Operations

(unaudited)

(in millions)

	PECO
	Three Months Ended March 31,
	2013			2012			Variance
Operating revenues	$	895		$	875		$	20
Operating expenses
Purchased power and fuel		406			411			(5	)
Operating and maintenance		188			203			(15	)
Depreciation and amortization		57			53			4
Taxes other than income		41			31			10
Total operating expenses		692			698			(6	)
Operating income		203			177			26
Other income and deductions
Interest expense		(29	)		(31	)		2
Other, net		3			2			1
Total other income and deductions		(26	)		(29	)		3
Income before income taxes		177			148			29
Income taxes		55			51			4
Net income		122			97			25
Preferred security dividends		1			1			—
Net income on common stock	$	121		$	96		$	25
	BGE
	Three Months Ended March 31,
	2013			2012(a)			Variance
Operating revenues	$	880		$	52		$	828
Operating expenses
Purchased power and fuel		426			68			358
Operating and maintenance		143			60			83
Depreciation and amortization		93			19			74
Taxes other than income		55			9			46
Total operating expenses		717			156			561
Operating income (loss)		163			(104	)		267
Other income and deductions
Interest expense		(33	)		(8	)		(25	)
Other, net		5			1			4
Total other income and deductions		(28	)		(7	)		(21	)
Income (loss) before income taxes		135			(111	)		246
Income taxes		55			(46	)		101
Net income (loss)		80			(65	)		145
Preference stock dividends		3			1			2
Net income (loss) on common stock	$	77		$	(66	)	$	143

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

3

EXELON CORPORATION

Business Segment Comparative Statements of Operations

(unaudited)

(in millions)

	Other (a)
	Three Months Ended March 31,
	2013			2012 (b)			Variance
Operating revenues	$	(386	)	$	(368	)	$	(18	)
Operating expenses
Purchased power and fuel		(402	)		(378	)		(24	)
Operating and maintenance		(7	)		208			(215	)
Depreciation and amortization		12			8			4
Taxes other than income		14			6			8
Total operating expenses		(383	)		(156	)		(227	)
Operating loss		(3	)		(212	)		209
Other income and deductions
Interest expense		(126	)		(20	)		(106	)
Other, net		31			9			22
Total other income and deductions		(95	)		(11	)		(84	)
Loss before income taxes		(98	)		(223	)		125
Income taxes		5			(138	)		143
Net loss	$	(103	)	$	(85	)	$	(18	)

(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.

4

EXELON CORPORATION

Consolidated Balance Sheets

(in millions)

	March 31, 2013			December 31, 2012
	(unaudited)
ASSETS
Current assets
Cash and cash equivalents	$	679		$	1,411
Cash and cash equivalents of variable interest entities		93			75
Restricted cash and investments		83			86
Restricted cash and investments of variable interest entities		65			47
Accounts receivable, net
Customer		2,835			2,789
Other		1,110			1,147
Accounts receivable, net, variable interest entities		285			292
Mark-to-market derivative assets		666			938
Unamortized energy contract assets		727			886
Inventories, net
Fossil fuel		122			246
Materials and supplies		791			768
Deferred income taxes		331			131
Regulatory assets		765			764
Other		722			560
Total current assets		9,274			10,140
Property, plant and equipment, net		45,784			45,186
Deferred debits and other assets
Regulatory assets		6,521			6,497
Nuclear decommissioning trust (NDT) funds		7,559			7,248
Investments		1,181			1,184
Investments in affiliates		22			22
Investment in CENG		1,883			1,849
Goodwill		2,625			2,625
Mark-to-market derivative assets		706			937
Unamortized energy contracts assets		968			1,073
Pledged assets for Zion Station decommissioning		580			614
Other		1,140			1,186
Total deferred debits and other assets		23,185			23,235
Total assets	$	78,243		$	78,561
Liabilities and shareholders’ equity
Current liabilities
Short-term borrowings	$	233		$	—
Short-term notes payable - accounts receivable agreement		210			210
Long-term debt due within one year		2,085			975
Long-term debt due within one year of variable interest entities		79			72
Accounts payable		2,198			2,446
Accounts payable of variable interest entities		188			202
Accrued expenses		1,430			1,800
Deferred income taxes		29			58
Regulatory liabilities		418			368
Dividends payable		1			4
Mark-to-market derivative liabilities		181			352
Unamortized energy contract liabilities		410			455
Other		859			849
Total current liabilities		8,321			7,791
Long-term debt		16,210			17,190
Long-term debt to financing trusts		648			648
Long-term debt of variable interest entity		497			508
Deferred credits and other liabilities
Deferred income taxes and unamortized investment tax credits		11,315			11,551
Asset retirement obligations		5,149			5,074
Pension obligations		3,161			3,428
Non-pension postretirement benefit obligations		2,672			2,662
Spent nuclear fuel obligation		1,020			1,020
Regulatory liabilities		4,115			3,981
Mark-to-market derivative liabilities		259			281
Unamortized energy contract liabilities		466			528
Payable for Zion Station decommissioning		372			432
Other		2,625			1,650
Total deferred credits and other liabilities		31,154			30,607
Total liabilities		56,830			56,744
Commitments and contingencies
Preferred securities of subsidiary		87			87
Shareholders’ equity
Common stock		16,652			16,632
Treasury stock, at cost		(2,327	)		(2,327	)
Retained earnings		9,437			9,893
Accumulated other comprehensive loss, net		(2,673	)		(2,767	)
Total shareholders’ equity		21,089			21,431
BGE preference stock not subject to mandatory redemption		193			193
Noncontrolling interest		44			106
Total equity		21,326			21,730
Total liabilities and shareholders’ equity	$	78,243		$	78,561

5

EXELON CORPORATION

Consolidated Statements of Cash Flows

(unaudited)

(in millions)

	Three Months Ended March 31,
	2013			2012 (a)
Cash flows from operating activities
Net income	$	1			200
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation, amortization and accretion, including nuclear fuel and energy contract amortization		1,017			776
Deferred income taxes and amortization of investment tax credits		(610	)		101
Net fair value changes related to derivatives		388			(73	)
Net realized and unrealized gains on nuclear decommissioning trust fund investments		(66	)		(103	)
Other non-cash operating activities		231			530
Changes in assets and liabilities:
Accounts receivable		(70	)		394
Inventories		101			104
Accounts payable, accrued expenses and other current liabilities		(542	)		(1,176	)
Option premiums paid, net		(3	)		(100	)
Counterparty collateral received (posted), net		(186	)		340
Income taxes		632			178
Pension and non-pension postretirement benefit contributions		(267	)		(55	)
Other assets and liabilities		233			(122	)
Net cash flows provided by operating activities		859			994
Cash flows from investing activities
Capital expenditures		(1,447	)		(1,496	)
Proceeds from nuclear decommissioning trust fund sales		677			3,680
Investment in nuclear decommissioning trust funds		(729	)		(3,726	)
Cash and restricted cash acquired from Constellation		—			964
Change in restricted cash		(12	)		(8	)
Other investing activities		40			(54	)
Net cash flows used in investing activities		(1,471	)		(640	)
Cash flows from financing activities
Changes in short-term debt		233			141
Issuance of long-term debt		149			—
Retirement of long-term debt		(1	)		(451	)
Dividends paid on common stock		(450	)		(350	)
Proceeds from employee stock plans		12			12
Other financing activities		(45	)		(1	)
Net cash flows used in financing activities		(102	)		(649	)
Decrease in cash and cash equivalents		(714	)		(295	)
Cash and cash equivalents at beginning of period		1,486			1,016
Cash and cash equivalents at end of period	$	772		$	721

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

6

EXELON CORPORATION

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

(unaudited)

(in millions, except per share data)

	Three Months Ended March 31, 2013									Three Months Ended March 31, 2012 (a)
	GAAP (b)			Adjustments			Adjusted Non-GAAP			GAAP (b)			Adjustments			Adjusted Non-GAAP
Operating revenues	$	6,082		$	812	(c),(d)	$	6,894		$	4,690		$	147	(c),(d),(e),(k)	$	4,837
Operating expenses
Purchased power and fuel		2,981			253	(c),(d)		3,234			1,765			1	(c),(d),(e),(f)		1,766
Operating and maintenance		1,764			(38	)(e),(f),(g)		1,726			1,968			(574	)(e),(f),(k),(l),(m)		1,394
Depreciation, amortization, accretion and depletion		543			(1	)(f)		542			382			(16	)(e)		366
Taxes other than income		277			—			277			194			1	(e),(k)		195
Total operating expenses		5,565			214			5,779			4,309			(588	)		3,721
Equity in earnings (losses) of unconsolidated affiliates		(9	)		18	(d)		9			(22	)		8	(d)		(14	)
Operating income		508			616			1,124			359			743			1,102
Other income and deductions
Interest expense		(623	)		285	(f),(g),(h),(i)		(338	)		(195	)		(1	)(d)		(196	)
Other, net		172			(30	)(e),(f),(h),(j)		142			194			(119	)(j)		75
Total other income and deductions		(451	)		255			(196	)		(1	)		(120	)		(121	)
Income before income taxes		57			871			928			358			623			981
Income taxes		56			265	(c),(d),(e),(f),   (g),(h),(i),(j)		321			158			220	(c),(d),(e),(f),   (j),(k),(l),(m),(n)		378
Net income		1			606			607			200			403			603
Net income attributable to noncontrolling interests, preferred security dividends and preference stock dividends		5			—			5			—			—			—
Net income (loss) on common stock	$	(4	)	$	606		$	602		$	200		$	403		$	603
Effective tax rate		98.2	%					34.6	%		44.1	%					38.5	%
Earnings per average common share
Basic	$	(0.01	)	$	0.71		$	0.70		$	0.28		$	0.57		$	0.85
Diluted	$	(0.01	)	$	0.71		$	0.70		$	0.28		$	0.57		$	0.85
Average common shares outstanding
Basic		855						855			705						705
Diluted		859						859			707						707
Effect of adjustments on earnings per average diluted common share recorded in accordance with GAAP:
Mark-to-market impact of economic hedging activities (c)				$	0.27								$	(0.06	)
Amortization of commodity contract intangibles (d)					0.14									0.11
Plant retirements and divestitures (e)					(0.02	)								0.01
Constellation merger and integration costs (f)					0.03									0.16
Nuclear uprate project cancellation (g)					0.02									—
Remeasurement of like-kind exchange tax position (h)					0.31									—
Amortization of the fair value of certain debt (i)					—									—
Unrealized (gains) related to NDT fund investments (j)					(0.04	)								(0.05	)
Maryland commitments (k)					—									0.32
Federal Regulatory Energy Commission (FERC) settlement (l)					—									0.25
Other acquisition costs (m)					—									—
Non-cash remeasurement of deferred income taxes (n)					—									(0.17	)
Total adjustments				$	0.71								$	0.57

(a) For the three months ended March 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 electric and gas distribution rate case for the recovery of previously incurred integration costs.

(g) Adjustment to exclude a 2013 charge to earnings 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 expected to be retired in 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.

7

EXELON CORPORATION (a)

Reconciliation of Adjusted (non-GAAP) Operating

Earnings to GAAP Earnings (in millions)

Three Months Ended March 31, 2013 and 2012

	Exelon Earnings per Diluted Share			Generation			ComEd			PECO			BGE			Other (b)			Exelon
2012 GAAP Earnings (Loss)	$	0.28		$	168		$	87		$	96		$	(66	)	$	(85	)	$	200
2012 Adjusted (non-GAAP) Operating Earnings (Loss) Adjustments:
Mark-to-Market Impact of Economic Hedging Activities		(0.06	)		(36	)		—			—			—			(7	)		(43	)
Unrealized Gains Related to NDT Fund Investments (1)		(0.05	)		(36	)		—			—			—			—			(36	)
Plant Retirements and Divestitures (2)		0.01			6			—			—			—			—			6
Constellation Merger and Integration Costs (3)		0.16			45			1			4			1			62			113
Maryland Commitments (4)		0.32			22			—			—			83			122			227
Amortization of Commodity Contract Intangibles (5)		0.11			78			—			—			—			—			78
FERC Settlement (6)		0.25			172			—			—			—			—			172
Non-Cash Remeasurement of Deferred Income Taxes (7)		(0.17	)		(13	)		—			—			—			(104	)		(117	)
Other Acquisition Costs		—			3			—			—			—			—			3
2012 Adjusted (non-GAAP) Operating Earnings (Loss)		0.85			409			88			100			18			(12	)		603
Year Over Year Effects on Earnings:
Generation Energy Margins, Excluding Mark-to-Market:
Nuclear Volume (8)		0.01			12			—			—			—			—			12
Nuclear Fuel Costs (9)		(0.02	)		(16	)		—			—			—			—			(16	)
Capacity Pricing (10)		(0.03	)		(29	)		—			—			—			—			(29	)
Market and Portfolio Conditions (11)		0.19			162			—			—			—			—			162
ComEd, PECO and BGE Margins:
Weather		0.04			—			11			27			—	(c)		—			38
Load		—			—			(2	)		—			—	(c)		—			(2	)
Other Energy Delivery (12)		0.23			—			(4	)		(10	)		214			—			200
Operating and Maintenance Expense:
Labor, Contracting and Materials (13)		(0.17	)		(100	)		(10	)		3			(40	)		—			(147	)
Planned Nuclear Refueling Outages (14)		0.02			18			—			—			—			—			18
Pension and Non-Pension Postretirement Benefits (15)		(0.01	)		(4	)		(4	)		2			(4	)		—			(10	)
Other Operating and Maintenance (16)		(0.08	)		(55	)		7			3			(27	)		1			(71	)
Depreciation and Amortization Expense (17)		(0.13	)		(50	)		(11	)		(3	)		(44	)		(2	)		(110	)
Equity in Earnings of Unconsolidated Affiliates (18)		0.02			14			—			—			—			—			14
Income Taxes (19)		0.04			27			2			6			(2	)		(1	)		32
Interest Expense, Net (20)		(0.03	)		(18	)		9			1			(15	)		(3	)		(26	)
Other (21)		(0.08	)		(34	)		3			(6	)		(26	)		(3	)		(66	)
Share Differential (22)		(0.15	)		—			—			—			—			—			—
2013 Adjusted (non-GAAP) Operating Earnings (Loss)		0.70			336			89			123			74			(20	)		602
2013 Adjusted (non-GAAP) Operating Earnings (Loss) Adjustments:
Mark-to-Market Impact of Economic Hedging Activities		(0.27	)		(246	)		—			—			—			11			(235	)
Unrealized Gains Related to NDT Fund Investments (1)		0.04			35			—			—			—			—			35
Plant Retirements and Divestitures (2)		0.02			13			—			—			—			—			13
Constellation Merger and Integration Costs (3)		(0.03	)		(29	)		—			(2	)		3			1			(27	)
Amortization of Commodity Contract Intangibles (5)		(0.14	)		(117	)		—			—			—			—			(117	)
Amortization of the Fair Value of Certain Debt (23)		—			3			—			—			—			—			3
Remeasurement of Like-Kind Exchange Tax Position (24)		(0.31	)		—			(170	)		—			—			(95	)		(265	)
Nuclear Uprate Project Cancellation (25)		(0.02	)		(13	)		—			—			—			—			(13	)
2013 GAAP Earnings (Loss)	$	(0.01	)	$	(18	)	$	(81	)	$	121		$	77		$	(103	)	$	(4	)

(a) For the three months ended March 31, 2012, includes financial results for Constellation and BGE beginning on March 12, 2012, the date the merger was completed. Therefore, the results of operations from 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 electric and gas distribution rate 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) 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.

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

(8) Primarily reflects the impact of decreased planned and unplanned nuclear outage days in 2013, excluding Constellation Energy Nuclear Group, LLC (CENG).

(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 Reliability Pricing Model (RPM) for the PJM Interconnection, LLC (PJM) market, partially offset by the inclusion of Constellation’s results for the full quarter in 2013.

(11) Primarily reflects the inclusion of Constellation’s results for the full quarter in 2013, partially offset by the impact of decreased realized prices for the sale of energy across all regions.

(12) For ComEd, primarily reflects lower realized prices resulting from changes in customer mix, partially offset by increased distribution revenue due to recovery of increased costs and capital investment pursuant to the formula rate under EIMA. 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 decreased cost recovery for regulatory required programs (partially offset in operating and maintenance expense, depreciation expense and income taxes). For BGE, primarily reflects the inclusion of results for the full quarter in 2013, which includes increased distribution revenue pursuant to the February 22, 2013 order for BGE’s 2012 Maryland electric and natural gas distribution rate case.

(13) Primarily reflects the inclusion of Constellation and BGE’s results for the full quarter in 2013, the impacts of inflation across all operating companies and increased EIMA costs at ComEd, offset by reduced contracting expenses at PECO.

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

(15) 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.

(16) Primarily reflects the inclusion of Constellation and BGE’s results for the full quarter in 2013. For ComEd and PECO, primarily reflects decreased costs associated with regulatory required programs (completely offset by decreased other energy delivery revenues).

(17) Primarily reflects the inclusion of Constellation and BGE’s results for the full quarter in 2013, increased depreciation expense across the operating companies for ongoing capital expenditures, the non-cash amortization of intangible assets at Generation primarily related to the trade name and retail relationships recorded at fair value at the merger date and increased regulatory asset amortization at ComEd.

(18) 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.

(19) 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.

(20) Primarily reflects the inclusion of Constellation and BGE’s results for the full quarter 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.

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

(22) 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.

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

(24) 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.

(25) Reflects a 2013 charge to earnings related to Generation’s cancellation of previously capitalized nuclear uprate projects.

8

EXELON CORPORATION

Reconciliation of Adjusted (non-GAAP) Operating Earnings to

GAAP Consolidated Statements of Operations

(unaudited)

(in millions)

	Generation
	Three Months Ended March 31, 2013									Three Months Ended March 31, 2012 (a)
	GAAP (b)			Adjustments			Adjusted Non-GAAP			GAAP (b)			Adjustments			Adjusted Non-GAAP
Operating revenues	$	3,533		$	830	(c),(d)	$	4,363		$	2,743		$	45	(c),(d),(e)	$	2,788
Operating expenses
Purchased power and fuel		2,169			253	(c),(d)		2,422			1,044			1	(c),(d),(e),(f)		1,045
Operating and maintenance		1,112			(40	)(e),(f),(g)		1,072			1,179			(321	)(e),(f),(j),(k),(l)		858
Depreciation, amortization, accretion and depletion		214			(1	)(f)		213			153			(16	)(e)		137
Taxes other than income		93			—			93			73			(1	)(e)		72
Total operating expenses		3,588			212			3,800			2,449			(337	)		2,112
Equity in earnings (losses) of unconsolidated affiliates		(9	)		18	(d)		9			(22	)		8			(14	)
Operating income (loss)		(64	)		636			572			272			390			662
Other income and deductions
Interest expense		(82	)		(2	)(f),(g),(h)		(84	)		(54	)		(1	)(d)		(55	)
Other, net		128			(111	)(e),(f),(i)		17			178			(119	)(i)		59
Total other income and deductions		46			(113	)		(67	)		124			(120	)		4
Income (loss) before income taxes		(18	)		523			505			396			270			666
Income taxes		(1	)		169	(c),(d),(e),(f),   (g),(h),(i)		168			230			29	(c),(d),(e),(f),   (i),(j),(k),(l),(m)		259
Net income (loss)		(17	)		354			337			166			241			407
Net income (loss) attributable to noncontrolling interests		1			—			1			(2	)		—			(2	)
Net income (loss) on common stock	$	(18	)	$	354		$	336		$	168		$	241		$	409

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

(b) Results reported in accordance with 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 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.

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

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

(i) 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.

(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.

9

EXELON CORPORATION

Reconciliation of Adjusted (non-GAAP) Operating Earnings to

GAAP Consolidated Statements of Operations

(unaudited)

(in millions)

	ComEd
	Three Months Ended March 31, 2013									Three Months Ended March 31, 2012
	GAAP (a)			Adjustments			Adjusted  Non- GAAP			GAAP (a)			Adjustments			Adjusted  Non- GAAP
Operating revenues	$	1,160		$	—		$	1,160		$	1,388		$	—		$	1,388
Operating expenses
Purchased power		382			—			382			620			—			620
Operating and maintenance		328			—			328			318			(2	)(c)		316
Depreciation and amortization		167			—			167			149			—			149
Taxes other than income		74			—			74			75			—			75
Total operating expenses		951			—			951			1,162			(2	)		1,160
Operating income		209			—			209			226			2			228
Other income and deductions
Interest expense		(353	)		287	(b)		(66	)		(82	)		—			(82	)
Other, net		5			—			5			4			—			4
Total other income and deductions		(348	)		287			(61	)		(78	)		—			(78	)
Income (loss) before income taxes		(139	)		287			148			148			2			150
Income taxes		(58	)		117	(b)		59			61			1	(c)		62
Net income (loss)	$	(81	)	$	170		$	89		$	87		$	1		$	88

(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.

10

EXELON CORPORATION

Reconciliation of Adjusted (non-GAAP) Operating Earnings to

GAAP Consolidated Statements of Operations

(unaudited)

(in millions)

	PECO
	Three Months Ended March 31, 2013									Three Months Ended March 31, 2012
	GAAP (a)			Adjustments			Adjusted Non- GAAP			GAAP (a)			Adjustments			Adjusted Non- GAAP
Operating revenues	$	895		$	—		$	895		$	875		$	—		$	875
Operating expenses
Purchased power and fuel		406			—			406			411			—			411
Operating and maintenance		188			(2	)(b)		186			203			(7	)(b)		196
Depreciation and amortization		57			—			57			53			—			53
Taxes other than income		41			—			41			31			—			31
Total operating expenses		692			(2	)		690			698			(7	)		691
Operating income		203			2			205			177			7			184
Other income and deductions
Interest expense		(29	)		—			(29	)		(31	)		—			(31	)
Other, net		3			—			3			2			—			2
Total other income and deductions		(26	)		—			(26	)		(29	)		—			(29	)
Income before income taxes		177			2			179			148			7			155
Income taxes		55			—	(b)		55			51			3	(b)		54
Net income		122			2			124			97			4			101
Preferred security dividends		1			—			1			1			—			1
Net income on common stock	$	121		$	2		$	123		$	96		$	4		$	100

(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.

11

EXELON CORPORATION

Reconciliation of Adjusted (non-GAAP) Operating Earnings to

GAAP Consolidated Statements of Operations

(unaudited)

(in millions)

	BGE
	Three Months Ended March 31, 2013									March 12, 2012 through March 31, 2012
	GAAP (a)			Adjustments			Adjusted Non- GAAP			GAAP (b)			Adjustments			Adjusted Non- GAAP
Operating revenues	$	880		$	—		$	880		$	52		$	113	(c)	$	165
Operating expenses
Purchased power and fuel		426			—			426			68			—			68
Operating and maintenance		143			5	(b)		148			60			(30	)(b),(c)		30
Depreciation and amortization		93			—			93			19			—			19
Taxes other than income		55			—			55			9			2	(c)		11
Total operating expenses		717			5			722			156			(28	)		128
Operating income (loss)		163			(5	)		158			(104	)		141			37
Other income and deductions
Interest expense		(33	)		—			(33	)		(8	)		—			(8	)
Other, net		5			—			5			1			—			1
Total other income and deductions		(28	)		—			(28	)		(7	)		—			(7	)
Income (loss) before income taxes		135			(5	)		130			(111	)		141			30
Income taxes		55			(2	)(b)		53			(46	)		57	(b),(c)		11
Net income (loss)		80			(3	)		77			(65	)		84			19
Preference stock dividends		3			—			3			1			—			1
Net income (loss) on common stock	$	77		$	(3	)	$	74		$	(66	)	$	84		$	18

(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 electric and gas distribution rate 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.

12

EXELON CORPORATION

Reconciliation of Adjusted (non-GAAP) Operating Earnings to

GAAP Consolidated Statements of Operations

(unaudited)

(in millions)

	Other (a)
	Three Months Ended March 31, 2013									Three Months Ended March 31, 2012 (b)
	GAAP (c)			Adjustments			Adjusted Non- GAAP			GAAP (c)			Adjustments			Adjusted Non- GAAP
Operating revenues	$	(386	)	$	(18	)(d)	$	(404	)	$	(368	)	$	(11	)(d)	$	(379	)
Operating expenses
Purchased power and fuel		(402	)		—			(402	)		(378	)		—			(378	)
Operating and maintenance		(7	)		(1	)(e)		(8	)		208			(214	)(e),(g)		(6	)
Depreciation and amortization		12			—			12			8			—			8
Taxes other than income		14			—			14			6			—			6
Total operating expenses		(383	)		(1	)		(384	)		(156	)		(214	)		(370	)
Operating loss		(3	)		(17	)		(20	)		(212	)		203			(9	)
Other income and deductions
Interest expense		(126	)		—			(126	)		(20	)		—			(20	)
Other, net		31			81	(f)		112			9			—			9
Total other income and deductions		(95	)		81			(14	)		(11	)		—			(11	)
Loss before income taxes		(98	)		64			(34	)		(223	)		203			(20	)
Income taxes		5			(19	)(d),(e),(f)		(14	)		(138	)		130	(d),(e),(g),(h)		(8	)
Net loss	$	(103	)	$	83		$	(20	)	$	(85	)	$	73		$	(12	)

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

(b) For the three months ended March 31, 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 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.

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

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

13

EXELON CORPORATION

Exelon Generation Statistics

	Three Months Ended (a)
	Mar. 31, 2013			Dec. 31, 2012			Sep. 30, 2012		Jun. 30, 2012		Mar. 31, 2012
Supply (in GWhs)
Nuclear Generation (b)
Mid-Atlantic		12,762			11,547			11,449		12,277		12,064
Midwest		23,269			23,335			23,132		22,860		23,198
Total Nuclear Generation		36,031			34,882			34,581		35,137		35,262
Fossil and Renewables (b)
Mid-Atlantic (b)(d)		3,160			2,154			2,547		2,316		1,791
Midwest		581			300			171		228		272
New England		2,392			2,368			3,953		2,755		889
New York		—			—			—		—		—
ERCOT		733			755			2,410		2,177		840
Other (e)		2,254			1,358			1,813		1,923		819
Total Fossil and Renewables		9,120			6,935			10,894		9,399		4,611
Purchased Power
Mid-Atlantic (c)		3,233			4,332			6,811		7,111		2,577
Midwest		1,700			2,661			3,035		1,558		2,552
New England		1,507			2,304			1,961		3,905		1,100
New York (c)		3,511			3,678			4,026		2,818		935
ERCOT		4,199			6,043			7,741		6,686		2,832
Other (e)		3,703			4,172			5,372		6,012		1,769
Total Purchased Power		17,853			23,190			28,946		28,090		11,765
Total Supply/Sales by Region (g)
Mid-Atlantic (f)		19,155			18,033			20,807		21,704		16,432
Midwest (f)		25,550			26,296			26,338		24,646		26,022
New England		3,899			4,672			5,914		6,660		1,989
New York		3,511			3,678			4,026		2,818		935
ERCOT		4,932			6,798			10,151		8,863		3,672
Other (e)		5,957			5,530			7,185		7,935		2,588
Total Supply/Sales by Region		63,004			65,007			74,421		72,626		51,638
	Three Months Ended (a)
	Mar. 31, 2013			Dec. 31, 2012			Sep. 30, 2012		Jun. 30, 2012		Mar. 31, 2012
Average Margin ($/MWh) (h) (i)
Mid-Atlantic (j)	$	44.04		$	48.24		$	43.64	$	40.68	$	46.86
Midwest (j)		28.08			26.09			27.68		31.00		31.40
New England		7.63			3.64			13.70		9.01		19.61
New York		(6.27	)		4.35			3.23		13.84		8.56
ERCOT		20.54			13.39			15.66		13.43		9.26
Other (e)		7.61			7.96			5.85		4.28		5.41
Average Margin - Overall Portfolio	$	27.23		$	26.52		$	25.96	$	26.15	$	32.57
Around-the-clock Market Prices ($/MWh) (k)
PJM West Hub	$	37.53		$	35.94		$	38.13	$	30.40	$	31.10
NiHub		30.93			28.37			34.29		26.02		27.13
New England Mass Hub ATC Spark Spread		(6.63	)		3.07			12.69		7.77		0.80
NYPP Zone A		40.23			34.70			34.56		27.87		27.18
ERCOT North Spark Spread		(0.66	)		(0.27	)		3.60		6.01		3.46
	Three Months Ended (a)
	Mar. 31, 2013			Dec. 31, 2012			Sep. 30, 2012		Jun. 30, 2012		Mar. 31, 2012
Outage Days (l)
Refueling		49			113			43		51		67
Non-refueling		6			1			40		16		16
Total Outage Days		55			114			83		67		83

(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 2,588 GWhs, 3,255 GWhs, 3,126 GWhs, 3,225 GWhs and 319 GWhs in the Mid-Atlantic and 3,213 GWhs, 2,814 GWhs, 2,997 GWhs, 2,817 GWhs and 722 GWhs in New York as a result of the PPA with CENG for the three months ended March 31, 2013, December 31, 2012, September 30, 2012, June 30, 2012 and March 31, 2012, respectively.

(d) Excludes generation under the reliability-must-run rate schedule and generation of Brandon Shores, H.A. Wagner, and C.P. Crane, the generating facilities divested in Q4 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 1,572 GWhs, 2,977 GWhs, 4,352 GWhs, 4,248 GWhs, and 1,888 GWhs, for the three months ended March 31, 2013, December 31, 2012, September 30, 2012, June 30, 2012, and March 31, 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 quarter.

(l) Outage days exclude Salem and CENG.

14

EXELON CORPORATION

ComEd Statistics

Three Months Ended March 31, 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		6,876		6,406		7.3	%		(0.1	)%	$	584		$	775		(24.6	)%
Small Commercial & Industrial		7,873		7,916		(0.5	)%		(3.2	)%		308			348		(11.5	)%
Large Commercial & Industrial		6,840		6,703		2.0	%		(0.4	)%		102			100		2.0	%
Public Authorities & Electric Railroads		373		325		14.8	%		9.7	%		12			12		0.0	%
Total Retail		21,962		21,350		2.9	%		(1.2	)%		1,006			1,235		(18.5	)%
Other Revenue (b)												154			153		0.7	%
Total Electric Revenue											$	1,160		$	1,388		(16.4	)%
Purchased Power											$	382		$	620		(38.4	)%
								% Change
Heating and Cooling Degree-Days	2013		2012		Normal			From 2012			From Normal
Heating Degree-Days		3,259		2,384		3,164			36.7	%		3.0	%
Cooling Degree-Days		—		39		—			(100.0	)%		n/a
Number of Electric Customers	2013		2012
Residential		3,470,659		3,465,669
Small Commercial & Industrial		366,284		365,525
Large Commercial & Industrial		2,001		2,013
Public Authorities & Electric Railroads		4,802		4,790
Total		3,843,746		3,837,997

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

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

15

EXELON CORPORATION

PECO Statistics

Three Months Ended March 31, 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		3,465		3,166		9.4	%		0.5	%	$	395		$	407		(2.9	)%
Small Commercial & Industrial		2,009		1,951		3.0	%		(4.5	)%		106			118		(10.2	)%
Large Commercial & Industrial		3,646		3,637		0.2	%		1.5	%		59			54		9.3	%
Public Authorities & Electric Railroads		255		237		7.6	%		7.6	%		8			8		0.0	%
Total Retail		9,375		8,991		4.3	%		0.0	%		568			587		(3.2	)%
Other Revenue (b)												55			56		(1.8	)%
Total Electric Revenue												623			643		(3.1	)%
Gas (in mmcfs)
Retail Deliveries and Sales
Retail Sales (c)		28,438		22,427		26.8	%		(0.4	)%		260			222		17.1	%
Transportation and Other		8,883		7,766		14.4	%		10.9	%		12			10		20.0	%
Total Gas		37,321		30,193		23.6	%		2.0	%		272			232		17.2	%
Total Electric and Gas Revenues											$	895		$	875		2.3	%
Purchased Power and Fuel											$	406		$	411		(1.2	)%
									% Change
Heating and Cooling Degree-Days	2013		2012		Normal			From 2012			From Normal
Heating Degree-Days		2,440		1,914		2,476			27.5	%		(1.5	)%
Cooling Degree-Days		—		4		—			n/a			n/a
Number of Electric Customers	2013		2012		Number of Gas Customers									2013		2012
Residential		1,423,333		1,420,734		Residential									455,979		452,800
Small Commercial & Industrial		148,749		148,756		Commercial & Industrial									41,972		41,577
Large Commercial & Industrial		3,117		3,109		Total Retail									497,951		494,377
Public Authorities & Electric Railroads		9,657		9,688		Transportation									904		888
Total		1,584,856		1,582,287		Total									498,855		495,265

(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.

16

EXELON CORPORATION

BGE Statistics

Three Months Ended March 31, 2013 and March 12, 2012 Through March 31, 2012

	Electric and Gas Deliveries						Revenue (in millions)
	2013		2012		% Change		2013			2012			% Change
Electric (in GWhs)
Retail Deliveries and Sales (a)
Residential		3,537		615		n.m.	$	365		$	(13	)		n.m.
Small Commercial & Industrial		3,980		143		n.m.		159			12			n.m.
Large Commercial & Industrial		349		843		n.m.		10			21			n.m.
Public Authorities & Electric Railroads		82		25		n.m.		8			3			n.m.
Total Retail		7,948		1,626		n.m.		542			23			n.m.
Other Revenue (b)								63			17			n.m.
Total Electric Revenue								605			40			n.m.
Gas (in mmcfs)
Retail Deliveries and Sales (c)
Retail Sales		40,261		4,867		n.m.		246			6			n.m.
Transportation and Other (d)		5,651		1,910		n.m.		29			6			n.m.
Total Gas		45,912		6,777		n.m.		275			12			n.m.
Total Electric and Gas Revenues							$	880		$	52			n.m.
Purchased Power and Fuel							$	426		$	68			n.m.
							% Change
Heating and Cooling Degree-Days	2013		2012		Normal		From 2011			From Normal
Heating Degree-Days		2,451		1,717		2,384		42.7	%		2.8	%
Cooling Degree-Days		1		—		—		n.m.			n.m.
Number of Electric Customers	2013		2012		Number of Gas Customers					2013			2012
Residential		1,118,824		1,116,201		Residential					612,065			610,612
Small Commercial & Industrial		119,189		119,227		Commercial & Industrial					44,308			44,170
Large Commercial & Industrial		5,451		5,442		Total Retail					656,373			654,782
Public Authorities & Electric Railroads		318		298		Transportation					—			—
Total		1,243,782		1,241,168		Total					656,373			654,782

(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 5,650 mmcfs ($24 million) for the three months ended March 31, 2013 and 1,910 mmcfs ($5 million) from March 12, 2012 through March 31, 2012.

17

EX-99.2

Earnings

Conference

Call

1

st

Quarter

2013

May

1

st

, 2013

Exhibit 99.2

Cautionary Statements Regarding

Forward-Looking Information

1

2013 1Q 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; and (2) other factors discussed

in filings with the

SEC by the Registrants. Readers are cautioned not to place undue

reliance on these

forward-looking statements, which apply only as of the date of this presentation.

None of the Registrants undertakes any obligation to publicly release any revision to

its forward-looking statements to reflect events or circumstances after the date of

this presentation.

2013 1Q Earnings Release Slides

2013 1Q Earnings Release Slides

2

Q1 2013 Executive Summary

Expect to deliver on full year financial expectations by focusing on

operational excellence and portfolio management

•

Delivered strong operating and financial results for 1Q 2013

Operating earnings of $0.70 for the first quarter

Best ever first quarter generation output; fourth best ever nuclear capacity

factor of 96.4%; Fossil availability factor of 98.4%; Renewable energy capture

of 94.9%

•

Forward markets continue to show signs of potential upside

•

Constructive electric and gas rate case order for BGE

•

Progress made on ComEd EIMA legislation amendments

•

Continue execution on the path laid out earlier this year

Improve balance sheet strength

Focus on operations and efficiency

Exploring opportunities for organic and opportunistic growth

Market Update

•

Upside in fundamental view starting to materialize in PJM; current view is that there is

still $2 -

$4/MWh upside in 2015+ based on the market forwards as of March

31,

2013

•

Current year gas price increase largely driven by weather; long-term gas price view of

$4 -

$6/mmbtu

2013 1Q Earnings Release Slides

3

42

40

38

36

34

32

30

4/1/13

3/1/13

2/1/13

1/1/13

NiHub

PJM-W

9.6

9.3

7.8

7.5

10.0

9.0

8.0

7.0

6.0

4/1/13

3/1/13

2/1/13

1/1/13

7.5

9.5

8.5

6.5

NiHub

PJM-W

2015 ATC Price Change

2015 Heat Rate Change

$41.43

$39.17

$33.72

$31.87

2013 1Q Earnings Release Slides

4

1Q 2013 Financial Summary

•

Delivered non-GAAP operating earnings

(1)

in 1Q of

$0.70/share at the upper end of our earnings

guidance

of

$0.60

-

$0.70/share

1Q 2013 vs. 1Q 2012

•

Lower ExGen pricing

•

Share differential

•

Favorable weather

•

Full quarter of Constellation & BGE in 1Q 2013

1Q 2013 vs. Guidance

•

Higher nuclear volume

•

Favorable O&M in 1Q expected to reverse over the

rest of 2013

•

Favorable tax items

•

Inability to achieve portfolio management targets

$0.39

$0.10

$0.14

$0.09

$0.70

($0.02)

HoldCo

ExGen

ComEd

PECO

BGE

2013 1Q Results

(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.

Expect 2Q 2013 earnings of $0.50 - $0.60/share

5

Exelon Generation: Gross Margin Update

March 31, 2013

December 31, 2012

Gross Margin Category ($M)

(1) (2)

2013

2014

2015

2013

2014

2015

Open Gross Margin

(3)

(including South, West, Canada hedged gross margin)

$6,000

$6,350

$6,400

$5,550

$5,900

$6,050

Mark-to-Market of Hedges

(3,4)

$1,200

$400

$250

$1,650

$650

$300

Power New Business / To Go

$350

$600

$800

$400

$650

$850

Non-Power Margins Executed

$300

$100

$50

$200

$100

$50

Non-Power New Business / To Go

(5)

$300

$500

$550

$400

$500

$550

Total Gross Margin

$8,150

$7,950

$8,050

$8,200

$7,800

$7,800

•

Forward

power

markets

increased

during

the

1st

quarter

in

nearly

all

regions

The MidWest and Mid-Atlantic saw increases of $2 per MWh or more, driven by expanding heat rates

and increasing natural gas prices

Continue to optimize our hedging to realize the upside that we believe remains in the market due to

liquidity and coal retirements

•

Power New Business To-Go is lower in 2014 and 2015 as we execute on favorable hedges.

Power

New

Business

To-Go

in

2013

has

been

lowered

to

reflect

our

portfolio

positioning

and

year-to-date results

2013 1Q Earnings Release Slides

1)

Gross margin rounded to nearest $50M.

2)

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

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

FIN 46R.

3)

Includes CENG Joint Venture.

4)

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

5)

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

revenue less costs of sales.

2013 1Q Earnings Release Slides

Key Highlights of 1Q 2013

BGE

2013 load growth largely

driven by the idling of RG Steel

and

energy efficiency partially

offset by improving economic

conditions

6

Exelon Utilities Load

2013E

1.0%

-0.8%

-0.5%

-0.1%

2012

-0.3%

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 (February 2013).    Assumes 2013 GDP of 1.9% 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

Moderate economic growth

and strong steel /auto sector

growth partially offset by

energy efficiency yields overall

load similar to 2012

2013E

2.0%

-2.8%

0.8%

0.5%

2012

-2.7%

-2.3%

-1.7%

-2.2%

PECO

2013 growth driven by  oil

refinery and improved

employment outlook partially

offset by energy efficiency

2013E

-1.7%

1.2%

-1.0%

-1.1%

2012

-0.2%

-2.8%

-2.1%

-1.5%

Chicago GMP

1.3%

Chicago

Unemployment

9.5%

Philadelphia GMP

1.4%

Philadelphia Unemployment

8.5%

Baltimore GMP

1.6%

Baltimore Unemployment

7.1%

2013 1Q Earnings Release Slides

2013 1Q Earnings Release Slides

7

2013 Cash Flow Summary

2013 1Q Earnings Release Slides

•

Expect Cash from Operations of ~$5.8B in 2013

•

CapEx spend is $150M lower than prior estimates in part due to cancellation of

Dresden and Quad Cities MUR projects

•

Financing plan reflects goal of maintaining a strong balance sheet

Financing plan for utilities primarily consists of debt refinancing and 

redemption of PECO’s $87M preferred stock

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

for AVSR1 and project financing for existing wind assets

•

Projecting to end the year in a strong cash position with $1.35B, the majority of

which will be held at ExGen

2013 1Q Earnings Release Slides

8

2013 Key Events

1Q13

2Q13

3Q13

2013 distribution

formula rate case

filing (4/29/13)

2013 transmission

formula rate case

filing (4/29/13);

rates effective June

2013 thru May 2014

2013 distribution

formula rate case filing

final order (by

12/27/13); rates

effective 1/2/14 –

1/1/15

4Q13

2013 transmission 

formula rate case filing

(by 5/15/13); rates

effective June 2013 thru

May 2014

MDPSC Order February

22, 2013

Regular procurement

event (January)

Regular procurement

event (April and June)

DSP II Procurement

(February)

DSP II Procurement

(October)

Regular

procurement event

(October)

2016/2017 PJM

RPM Auction Results

(5/24/13)

2013 1Q Earnings Release Slides

Electric & gas distribution

rate case filing

2013 1Q Earnings Release Slides

9

Exelon Generation Disclosures

March 31, 2013

2013 1Q Earnings Release Slides

2013 1Q Earnings Release Slides

10

Portfolio Management Strategy

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

Credit Rating

Capital &

Operating

Expenditure

Dividend

Capital

Structure

Protect Balance Sheet

Ensure Earnings Stability

Create Value

Strategic Policy Alignment

•Aligns hedging program with

financial policies and financial

outlook

•Establish minimum hedge targets

to meet financial objectives of the

company (dividend, credit rating)

•Hedge enough commodity risk to

meet future cash requirements

under a stress scenario

Three-Year Ratable Hedging

Tenor aligns with customer

Multiple channels to market that

Bull / Bear Program

•Ability to exercise fundamental

market views to create value within

the ratable framework

•Modified timing of hedges versus

purely ratable

•Cross-commodity hedging (heat

rate positions, options, etc.)

•Delivery locations, regional and

zonal spread relationships

•

Disciplined approach to hedging

•

preferences and market liquidity

•

allow us to maximize margins

•

Large open position in outer years

to benefit from price upside

•Ensure stability in near

-

term cash

flows and earnings

2013 1Q Earnings Release Slides

11

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 1Q Earnings Release Slides

(1) 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.

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

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

2013 1Q Earnings Release Slides

12

ExGen Disclosures 

Gross Margin Category ($M)

(1,2)

2013

2014

2015

Open Gross Margin

(including South, West & Canada hedged GM)

(3)

$6,000

$6,350

$6,400

Mark to Market of Hedges

(3,4)

$1,200

$400

$250

Power New Business / To Go

$350

$600

$800

Non-Power Margins Executed

$300

$100

$50

Non-Power New Business / To Go

(5)

$300

$500

$550

Total Gross Margin

$8,150

$7,950

$8,050

2013 1Q Earnings Release Slides

2013 1Q Earnings Release Slides

(1)

Gross margin rounded to nearest $50M.

(2)

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

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

FIN 46R.

(3)

Includes CENG Joint Venture.

(4)

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

(5)

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

revenue less costs of sales.

(6)

Based on March 31, 2013 market conditions.

Reference Prices

(6)

2013

2014

2015

Henry Hub Natural Gas ($/MMbtu)

$3.92

$4.23

$4.30

Midwest: NiHub ATC prices ($/MWh)

$32.49

$32.99

$33.72

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

$39.74

$40.54

$41.43

ERCOT-N ATC Spark Spread ($/MWh)

HSC Gas, 7.2HR, $2.50 VOM

$7.12

$8.53

$8.48

New York: NY Zone A ($/MWh)

$38.16

$37.55

$38.02

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

ALQN Gas, 7.5HR, $0.50 VOM

$2.66

$4.51

$3.73

13

ExGen Disclosures

Generation and Hedges

2013

2014

2015

Exp. Gen (GWh)

(1)

216,900

213,800

208,000

Midwest

97,600

97,100

96,500

Mid-Atlantic

(2)

74,700

72,400

70,200

ERCOT

15,600

17,800

18,100

New York

(2)

14,100

11,800

9,300

New England

14,900

14,700

13,900

% of Expected Generation Hedged

(3)

98-101%

70-73%

33-36%

Midwest

98-101%

69-72%

32-35%

Mid-Atlantic

(2)

99-102%

73-76%

41-44%

ERCOT

93-96%

66-69%

24-27%

New York

(2)

101-104%

74-77%

36-39%

New England

98-101%

61-64%

14-17%

Effective Realized Energy Price ($/MWh)

(4)

Midwest

$37.50

$35.00

$35.00

Mid-Atlantic

(2)

$49.00

$46.00

$48.00

ERCOT

(5)

$9.00

$7.00

$6.00

New York

(2)

$34.00

$36.00

$45.00

New England

(5)

$4.50

$4.00

$3.00

(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 

93.9%, 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 1Q Earnings Release Slides

14

ExGen Hedged Gross Margin Sensitivities

Gross Margin Sensitivities (With Existing Hedges) 

(1, 2)

2013

2014

2015

Henry Hub Natural Gas ($/Mmbtu)

+ $1/Mmbtu

$15

$285

$425

-

$1/Mmbtu

$(5)

$(225)

$(370)

NiHub ATC Energy Price

+ $5/MWh

$5

$180

$375

-

$5/MWh

$(5)

$(170)

$(375)

PJM-W ATC Energy Price

+ $5/MWh

$5

$115

$220

-

$5/MWh

$0

$(115)

$(215)

NYPP Zone A ATC Energy Price

+ $5/MWh

$0

$20

$30

-

$5/MWh

$0

$(20)

$(30)

Nuclear Capacity Factor

(3)

+/-

1%

+/-

$35

+/-

$45

+/-

$50

2013 1Q Earnings Release Slides

(1) Based on March 31, 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.

2013 1Q Earnings Release Slides

15

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

$9,450

2014

$8,600

2013

$8,350

2013 1Q Earnings Release Slides

$7,900

$7,400

$6,850

(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 March 31,

2013 (2) Gross Margin Upside/Risk based on commodity exposure which includes open generation and all committed transactions.

2013 1Q Earnings Release Slides

16

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 

$6.35 billion

(B)

Expected Generation (TWh)

97.1

72.4

17.8

11.8

14.7

(C)

Hedge % (assuming mid-point of range)

70.5%

74.5%

67.5%

75.5%

62.5%

(D=B*C)

Hedged Volume (TWh)

68.5

53.9

12.0

8.9

9.2

(E)

Effective Realized Energy Price ($/MWh)

$35.00

$46.00

$7.00

$36.00

$4.00

(F)

Reference Price ($/MWh)

$32.99

$40.54

$8.53

$37.55

$4.51

(G=E-F)

Difference ($/MWh)

$2.01

$5.46

($1.53)

$(1.55)

$0.51

(H=D*G)

Mark-to-market

value

of

hedges

($

million)

(1)

$140 million

$300 million

($20) million

$(15) million

$0 million

(I=A+H)

Hedged Gross Margin ($ million)

$6,750 million

(J)

Power New Business / To Go ($ million)

$600 million

(K)

Non-Power Margins Executed ($ million)

$100 million

(L)

Non-

Power New Business / To Go ($ million)

$500 million

(N=I+J+K+L)

Total Gross Margin

$7,950 million

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

2013 1Q Earnings Release Slides

2013 1Q Earnings Release Slides

17

Additional Disclosures

2013 1Q Earnings Release Slides

2013 1Q Earnings Release Slides

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)

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

terms through August 30, 2013.

(5)

Excludes BGE’s current portion of its rate stabilization bonds

(6)

“Other”

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

(7)

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

($ in millions)

18

Beginning Cash Balance

(1)

1,575

Cash Flow from Operations

(2)

625

1,375

625

3,375

5,825

CapEx (excluding other items

below):

(550)

(1,300)

(400)

(1,025)

(3,300)

Nuclear Fuel

n/a

n/a

n/a

(1,000)

(1,000)

Dividend

(3)

(1,250)

Nuclear Uprates

n/a

n/a

n/a

(125)

(125)

Wind

n/a

n/a

n/a

--

--

Solar

n/a

n/a

n/a

(550)

(550)

Upstream

n/a

n/a

n/a

(25)

(25)

Utility Smart Grid/Smart Meter

(125)

(100)

(175)

n/a

(400)

Net Financing (excluding

Dividend):

Debt Issuances

(4)

300

250

350

--

900

Debt Retirements

(5)

(400)

(250)

(300)

(450)

(1,400)

Project Finance/Federal Financing

Bank Loan

n/a

n/a

n/a

1,025

1,025

Other

(6)

50

100

(75)

(25)

75

Ending Cash Balance

(1)

1,350

(7)

2013 1Q Earnings Release Slides

Pension/OPEB Update 

19

2013 1Q Earnings Release Slides

Note: Estimates are based on 12/31/12 with expenses for legacy Exelon plans  updated for March 2013 census

2013

2014

(in $M)

Pre-Tax Expense

(1)

Contributions

(2)

Pre-Tax Expense

(1)

Contributions

(2)

Pension

$400

$335

$415

$275

OPEB

$220

$290

$220

$275

Total

$620

$625

$635

$550

(1)     Pension and OPEB expenses assume an ~ 24% capitalization rate.

(2)     Contributions shown in the table above are based on the current contribution policy for Exelon and Constellation plans.  Pension includes qualified    

          and non-qualified plans.

2013 1Q Earnings Release Slides

Sufficient Liquidity

(1)

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

(2)

Available Capacity Under Facilities represents the unused commitments under the borrower’s credit agreements net of outstanding letters of credit and

facility

draws.

The

amount

of

commercial

paper

outstanding

does

not

reduce

the

available

capacity

under

the

credit

agreements.

20

2013 1Q Earnings Release Slides

($ in Millions)

Aggregate

Bank

Commitments

(1)

600

1,000

600

5,675

8,375

Outstanding Facility Draws

--

--

--

--

--

Outstanding Letters of Credit

--

--

(1)

(1,475)

(1,478)

Available

Capacity

Under

Facilities

(2)

600

1,000

599

4,200

6,897

Outstanding Commercial Paper

--

(281)

--

--

(281)

Available Capacity Less Outstanding

Commercial Paper

600

719

599

4,200

6,616

Available Capacity Under Bank Facilities as of April 25, 2013

S&P Credit Metric Ratios

2013 1Q Earnings Release Slides

21

S&P Metrics

FFO / Debt

Credit Adjustments - Cash From Operations:

Source (2012 10K):

Methodology:

Cash From Operations

Stmt. of Cash Flows

Start with net cash flows provided by operating activities

(+/-) Working Capital Adjustments

Stmt. of Cash Flows

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

premiums, counterparty collateral and income taxes.  Impact is opposite of impact

to cash flow

S&P FFO Adjustments:

(+) Operating Lease Depreciation Adjustment

FN 19 - Commitments & Contingencies - Minimum Future Lease Payments

Reflects operating lease payments  – interest on PV of future operating lease

payments (using weighted average cost of debt)

(+) PPA Depreciation Adjustment

FN 19 - Commitments & Contingencies - Net Capacity Purchases

Reflects net capacity payments – interest on PV of PPAs (using weighted average

cost of debt)

(+/-) Normalize Pension/OPEB Contribution

FN 14 - Retirement Benefits - Contributions, Service & Int Costs, EROA

Reflects employer contributions – (service costs + interest costs + expected

return on assets), net of taxes at marginal rate

(-) Securitized Debt Principal Paydown

FN 11 - Debt and Credit Agreements

Reflects payment of principal on securitized debt

(+/-) Decommissioning classified as Investing

Stmt. of Cash Flows

Reclass activity classified as Investing to Cash from Operations

(-) Interest Capitalized / AFUDC

FN 1 - Accounting Policies - Capitalized Interest and AFUDC

Reclass activity classified as Investing to Cash from Operations

(+/-) Interest or Dividend on Hybrid Securities

FN 11 - Debt and Credit Agreements

Remove/add interest expense/dividend payments associated with instruments

that qualify as hybrid securites (treated all or partially as debt or equity)

(+/-) Other Adjustments

N/A

One-time or non-standard adjustments at discretion of rating agency

= Funds from Operations (FFO)

Credit Adjustments - Debt:

Source (2012 10K):

Methodology:

Total Long-term Debt (including current maturities)

Balance Sheet

Start with long-term debt outstanding

(+) Short-term Borrowings

Balance Sheet

Reflects short-terms borrowings (commerical paper, notes payable etc.)

S&P Debt Adjustments:

(+) Operating Leases

FN 19 - Commitments & Contingencies - Minimum Future Lease Payments

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

cost of debt)

(+) PPAs / Supply Agreements

FN 19 - Commitments & Contingencies - Net Capacity Purchases

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

(+) Unfunded Pension

FN 14 - Retirement Benefits - Unfunded Status

Reflects unfunded status, net of taxes at marginal rate

(+) Unfunded OPEB

FN 14 - Retirement Benefits - Unfunded Status

Reflects unfunded status, net of taxes at marginal rate

(-) Securitized Debt

FN 11 - Debt and Credit Agreements

Reflects securitized debt balance at year-end

(+) Accrued Interest

Supplemental Balance Sheet

Annual accrued interest

(+) Asset Retirement Obligation

Balance Sheet

If net obligation > 0, include net obligation, net of taxes at marginal rate

(+/-) Hybrid Securities

FN 11 - Debt and Credit Agreements

Reclassify instruments that qualify as hybrid securites between debt and equity

(treated all or partially as debt or equity)

(-) Off-credit Treatment of Debt

FN 11 - Debt and Credit Agreements

Non-recourse project level debt that qualifies for off-credit treatment under S&P's

methodology

(+/-) Other Adjustments

N/A

One-time or non-standard adjustments at discretion of rating agency

=  Adjusted Debt

Funds from Operations / Adjusted Debt

Calculation

Note:  See S&P publications for official guidelines, criteria and methodology

Reflects key credit ratio calculations and adjustments per S&P’s guidelines

Moody’s Credit Metric Ratios

2013 1Q Earnings Release Slides

22

Note:  See Moody’s publications for official guidelines, criteria and methodology

Note:  Moody’s Approach to Global Standard Adjustments for Non-Financial Corporations allows for Analyst discretion whether to incorporate imputed debt (and other associated

adjustments) for PPAs/tolls.  Moody’s official methodology for Exelon and subs does not include PPAs/tolls; however they view credit metrics both with and without

Reflects key credit ratio calculations and adjustments per Moody’s guidelines

Moody's Metrics

Cash From Ops (pre w/c) / Debt

Cash From Ops (pre w/c) / Adjusted Debt

Retained Cash Flow / Debt

(Adjusted FFO -

Adjusted Dividend) / Adjusted Debt

Free Cash Flow

Credit Adjustments -

Cash from Operations:

Source (2012 10K):

Methodology:

Cash From Operations

Stmt. of Cash Flows

Start with net cash flows provided by operating activities

(+/-) Working Capital Adjustments and changes in short-

terms assets and liabilities

Stmt. of Cash Flows and Supplemental Cash Flow Information

Includes changes in A/R, Inventories, A/P and other accrued expenses, counterparty collateral,

income taxes, under/over-recovered energy and transmission costs, other current assets. 

Impact is opposite of impact to cash flow

Moody's Cash From Ops Adjustments:

(+) Operating Lease Depreciation Adjustment

FN 19 -

Commitments & Contingencies -

Rental Expense

Equals annual rent expense x 2/3 (remaining 1/3 is allocated to interest)

(+) Normalize Pension/OPEB Contribution

FN 14 -

Retirement Benefits -

Contributions, Service Costs

Reflects employer contributions –

service costs, if > $0, otherwise $0

(-) Interest Capitalized / AFUDC

FN 1 -

Accounting Policies -

Capitalized Interest and AFUDC

Reclass activity classified as Investing to Cash from Operations

(+/-) Interest or Dividend on Hybrid Securities

FN 11 -

Debt and Credit Agreements

Remove/add interest expense/dividend payments associated with instruments that qualify as

hybrid securites (treated all or partially as debt or equity)

(+/-) Other Adjustments

N/A

One-time or non-standard adjustments at discretion of rating agency

= Cash from Ops (pre w/c)

Credit Adjustments -

FFO:

Source (2012 10K):

Methodology:

Net Income

Stmt. of Cash Flows

Start with net income

(+/-) Non-cash adjustments to cash flows

Stmt. of Cash Flows

Includes depreciation and amortization, deferred income taxes, net fair value change in

derivatives, net realized/unrealized gains/losses on decom funds, other non-cash

operating

activities

Moody's FFO Adjustments:

*** same as Cash from Ops Adjustments listed above ***

= Adjusted FFO

Credit Adjustments -

CapEx:

Source (2012 10K):

Methodology:

Capital Expenditures

Stmt. of Cash Flows

Start with capital expenditures

Moody's CapEx Adjustments:

(+) Operating Leases CapEx

FN 19 -

Commitments & Contingencies -

Rental Expense

Reclass of operatng spend to capital; equal to operating lease deprecation adjustment

(-) Interest Capitalized / AFUDC

FN 1 -

Accounting Policies -

Capitalized Interest and AFUDC

Reclass activity classified as Investing to Cash from Operations

=  Adjusted CapEx

Credit Adjustments -

Debt:

Source (2012 10K):

Methodology:

Total Long-term Debt (incl. current maturities)

Balance Sheet

Start with long-term debt outstanding

(+) Short-term Borrowings

Balance Sheet

Reflects short-terms borrowings (commerical paper, notes payable etc.)

Moody's Debt Adjustments:

(+) Unfunded Pension

FN 14 -

Retirement Benefits -

Unfunded Status

Reflects unfunded status (pension only)

(+/-) Hybrid Securities

FN 11 -

Debt and Credit Agreements

Reclassify instruments that qualify as hybrid securites between debt and equity (treated all or

partially as debt or equity)

(+) Operating Leases

FN 19 -

Commitments & Contingencies -

Minimum Future Lease Payments

Annual rent expense x multiple between 4 and 10 (currently 8 for

ExGen/Corp and 6 for utilities)

(+/-) Other Adjustments

N/A

One-time or non-standard adjustments at discretion of rating agency

=  Adjusted Debt

Credit Adjustments -

Dividend:

Source (2012 10K):

Methodology:

Common Dividends

Stmt. of Cash Flows

Start with common dividends

(+) Preferred Dividends

Stmt. of Cash Flows

Reflects dividends on preferred securities

Moody's Dividend Adjustments:

(+) Hybrid Securities

FN 11 -

Debt and Credit Agreements

Remove/add dividend payments/interest expense associated with instruments that qualify as

hybrid securites (treated all or partially as equity or debt)

=  Adjusted Dividend

Cash

From

Operations

+

Moody's

Cash

From

Ops

Adjustments

-

Adjusted

Dividend

-

Adjusted

CapEx

Calculation

2013 1Q Earnings Release Slides

23

ComEd April 2013 Distribution Formula Rate 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.

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.  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.

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.

24

BGE Rate Case Final Order

Electric

Gas

Docket #

9299

Test Year

October 2011 –

September 2012

BGE Ask

Final Order

BGE Ask

Final Order

Common Equity Ratio

48.4%

48.4%

48.4%

48.4%

Return on Equity (ROE)

10.5%

9.75%

10.5%

9.6%

Rate Base

$2.7B

$2.6B

$1B

$1.0B

Revenue Requirement Increase

$131M

$81M

$45M

$32M

2013 1Q Earnings Release Slides

New rates went into effect for service rendered on or after February 23, 2013

ComEd Operating EPS Contribution

Key

Drivers

–

1Q13

vs.

1Q12

(1)

Share differential: $(0.02)

Weather: $0.01

1Q13

Actual

Actual   Normal

Heating Degree-Days

2,384       3,259       3,164

Cooling Degree-Days              39

0            0       

1Q12

25

2013 1Q Earnings Release Slides

$0.13

$0.10

1Q

2013

2012

(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.

PECO Operating EPS Contribution

Key

Drivers

–

1Q13

vs.

1Q12

(1)

Share differential: $(0.03)

Weather: $0.03

1Q13

Actual

Actual   Normal

Heating Degree-Days      1,914         2,440        2,476

Cooling Degree-Days           4 

0             0        

1Q12

26

2013 1Q Earnings Release Slides

$0.14

$0.14

1Q

2013

2012

(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.

1Q GAAP EPS Reconciliation

Three Months Ended March 31, 2013

ExGen

ComEd

PECO

BGE

Other

Exelon

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

$0.39

$0.10

$0.14

$0.09

$(0.02)

$0.70

Mark-to-market impact of economic hedging activities

(0.29)

-

-

-

0.01

(0.27)

Unrealized gains related to nuclear decommissioning trust funds

0.04

-

-

-

-

0.04

Plant retirements and divestitures

0.02

-

-

-

-

0.02

Constellation merger and integration costs

(0.03)

-

(0.00)

0.00

0.00

(0.03)

Amortization of commodity contract intangibles

(0.14)

-

-

-

-

(0.14)

Amortization of the fair value of certain debt

0.00

-

-

-

-

0.00

Remeasurement of like-kind exchange tax position

-

(0.20)

-

-

(0.11)

(0.31)

Nuclear uprate project cancelation

(0.02)

-

-

-

-

(0.02)

1Q 2013 GAAP Earnings (Loss) Per Share

$(0.02)

$(0.09)

$0.14

$0.09

$(0.12)

$(0.01)

Three Months Ended March 31, 2012

ExGen

ComEd

PECO

BGE

Other

Exelon

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

$0.58

$0.13

$0.14

$0.02

$(0.02)

$0.85

Mark-to-market impact of economic hedging activities

0.05

-

-

-

0.01

0.06

Unrealized gains related to nuclear decommissioning trust funds

0.05

-

-

-

-

0.05

Plant retirements and divestitures

(0.01)

-

-

-

-

(0.01)

Constellation merger and integration costs

(0.06)

(0.00)

(0.01)

(0.00)

(0.09)

(0.16)

Maryland commitments

(0.03)

-

-

(0.12)

(0.17)

(0.32)

Amortization of commodity contract intangibles

(0.11)

-

-

-

-

(0.11)

FERC settlement

(0.25)

-

-

-

-

(0.25)

Non-cash remeasurement of deferred income taxes

0.02

-

-

-

0.15

0.17

Other acquisition costs

(0.00)

-

-

-

-

(0.00)

1Q 2012 GAAP Earnings (Loss) Per Share

$0.24

$0.12

$0.14

$(0.09)

$(0.12)

$0.28

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

2013 1Q Earnings Release Slides

27

GAAP to Operating Adjustments

•

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 from nuclear decommissioning trust 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 related to the Constellation merger and integration initiatives

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

the merger date

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

2013

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

position

Charge to earnings related to Exelon’s cancelation of previously capitalized nuclear uprate expenditures

Significant impairments of assets, including goodwill

Significant changes to GAAP

Other unusual items

2013 1Q Earnings Release Slides

28