Exhibit 99.1

News Release

Contact: JaCee Burnes Investor Relations 312-394-2948   Judy Rader Corporate Communications 312-394-7417 FOR IMMEDIATE RELEASE

EXELON ANNOUNCES SECOND QUARTER 2012 RESULTS

CHICAGO (Aug. 1, 2012) – Exelon Corporation (NYSE: EXC) announced second quarter 2012 consolidated earnings as follows:

	Second Quarter
	2012		2011
Adjusted (non-GAAP) Operating Results:
Net Income ($ millions)	$	522	$	697
Diluted Earnings per Share	$	0.61	$	1.05
GAAP Results:
Net Income ($ millions)	$	286	$	620
Diluted Earnings per Share	$	0.33	$	0.93

“We have delivered on our financial and operating commitments with solid second quarter earnings, and are reaffirming our full-year operating earnings guidance of $2.55 to $2.85 per share.” said Christopher M. Crane, Exelon’s president and CEO. “Our businesses are performing well. Exelon Generation’s nuclear fleet achieved a capacity factor of 93.4 percent, and our delivery companies – BGE, ComEd and PECO – provided strong operational and financial performance for the quarter. We are also pleased with the results of our merger integration efforts to date and are confident of realizing the value investors expect from the Exelon-Constellation merger.”

Second Quarter Operating Results

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

1

As shown in the table above, Exelon’s adjusted (non-GAAP) operating earnings declined to $0.61 per share in the second quarter of 2012 from $1.05 per share in the second quarter of 2011. Earnings in second quarter 2012 primarily reflected the following negative factors:

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

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

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

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

These factors were partially offset by:

• The addition of BGE’s financial results and Constellation’s contribution to Generation’s energy margins; and

• Fewer nuclear outage days.

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

	(in millions)			(per diluted share)
Mark-to-market gains primarily from Generation’s economic hedging activities, net of intercompany eliminations	$	123		$	0.15
Unrealized losses related to Nuclear Decommissioning Trust (NDT) fund investments to the extent not offset by contractual accounting	$	(19	)	$	(0.02	)
Financial impacts associated with plant retirements and divestitures	$	1			—
Certain costs related to the merger and integration initiatives	$	(67	)	$	(0.08	)
Non-cash amortization of intangible assets, net, related to commodity contracts recorded at fair value at the merger date	$	(281	)	$	(0.33	)
Non-cash amortization of certain debt recorded at fair value at the merger date	$	3			—
Non-cash benefit resulting from reassessment of state deferred income taxes	$	4			—

2

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

	(in millions)			(per diluted share)
Mark-to-market losses primarily from Generation’s economic hedging activities	$	(75	)	$	(0.12	)
Unrealized gains related to NDT fund investments to the extent not offset by contractual accounting	$	6		$	0.01
One-time benefits for the recovery of previously incurred costs per ComEd’s 2011 distribution rate case order	$	17		$	0.03
Certain costs related to the merger and integration initiatives	$	(15	)	$	(0.02	)
Financial impacts associated with the planned retirement of certain Generation fossil generating units	$	(10	)	$	(0.02	)

Second Quarter and Recent Highlights

• Nuclear Operations: Generation’s nuclear fleet, including its owned output from the Salem Generating Station, produced 35,137 gigawatt-hours (GWh) in the second quarter of 2012, compared with 33,167 GWh in the second quarter of 2011. The output data excludes the units owned by Constellation Energy Nuclear Group LLC (CENG). Excluding Salem and the units owned by CENG, the Exelon-operated nuclear plants achieved a 93.4 percent capacity factor for the second quarter of 2012 compared with 89.6 percent for the second quarter of 2011. The Exelon-operated nuclear plants completed one scheduled refueling outage in the second quarter of 2012, compared with completing two scheduled refueling outages in the second quarter of 2011. The number of planned refueling outage days totaled 51 in the second quarter of 2012 versus 103 days in the second quarter of 2011. The number of non-refueling outage days at the Exelon-operated plants totaled 16 days in the second quarter of 2012 compared with 24 days in the second quarter of 2011.

• Fossil and Renewables Operations: The equivalent demand forced outage rate for Generation’s fossil fleet is 4.5 percent in the first half of 2012, compared with 5.0 percent in the first half of 2011. The 2012 fossil fleet results include former Constellation plants, exclusive of the Maryland Clean Coal plants to be sold, whereas 2011 data include only legacy Exelon plants. The equivalent availability factor for the hydroelectric facilities was 96.2 percent in the second quarter of 2012, compared with 93.4 percent in the second quarter of 2011. The change was largely due to planned outages in April 2011. The energy capture for the wind fleet was 95.0 percent in the second quarter of 2012, compared with 93.0 percent in the second quarter of 2011.

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• ComEd Distribution Formula Rate Cases: On November 8, 2011, ComEd filed its initial formula rate tariff and associated testimony based on 2010 costs and 2011 plant additions. The primary purpose of this initial proceeding was to establish the formula rate under which rates will be calculated going-forward, and the initial rates, which went into effect in late June. On May 30, 2012 the Illinois Commerce Commission (ICC) issued its final Order (Order) in ComEd’s 2011 formula rate proceeding under the Energy Infrastructure Modernization Act (EIMA). The Order reduced the annual revenue requirement by $168 million, or approximately $110 million more than the reduction proposed by ComEd. Of this incremental revenue requirement reduction, approximately $50 million reflected the ICC’s determination that certain costs should be recovered through alternative rate recovery tariffs available to ComEd or will be reflected in the annual reconciliation, thereby primarily delaying the timing of cash flows. In the second quarter of 2012, ComEd recorded a reduction of revenue of approximately $100 million pre-tax to decrease the regulatory asset for the 2011 and 2012 reconciliations consistent with the terms of the Order. On June 22, 2012 the ICC granted expedited rehearing on ComEd’s pension asset recovery, the use of average or year-end rate base in determining ComEd’s reconciliation revenue requirement and the interest rate charged on over/under recovered costs. A final order on rehearing is due by September 19, 2012.

• BGE Electric and Gas Distribution Rate Case: On July 27, 2012, BGE filed an application for increases of $151 million and $53 million to its electric and gas base rates, respectively with the Maryland Public Service Commission (MDPSC). The requested rate of return on equity in the application is 10.5 percent. The MDPSC will determine any increase in rates after a 7-month proceeding with input from all interested parties. The new electric and gas distribution base rates are expected to take effect in late February 2013.

• Debt Exchange: On June 13, 2012, Generation commenced private offers to certain eligible holders to exchange any and all of the $700 million outstanding 7.60 percent Senior Notes due 2032 (Old Notes) of Exelon Corporation which were assumed by Exelon in the merger with Constellation Energy Group, Inc., for:

– Generation’s newly issued 4.25 percent Senior Notes due 2022, plus a cash payment; and

– Generation’s newly issued 5.60 percent Senior Notes due 2042, plus a cash payment.

Pursuant to an exchange offer completed on July 12, 2012, Generation purchased $442 million of the outstanding Old Notes in exchange for issuing $535 million of new notes, including a cash payment of $60 million. Generation incurred gains associated with the early retirement of debt of approximately $13 million as a result of paying a price less than book value of the Old Notes. The gain was recorded as an increase to Long-term Debt within Generation’s Consolidated Balance Sheets and will be amortized to income over the life of the debt as a reduction in interest expense.

4

• Hedging Update: Exelon’s hedging program involves the hedging of commodity risk for Exelon’s expected generation, typically on a ratable basis over a three-year period. Expected generation represents the amount of energy estimated to be generated or purchased through owned or contracted-for capacity. The proportion of expected generation hedged as of June 30, 2012 is 99 to 102 percent for 2012, 79 to 82 percent for 2013 and 46 to 49 percent for 2014. The primary objective of Exelon’s hedging program is to manage market risks and protect the value of its generation and its investment grade balance sheet while preserving its ability to participate in improving long-term market fundamentals.

Operating Company Results

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

Second quarter 2012 net income was $166 million compared with $443 million in the second quarter of 2011. Second quarter 2012 net income included (all after tax) mark-to-market gains of $120 million from economic hedging activities, unrealized losses of $19 million related to Nuclear Decommissioning Trust (NDT) fund investments, a net impact of $1 million for plant retirements and divestitures, certain costs of $57 million associated with the merger and integration initiatives, amortization of commodity contract intangibles of $281 million and $3 million of amortization of the fair value of certain debt expected to be retired in 2013. Second quarter 2011 net income included (all after tax) mark-to-market losses of $75 million from economic hedging activities, net costs of $10 million associated with the planned retirement of certain fossil generating units, unrealized gains of $6 million related to NDT fund investments and certain costs of $1 million associated with the proposed merger with Constellation.

Excluding the effects of these items, Generation’s net income in the second quarter of 2012 decreased $124 million compared with the same quarter in 2011. This decrease primarily reflected:

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

• Higher operating and maintenance expenses; and

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

These items were partially offset by increased nuclear volumes, lower nuclear refueling outage costs and the contribution to Generation’s energy margins from Constellation.

5

Generation’s average realized margin on all electric sales, including sales to affiliates and excluding trading activity, was $26.15 per megawatt-hour (MWh) in the second quarter of 2012 compared with $41.59 per MWh in the second quarter of 2011.

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

ComEd recorded net income of $42 million in the second quarter of 2012, compared with net income of $114 million in the second quarter of 2011. Second quarter net income in 2011 included an after-tax non-cash credit of $17 million for the recovery of previously incurred costs pursuant to the 2011 distribution rate case order. Excluding the effects of this item, ComEd’s net income in the second quarter of 2012 was down $55 million from the same quarter in 2011, primarily due to decreased distribution revenues as a result of a final order issued by the ICC on the 2011 performance based formula rate proceeding under the EIMA, higher operating and maintenance expenses reflecting increased labor and contracting costs driven, in part by EIMA initiatives and one-time benefits recorded in the second quarter of 2011 related to the 2011 ComEd electric distribution rate case.

These unfavorable items were partially offset by the effect of favorable weather in ComEd’s service territory and lower interest expense.

In the second quarter of 2012, heating degree-days in the ComEd service territory were down 33.9 percent relative to the same period in 2011 and were 28.9 percent below normal. For the second quarter of 2012, cooling degree-days in the ComEd service territory were up 78.5 percent relative to the same period in 2011 and were 94.0 percent above normal. Total retail electric deliveries increased 3.2 percent quarter over quarter.

Weather-normalized retail electric deliveries decreased 1.3 percent in the second quarter of 2012 relative to 2011, reflecting decreases in deliveries to both residential and small commercial and industrial (C&I) customers that were partially offset by an increase in deliveries to large C&I customers. For ComEd, weather had a favorable after-tax effect of $11 million on second quarter 2012 earnings relative to 2011 and a favorable after-tax effect of $12 million relative to normal weather.

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

PECO’s net income in the second quarter of 2012 was $79 million, compared with $82 million in the second quarter of 2011. Second quarter net income in 2012 included certain after-tax costs of $2 million associated with the merger and integration initiatives. Excluding the effect of this item, PECO’s net income in the second quarter of 2012 was down $1 million from the same quarter in 2011, primarily reflecting the effect of unfavorable weather in PECO’s service territory and lower load.

These unfavorable items were partially offset by lower operating and maintenance expenses reflecting decreased labor and contracting costs.

In the second quarter of 2012, heating degree-days in the PECO service territory were up 1.8 percent from 2011 and were 27.2 percent below normal. Total retail electric deliveries were down 4.5 percent quarter over quarter. On the retail gas side, deliveries in the second quarter of 2012 were down 6.0 percent from the second quarter of 2011.

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Weather-normalized retail electric deliveries were down 2.7 percent in the second quarter of 2012 relative to 2011, reflecting declines in deliveries to all customer classes. Weather-normalized retail gas deliveries were down 3.7 percent in the second quarter of 2012. For PECO, weather had an unfavorable after-tax effect of $8 million on second quarter 2012 earnings relative to 2011 and a favorable after-tax effect of $1 million relative to normal weather.

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

BGE’s net income in the second quarter of 2012 was $13 million. The net income included after-tax costs of $1 million associated with the merger and integration initiatives. Excluding the effects of these items, BGE’s net income in the second quarter of 2012 was $14 million.

Adjusted (non-GAAP) Operating Earnings

Adjusted (non-GAAP) operating earnings, which generally exclude significant one-time charges or credits that are not normally associated with ongoing operations, mark-to-market adjustments from economic hedging activities and unrealized gains and losses from NDT fund investments, are provided as a supplement to results reported in accordance with GAAP. Management uses such adjusted (non-GAAP) operating earnings measures internally to evaluate the company’s performance and manage its operations. Reconciliation of GAAP to adjusted (non-GAAP) operating earnings for historical periods is attached. Additional earnings release attachments, which include the reconciliation on pages 7 and 8, are posted on Exelon’s Web site: www.exeloncorp.com and have been furnished to the Securities and Exchange Commission on Form 8-K on August 1, 2012.

Cautionary Statements Regarding Forward-Looking Information

This news release contains certain forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995, that are subject to risks and uncertainties. The factors that could cause actual results to differ materially from the forward-looking statements made by Exelon Corporation, Commonwealth Edison Company, PECO Energy Company, Baltimore Gas and Electric Company and Exelon Generation Company, LLC (Registrants) include those factors discussed herein, as well as the items discussed in (1) Exelon’s 2011 Annual Report on Form 10-K in (a) ITEM 1A. Risk Factors, (b) ITEM 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations and (c) ITEM 8. Financial Statements and

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Supplementary Data: Note 18; (2) Constellation Energy Group’s 2011 Annual Report on Form 10-K in (a) ITEM 1A. Risk Factors, (b) ITEM 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations and (c) ITEM 8. Financial Statements and Supplementary Data: Note 12; (3) the Registrant’s First Quarter 2012 Quarterly Report on Form 10-Q in (a) Part II, Other Information, ITEM 1A. Risk Factors and (b) Part I, Financial Information, ITEM 1. Financial Statements: Note 15; and (4) other factors discussed in filings with the SEC by the Registrants. Readers are cautioned not to place undue reliance on these forward-looking statements, which apply only as of the date of this 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.

###

Exelon Corporation is the nation’s leading competitive energy provider, with approximately $33 billion in annual revenues. Headquartered in Chicago, Exelon has operations and business activities in 47 states, the District of Columbia and Canada. Exelon is the largest competitive U.S. power generator, with approximately 35,000 megawatts of owned capacity comprising one of the nation’s cleanest and lowest-cost power generation fleets. The company’s Constellation business unit provides energy products and services to approximately 100,000 business and public sector customers and approximately 1 million residential customers. Exelon’s utilities deliver electricity and natural gas to more than 6.6 million customers in central Maryland (BGE), northern Illinois (ComEd) and southeastern Pennsylvania (PECO).

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Earnings Release Attachments

Table of Contents

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

EXELON CORPORATION

Consolidating Statements of Operations

(unaudited)

(in millions)

	Three Months Ended June 30, 2012
	Generation			ComEd			PECO			BGE			Other (a)			Exelon Consolidated
Operating revenues	$	3,753		$	1,281		$	715		$	616		$	(411	)	$	5,954
Operating expenses
Purchased power and fuel		1,852			587			296			285			(414	)		2,606
Operating and maintenance		1,209			331			172			161			(2	)		1,871
Depreciation, amortization, accretion and depletion		204			152			54			71			13			494
Taxes other than income		90			69			42			47			6			254
Total operating expenses		3,355			1,139			564			564			(397	)		5,225
Equity in loss of unconsolidated affiliates		(57	)		—			—			—			—			(57	)
Operating income (loss)		341			142			151			52			(14	)		672
Other income and deductions
Interest expense		(85	)		(74	)		(31	)		(34	)		(32	)		(256	)
Other, net		(33	)		3			2			7			20			(1	)
Total other income and deductions		(118	)		(71	)		(29	)		(27	)		(12	)		(257	)
Income (loss) before income taxes		223			71			122			25			(26	)		415
Income taxes		58			29			42			9			(12	)		126
Net income (loss)		165			42			80			16			(14	)		289
Net loss attributable to noncontrolling interests, preferred security dividends and preference stock dividends		(1	)		—			1			3			—			3
Net income (loss) on common stock	$	166		$	42		$	79		$	13		$	(14	)	$	286
	Three Months Ended June 30, 2011
	Generation			ComEd			PECO			BGE			Other (a)			Exelon Consolidated
Operating revenues	$	2,455		$	1,444		$	842		$	—		$	(245	)	$	4,496
Operating expenses
Purchased power and fuel		841			716			408			—			(249	)		1,716
Operating and maintenance		763			268			172			—			23			1,226
Depreciation, amortization, accretion and depletion		138			136			50			—			5			329
Taxes other than income		66			70			51			—			4			191
Total operating expenses		1,808			1,190			681			—			(217	)		3,462
Operating income (loss)		647			254			161			—			(28	)		1,034
Other income and deductions
Interest expense		(45	)		(86	)		(34	)		—			(17	)		(182	)
Other, net		76			4			3			—			18			101
Total other income and deductions		31			(82	)		(31	)		—			1			(81	)
Income (loss) before income taxes		678			172			130						(27	)		953
Income taxes		235			58			47			—			(8	)		332
Net income (loss)		443			114			83			—			(19	)		621
Preferred security dividends		—			—			1			—			—			1
Net income (loss) on common stock	$	443		$	114		$	82		$	—		$	(19	)	$	620

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

1

EXELON CORPORATION

Consolidating Statements of Operations

(unaudited)

(in millions)

	Six Months Ended June 30, 2012 (a)
	Generation			ComEd			PECO			BGE			Other (b)			Exelon Consolidated
Operating revenues	$	6,492		$	2,670		$	1,590		$	668		$	(780	)	$	10,640
Operating expenses
Purchased power and fuel		2,896			1,208			707			352			(792	)		4,371
Operating and maintenance		2,382			650			375			222			206			3,835
Depreciation, amortization, accretion and depletion		357			300			107			90			22			876
Taxes other than income		164			144			74			57			9			448
Total operating expenses		5,799			2,302			1,263			721			(555	)		9,530
Equity in loss of unconsolidated affiliates		(79	)		—			—			—			—			(79	)
Operating income (loss)		614			368			327			(53	)		(225	)		1,031
Other income and deductions
Interest expense		(138	)		(156	)		(62	)		(42	)		(53	)		(451	)
Other, net		145			7			5			8			29			194
Total other income and deductions		7			(149	)		(57	)		(34	)		(24	)		(257	)
Income (loss) before income taxes		621			219			270			(87	)		(249	)		774
Income taxes		289			90			93			(38	)		(150	)		284
Net income (loss)		332			129			177			(49	)		(99	)		490
Net loss attributable to noncontrolling interests, preferred security dividends and preference stock dividends		(2	)		—			2			4			—			4
Net income (loss) on common stock	$	334		$	129		$	175		$	(53	)	$	(99	)	$	486
	Six Months Ended June 30, 2011
	Generation			ComEd			PECO			BGE			Other (b)			Exelon Consolidated
Operating revenues	$	5,098		$	2,910		$	1,996		$	—		$	(553	)	$	9,451
Operating expenses
Purchased power and fuel		1,724			1,505			1,042			—			(555	)		3,716
Operating and maintenance		1,517			534			378			—			20			2,449
Depreciation, amortization, accretion and depletion		277			270			98			—			11			656
Taxes other than income		132			147			106			—			9			394
Total operating expenses		3,650			2,456			1,624			—			(515	)		7,215
Operating income (loss)		1,448			454			372			—			(38	)		2,236
Other income and deductions
Interest expense		(91	)		(172	)		(68	)		—			(32	)		(363	)
Other, net		152			8			8			—			28			196
Total other income and deductions		61			(164	)		(60	)		—			(4	)		(167	)
Income (loss) before income taxes		1,509			290			312			—			(42	)		2,069
Income taxes		571			107			102			—			(1	)		779
Net income (loss)		938			183			210			—			(41	)		1,290
Preferred security dividends		—			—			2			—			—			2
Net income (loss) on common stock	$	938		$	183		$	208		$	—		$	(41	)	$	1,288

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

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

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EXELON CORPORATION

Business Segment Comparative Statements of Operations

(unaudited)

(in millions)

	Generation
	Three Months Ended June 30,									Six Months Ended June 30,
	2012			2011			Variance			2012 (a)			2011			Variance
Operating revenues	$	3,753		$	2,455		$	1,298		$	6,492		$	5,098		$	1,394
Operating expenses
Purchased power and fuel		1,852			841			1,011			2,896			1,724			1,172
Operating and maintenance		1,209			763			446			2,382			1,517			865
Depreciation, amortization, accretion and depletion		204			138			66			357			277			80
Taxes other than income		90			66			24			164			132			32
Total operating expenses		3,355			1,808			1,547			5,799			3,650			2,149
Equity in loss of unconsolidated affiliates		(57	)		—			(57	)		(79	)		—			(79	)
Operating income		341			647			(306	)		614			1,448			(834	)
Other income and deductions
Interest expense		(85	)		(45	)		(40	)		(138	)		(91	)		(47	)
Other, net		(33	)		76			(109	)		145			152			(7	)
Total other income and deductions		(118	)		31			(149	)		7			61			(54	)
Income before income taxes		223			678			(455	)		621			1,509			(888	)
Income taxes		58			235			(177	)		289			571			(282	)
Net income		165			443			(278	)		332			938			(606	)
Net loss attributable to noncontrolling interests		(1	)		—			(1	)		(2	)		—			(2	)
Net income on common stock	$	166		$	443		$	(277	)	$	334		$	938		$	(604	)

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

	ComEd
	Three Months Ended June 30,									Six Months Ended June 30,
	2012			2011			Variance			2012			2011			Variance
Operating revenues	$	1,281		$	1,444		$	(163	)	$	2,670		$	2,910		$	(240	)
Operating expenses
Purchased power		587			716			(129	)		1,208			1,505			(297	)
Operating and maintenance		331			268			63			650			534			116
Depreciation and amortization		152			136			16			300			270			30
Taxes other than income		69			70			(1	)		144			147			(3	)
Total operating expenses		1,139			1,190			(51	)		2,302			2,456			(154	)
Operating income		142			254			(112	)		368			454			(86	)
Other income and deductions
Interest expense		(74	)		(86	)		12			(156	)		(172	)		16
Other, net		3			4			(1	)		7			8			(1	)
Total other income and deductions		(71	)		(82	)		11			(149	)		(164	)		15
Income before income taxes		71			172			(101	)		219			290			(71	)
Income taxes		29			58			(29	)		90			107			(17	)
Net income	$	42		$	114		$	(72	)	$	129		$	183		$	(54	)

3

EXELON CORPORATION

Business Segment Comparative Statements of Operations

(unaudited)

(in millions)

	PECO
	Three Months Ended June 30,									Six Months Ended June 30,
	2012			2011			Variance			2012			2011			Variance
Operating revenues	$	715		$	842		$	(127	)	$	1,590		$	1,996		$	(406	)
Operating expenses
Purchased power and fuel		296			408			(112	)		707			1,042			(335	)
Operating and maintenance		172			172			—			375			378			(3	)
Depreciation and amortization		54			50			4			107			98			9
Taxes other than income		42			51			(9	)		74			106			(32	)
Total operating expenses		564			681			(117	)		1,263			1,624			(361	)
Operating income		151			161			(10	)		327			372			(45	)
Other income and deductions
Interest expense		(31	)		(34	)		3			(62	)		(68	)		6
Other, net		2			3			(1	)		5			8			(3	)
Total other income and deductions		(29	)		(31	)		2			(57	)		(60	)		3
Income before income taxes		122			130			(8	)		270			312			(42	)
Income taxes		42			47			(5	)		93			102			(9	)
Net income		80			83			(3	)		177			210			(33	)
Preferred security dividends		1			1			—			2			2			—
Net income on common stock	$	79		$	82		$	(3	)	$	175		$	208		$	(33	)
	BGE
	Three Months Ended June 30,									March 12, 2012 through June 30, 2012
	2012			2011			Variance			2012			2011			Variance
Operating revenues	$	616		$	—		$	616		$	668		$	—		$	668
Operating expenses
Purchased power and fuel		285			—			285			352			—			352
Operating and maintenance		161			—			161			222			—			222
Depreciation and amortization		71			—			71			90			—			90
Taxes other than income		47			—			47			57			—			57
Total operating expenses		564			—			564			721			—			721
Operating loss		52			—			52			(53	)		—			(53	)
Other income and deductions
Interest expense		(34	)		—			(34	)		(42	)		—			(42	)
Other, net		7			—			7			8			—			8
Total other income and deductions		(27	)		—			(27	)		(34	)		—			(34	)
Loss before income taxes		25			—			25			(87	)		—			(87	)
Income taxes		9			—			9			(38	)		—			(38	)
Net loss		16			—			16			(49	)		—			(49	)
Preference stock dividends		3			—			3			4			—			4
Net loss on common stock	$	13		$	—		$	13		$	(53	)	$	—		$	(53	)

4

EXELON CORPORATION

Business Segment Comparative Statements of Operations

(unaudited)

(in millions)

	Other (a)
	Three Months Ended June 30,									Six Months Ended June 30,
	2012			2011			Variance			2012 (b)			2011			Variance
Operating revenues	$	(411	)	$	(245	)	$	(166	)	$	(780	)	$	(553	)	$	(227	)
Operating expenses
Purchased power and fuel		(414	)		(249	)		(165	)		(792	)		(555	)		(237	)
Operating and maintenance		(2	)		23			(25	)		206			20			186
Depreciation and amortization		13			5			8			22			11			11
Taxes other than income		6			4			2			9			9			—
Total operating expenses		(397	)		(217	)		(180	)		(555	)		(515	)		(40	)
Operating loss		(14	)		(28	)		14			(225	)		(38	)		(187	)
Other income and deductions
Interest expense		(32	)		(17	)		(15	)		(53	)		(32	)		(21	)
Other, net		20			18			2			29			28			1
Total other income and deductions		(12	)		1			(13	)		(24	)		(4	)		(20	)
Loss before income taxes		(26	)		(27	)		1			(249	)		(42	)		(207	)
Income taxes		(12	)		(8	)		(4	)		(150	)		(1	)		(149	)
Net loss	$	(14	)	$	(19	)	$	5		$	(99	)	$	(41	)	$	(58	)

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

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

5

EXELON CORPORATION

Consolidated Balance Sheets

(unaudited)

(in millions)

	June 30, 2012 (a)			December 31, 2011
ASSETS
Current assets
Cash and cash equivalents	$	1,349		$	1,016
Restricted cash and investments		83			40
Restricted cash and investments of variable interest entities		34			—
Accounts receivable, net
Customer		2,828			1,613
Other		1,252			1,000
Accounts receivable, net, variable interest entities		241			—
Mark-to-market derivative assets		1,170			432
Unamortized energy contracts assets		1,433			13
Inventories, net
Fossil fuel		227			208
Materials and supplies		772			656
Deferred income taxes		63			—
Regulatory assets		867			390
Other		1,435			345
Total current assets		11,754			5,713
Property, plant and equipment, net		42,613			32,570
Deferred debits and other assets
Regulatory assets		6,103			4,518
Nuclear decommissioning trust (NDT) funds		6,841			6,507
Investments		836			751
Investments in affiliates		420			15
Investment in CENG		1,878			—
Goodwill		2,626			2,625
Mark-to-market derivative assets		1,241			650
Unamortized energy contracts assets		1,317			388
Pledged assets for Zion Station decommissioning		650			734
Other		1,155			524
Total deferred debits and other assets		23,067			16,712
Total assets	$	77,434		$	54,995
Liabilities and shareholders’ equity
Current liabilities
Short-term borrowings	$	376		$	163
Short-term notes payable—accounts receivable agreement		225			225
Long-term debt due within one year		526			828
Long-term debt of variable interest entities due within one year		65			—
Accounts payable		2,183			1,444
Accounts payable of variable interest entities		119			—
Accrued expenses		1,441			1,255
Deferred income taxes		482			1
Regulatory liabilities		259			197
Dividends payable		4			349
Mark-to-market derivative liabilities		829			112
Unamortized energy contract liabilities		616			—
Other		958			560
Total current liabilities		8,083			5,134
Long-term debt		17,045			11,799
Long-term debt to financing trusts		649			390
Long-term debt of variable interest entity		479			—
Deferred credits and other liabilities
Deferred income taxes and unamortized investment tax credits		10,823			8,253
Asset retirement obligations		4,126			3,884
Pension obligations		2,610			2,194
Non-pension postretirement benefit obligations		2,703			2,263
Spent nuclear fuel obligation		1,019			1,019
Regulatory liabilities		3,963			3,627
Mark-to-market derivative liabilities		578			126
Unamortized energy contract liabilities		747			—
Payable for Zion Station decommissioning		464			563
Other		1,736			1,268
Total deferred credits and other liabilities		28,769			23,197
Total liabilities		55,025			40,520
Commitments and contingencies
Preferred securities of subsidiary		87			87
Shareholders’ equity
Common stock		16,559			9,107
Treasury stock, at cost		(2,327	)		(2,327	)
Retained earnings		10,114			10,055
Accumulated other comprehensive loss, net		(2,313	)		(2,450	)
Total shareholders’ equity		22,033			14,385
BGE preference stock not subject to mandatory redemption		193			—
Noncontrolling interest		96			3
Total equity		22,322			14,388
Total liabilities and shareholders’ equity	$	77,434		$	54,995

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

6

EXELON CORPORATION

Consolidated Statements of Cash Flows

(unaudited)

(in millions)

	Six Months Ended June 30,
	2012 (a)			2011
Cash flows from operating activities
Net income	$	490		$	1,290
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation, amortization, accretion and depletion including nuclear fuel and energy contract amortization		1,895			1,114
Deferred income taxes and amortization of investment tax credits		227			590
Net fair value changes related to derivatives		(323	)		264
Net realized and unrealized gains on NDT fund investments		(70	)		(51	)
Other non-cash operating activities		937			378
Changes in assets and liabilities:
Accounts receivable		414			—
Inventories		45			17
Accounts payable, accrued expenses and other current liabilities		(1,058	)		(486	)
Option premiums (paid) received, net		(109	)		38
Counterparty collateral received (posted), net		451			(494	)
Income taxes		259			691
Pension and non-pension postretirement benefit contributions		(90	)		(2,089	)
Other assets and liabilities		(339	)		(249	)
Net cash flows provided by operating activities		2,729			1,013
Cash flows from investing activities
Capital expenditures		(2,816	)		(1,985	)
Proceeds from nuclear decommissioning trust fund sales		5,371			1,657
Investment in nuclear decommissioning trust funds		(5,483	)		(1,772	)
Cash acquired from Constellation		964			—
Proceeds from sales of investments		12			—
Purchases of investments		(5	)		—
Change in restricted cash		(15	)		(2	)
Other investing activities		(12	)		28
Net cash flows used in investing activities		(1,984	)		(2,074	)
Cash flows from financing activities
Changes in short-term debt		179			140
Issuance of long-term debt		850			599
Retirement of long-term debt		(649	)		(2	)
Dividends paid on common stock		(773	)		(695	)
Dividends paid to former Constellation shareholders		(51	)		—
Proceeds from employee stock plans		42			15
Other financing activities		(10	)		(46	)
Net cash flows (used in) provided by financing activities		(412	)		11
Increase (decrease) in cash and cash equivalents		333			(1,050	)
Cash and cash equivalents at beginning of period		1,016			1,612
Cash and cash equivalents at end of period	$	1,349		$	562

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

7

EXELON CORPORATION

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

(unaudited)

(in millions, except per share data)

	Three Months Ended June 30, 2012 (a)									Three Months Ended June 30, 2011
	GAAP (b)			Adjustments			Adjusted Non-GAAP			GAAP (b)			Adjustments			Adjusted Non-GAAP
Operating revenues	$	5,954		$	412	(c),(d),(e)	$	6,366		$	4,496		$	(8	)(c)	$	4,488
Operating expenses
Purchased power and fuel		2,606			262	(c),(d),(e)		2,868			1,716			(124	)(d)		1,592
Operating and maintenance		1,871			(144	)(c),(f)		1,727			1,226			(15	)(c),(f),(j)		1,211
Depreciation, amortization, accretion and depletion		494			(14	)(c),(f)		480			329			(22	)(c)		307
Taxes other than income		254			(2	)(c)		252			191			—			191
Total operating expenses		5,225			102			5,327			3,462			(161	)		3,301
Equity in loss of unconsolidated affiliates		(57	)		52	(e),(f)		(5	)		—			—			—
Operating income		672			362			1,034			1,034			153			1,187
Other income and deductions
Interest expense		(256	)		(5	)(g)		(261	)		(182	)		—			(182	)
Other, net		(1	)		62	(c),(f),(h)		61			101			(25	)(h)		76
Total other income and deductions		(257	)		57			(200	)		(81	)		(25	)		(106	)
Income before income taxes		415			419			834			953			128			1,081
Income taxes		126			183	(c),(d),(e),  (f),(g),(h),(i)		309			332			51	(c),(d),(f),  (h),(j)		383
Net income		289			236			525			621			77			698
Net loss attributable to noncontrolling interests, preferred security dividends and preference stock dividends		3			—			3			1			—			1
Net income on common stock	$	286		$	236		$	522		$	620		$	77		$	697
Effective tax rate		30.4	%					37.1	%		34.8	%					35.4	%
Earnings per average common share
Basic	$	0.34		$	0.28		$	0.62		$	0.93		$	0.12		$	1.05
Diluted	$	0.33		$	0.28		$	0.61		$	0.93		$	0.12		$	1.05
Average common shares outstanding
Basic		853						853			663						663
Diluted		856						856			664						664
Effect of adjustments on earnings per average diluted common share recorded in accordance with GAAP:
Plant retirements and divestitures (c)				$	—								$	0.02
Mark-to-market impact of economic hedging activities (d)					(0.15	)								0.12
Amortization of commodity contract intangibles (e)					0.33									—
Constellation merger and integration costs (f)					0.08									0.02
Amortization of the fair value of certain debt (g)					—									—
Unrealized losses (gains) related to NDT fund investments (h)					0.02									(0.01	)
Reassessment of state deferred income taxes (i)					—									—
Recovery of costs pursuant to the 2011 distribution rate case order (j)					—									(0.03	)
Total adjustments				$	0.28								$	0.12

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

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

(c) Adjustment to exclude costs associated with the retirement of fossil generating units, the impacts of the Federal Energy Regulatory Commission (FERC) approved reliability-must-run rate schedule, and the revenues and operating expenses related to three generation facilities required to be sold within 180 days of the merger.

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

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

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

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

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

(i) Adjustment to exclude a one-time, non-cash benefit associated with a change in state deferred tax rates resulting from a reassessment of anticipated apportionment of Exelon’s deferred taxes as a result of the merger.

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

8

EXELON CORPORATION

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

(unaudited)

(in millions, except per share data)

	Six Months Ended June 30, 2012 (a)									Six Months Ended June 30, 2011
	GAAP (b)			Adjustments			Adjusted Non-GAAP			GAAP (b)			Adjustments			Adjusted Non-GAAP
Operating revenues	$	10,640		$	559	(c),(d),  (e),(f)	$	11,199		$	9,451		$	(8	)(c)	$	9,443
Operating expenses
Purchased power and fuel		4,371			262	(c),(d),  (e),(g)		4,633			3,716			(272	)(d)		3,444
Operating and maintenance		3,835			(716	)(c),(e),(f),  (g),(h),(i)		3,119			2,449			(17	)(c),(g),  (m)		2,432
Depreciation, amortization, accretion and depletion		876			(30	)(c),(g)		846			656			(46	)(c)		610
Taxes other than income		448			(1	)(c),(f)		447			394			—			394
Total operating expenses		9,530			(485	)		9,045			7,215			(335	)		6,880
Equity in earnings of unconsolidated affiliates		(79	)		60	(e),(g)		(19	)		—			—			—
Operating income		1,031			1,104			2,135			2,236			327			2,563
Other income and deductions
Interest expense		(451	)		(6	)(j)		(457	)		(363	)		—			(363	)
Other, net		194			(57	)(c),(g),(k)		137			196			(88	)(k)		108
Total other income and deductions		(257	)		(63	)		(320	)		(167	)		(88	)		(255	)
Income before income taxes		774			1,041			1,815			2,069			239			2,308
Income taxes		284			402	(c),(d),(e),  (f),(g),(h),(i),  (j),(k),(l)		686			779			51	(c),(d),(g),  (k),(m),(n)		830
Net income on common stock		490			639			1,129			1,290			188			1,478
Net loss attributable to noncontrolling interests, preferred security dividends and preference stock dividends		4			—			4			2			—			2
Net income	$	486		$	639		$	1,125		$	1,288		$	188		$	1,476
Effective tax rate		36.7	%					37.8	%		37.7	%					36.0	%
Earnings per average common share
Basic	$	0.62		$	0.82		$	1.44		$	1.94		$	0.28		$	2.22
Diluted	$	0.62		$	0.82		$	1.44		$	1.94		$	0.28		$	2.22
Average common shares outstanding
Basic		779						779			663						663
Diluted		781						781			664						664
Effect of adjustments on earnings per average diluted common share recorded in accordance with GAAP:
Plant retirements and divestitures (c)				$	0.01								$	0.04
Mark-to-market impact of economic hedging activities (d)					(0.21	)								0.25
Amortization of commodity contract intangibles (e)					0.46									—
Maryland commitments (f)					0.29									—
Constellation merger and integration costs (g)					0.23									0.02
FERC settlement (h)					0.22									—
Other acquisition costs (i)					—									—
Amortization of the fair value of certain debt (j)					—									—
Unrealized (gains) related to NDT fund investments (k)					(0.02	)								(0.04	)
Reassessment of state deferred income taxes (l)					(0.16	)								—
Recovery of costs pursuant to the 2011 distribution rate case order (m)					—									(0.03	)
Charge resulting from Illinois tax rate change legislation (n)					—									0.04
Total adjustments				$	0.82								$	0.28

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

(b) Results reported in accordance with GAAP.

(c) Adjustment to exclude costs associated with the retirement of fossil generating units, the impacts of the FERC approved reliability-must-run rate schedule, and the revenues and operating expenses related to three generation facilities required to be sold within 180 days of the merger.

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

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

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

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

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

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

(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.

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

(l) Adjustment to exclude a one-time, non-cash benefit associated with a change in state deferred tax rates resulting from a reassessment of anticipated apportionment of Exelon’s deferred taxes as a result of the merger.

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

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

9

EXELON CORPORATION (a)

Reconciliation of Adjusted (non-GAAP) Operating

Earnings to GAAP Earnings (in millions)

Three Months Ended June 30, 2012 and 2011

	Exelon Earnings per Diluted Share			Generation			ComEd			PECO			BGE			Other (b)			Exelon
2011 GAAP Earnings (Loss)	$	0.93		$	443		$	114		$	82		$	—		$	(19	)	$	620
2011 Adjusted (non-GAAP) Operating Earnings (Loss) Adjustments:
Mark-to-Market Impact of Economic Hedging Activities		0.12			75			—			—			—			—			75
Unrealized Gains Related to NDT Fund Investments (1)		(0.01	)		(6	)		—			—			—			—			(6	)
Plant Retirements and Divestitures (2)		0.02			10			—			—			—			—			10
Recovery of Costs Pursuant to the 2011 Distribution Rate Case Order (3)		(0.03	)		—			(17	)		—			—			—			(17	)
Constellation Merger and Integration Costs (4)		0.02			1			—			—			—			14			15
2011 Adjusted (non-GAAP) Operating Earnings (Loss)		1.05			523			97			82			—			(5	)		697
Year Over Year Effects on Earnings:
Generation Energy Margins, Excluding Mark-to-Market:
Nuclear Volume (5)		0.03			22			—			—			—			—			22
Nuclear Fuel Costs (6)		(0.01	)		(12	)		—			—			—			—			(12	)
Capacity Pricing		(0.03	)		(26	)		—			—			—			—			(26	)
Market and Portfolio Conditions (7)		0.25			212			—			—			—			—			212
Transmission Upgrades (8)		—			6			—			—			—			(6	)		—
ComEd, PECO and BGE Margins:
Weather		—			—			11			(8	)		—	(c)		—			3
Load		(0.01	)		—			(4	)		(3	)		—	(c)		—			(7	)
Discrete Impacts of the 2012 Distribution Formula Rate Order (9)		(0.07	)		—			(59	)		—			—			—			(59	)
Other Energy Delivery (10)		0.28			—			42			1			199			—			242
Discrete Impacts of the 2011 Distribution Rate Case Order (11)		(0.03	)		—			(22	)		—			—			—			(22	)
Operating and Maintenance Expense:
Labor, Contracting and Materials (12)		(0.24	)		(149	)		(10	)		9			(59	)		—			(209	)
Planned Nuclear Refueling Outages (13)		0.04			31			—			—			—			—			31
Pension and Non-Pension Postretirement Benefits (14)		(0.03	)		(9	)		(5	)		(2	)		(4	)		(3	)		(23	)
Other Operating and Maintenance		(0.12	)		(72	)		(3	)		(5	)		(32	)		11			(101	)
Depreciation and Amortization Expense (15)		(0.13	)		(45	)		(9	)		(2	)		(43	)		(5	)		(104	)
Nuclear Decommissioning Trust Fund Special Transfer Tax Deduction (16)		(0.07	)		(41	)		—			—			—			(2	)		(43	)
Equity in Losses of Unconsolidated Affiliates (17)		—			(3	)		—			—			—			—			(3	)
Income Taxes		—			(2	)		(3	)		2			1			(1	)		(3	)
Interest Expense, Net		(0.05	)		(26	)		7			2			(21	)		(2	)		(40	)
Other		(0.04	)		(10	)		—			5			(27	)		(1	)		(33	)
Share Differential (18)		(0.21	)		—			—			—			—			—			—
2012 Adjusted (non-GAAP) Operating Earnings (Loss)		0.61			399			42			81			14			(14	)		522
2012 Adjusted (non-GAAP) Operating Earnings (Loss) Adjustments:
Mark-to-Market Impact of Economic Hedging Activities		0.15			120			—			—			—			3			123
Unrealized Losses Related to NDT Fund Investments (1)		(0.02	)		(19	)		—			—			—			—			(19	)
Plant Retirements and Divestitures (2)		—			1			—			—			—			—			1
Constellation Merger and Integration Costs (4)		(0.08	)		(57	)		—			(2	)		(1	)		(7	)		(67	)
Amortization of Commodity Contract Intangibles (19)		(0.33	)		(281	)		—			—			—			—			(281	)
Amortization of the Fair Value of Certain Debt (20)		—			3			—			—			—			—			3
Reassessment of State Deferred Income Taxes (21)		—			—			—			—			—			4			4
2012 GAAP Earnings (Loss)	$	0.33		$	166		$	42		$	79		$	13		$	(14	)	$	286

(a) For the three months ended June 30, 2012, includes financial results for Constellation and BGE. Therefore, the results of operations from 2012 and 2011 are not comparable for Generation, BGE, Other and Exelon. The explanations below identify any 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 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, thereby recovering a specified dollar amount of distribution revenues per customer, by customer class, regardless of changes in consumption levels. Therefore, while these revenues are affected by customer growth, they will not be affected by actual weather or usage conditions.

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

(2) Primarily reflects incremental accelerated depreciation associated with the retirement of four fossil generating units and compensation for operating two of the units past their planned May 31, 2011 retirement date under a FERC-approved reliability-must-run rate schedule. For 2012, also reflects revenues and operating expenses related to three generation facilities required to be sold within 180 days of the merger.

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

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

(5) Primarily reflects the impact of decreased planned nuclear outage days in 2012, excluding Constellation Energy Nuclear Group, LLC (CENG).

(6) Primarily reflects the impact of higher nuclear fuel prices, excluding CENG.

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

(8) Reflects intercompany expense in 2011 at Generation for upgrades in transmission assets owned by ComEd, which are reflected as assets at Exelon Corporate.

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

(10) For ComEd, primarily reflects increased distribution revenue pursuant to the 2011 electric distribution rate case order and the 2012 performance based formula rate, and increased cost recovery for energy efficiency and demand response programs (completely offset in operating and maintenance expense).

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

(12) Primarily reflects the impacts of increased wages and other benefits and increased contracting expenses (exclusive of planned nuclear refueling outages and incremental storm costs). At ComEd, increased contracting expenses primarily resulted from new projects related to EIMA. At PECO, decreased contracting expenses primarily relates to a reduction in construction and maintenance projects in 2012.

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

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

(15) Includes increased depreciation expense across the operating companies due to ongoing capital expenditures.

(16) Reflects one-time interest and tax benefits in 2011 associated with a change in the timing of the deduction for the transfer of cash or investments from nonqualified nuclear decommissioning trust funds to qualified decommissioning trust funds pursuant to the Energy Policy Act of 2005 and related Treasury Regulations.

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

(18) 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.

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

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

(21) Reflects a change in state deferred tax rates resulting from a reassessment of anticipated apportionment of Exelon’s deferred taxes as a result of the merger.

10

EXELON CORPORATION (a)

Reconciliation of Adjusted (non-GAAP) Operating

Earnings to GAAP Earnings (in millions)

Six Months Ended June 30, 2012 and 2011

	Exelon Earnings per Diluted Share			Generation			ComEd			PECO			BGE			Other (b)			Exelon
2011 GAAP Earnings (Loss)	$	1.94		$	938		$	183		$	208		$	—		$	(41	)	$	1,288
2011 Adjusted (non-GAAP) Operating Earnings (Loss) Adjustments:
Mark-to-Market Impact of Economic Hedging Activities		0.25			164			—			—			—			—			164
Unrealized Gains Related to NDT Fund Investments (1)		(0.04	)		(30	)		—			—			—			—			(30	)
Plant Retirements and Divestitures (2)		0.04			27			—			—			—			—			27
Non-Cash Charge Resulting From Illinois Tax Rate Change Legislation (3)		0.04			21			4			—			—			4			29
Recovery of Costs Pursuant to the 2011 Distribution Rate Case Order (4)		(0.03	)		—			(17	)		—			—			—			(17	)
Constellation Merger and Integration Costs (5)		0.02			1			—			—			—			14			15
2011 Adjusted (non-GAAP) Operating Earnings (Loss)		2.22			1,121			170			208			—			(23	)		1,476
Year Over Year Effects on Earnings:
Generation Energy Margins, Excluding Mark-to-Market:
Nuclear Volume (6)		0.03			23			—			—			—			—			23
Nuclear Fuel Costs (7)		(0.04	)		(31	)		—			—			—			—			(31	)
Capacity Pricing		(0.13	)		(100	)		—			—			—			—			(100	)
Market and Portfolio Conditions (8)		0.26			202			—			—			—			—			202
Transmission Upgrades (9)		—			6			—			—			—			(6	)		—
ComEd, PECO and BGE Margins:
Weather		(0.05	)		—			1			(37	)		—	(c)		—			(36	)
Load		(0.02	)		—			(4	)		(8	)		—	(c)		—			(12	)
Discrete Impacts of the 2012 Distribution Formula Rate Order (10)		(0.07	)		—			(52	)		—			—			—			(52	)
Other Energy Delivery (11)		0.45			—			99			(2	)		257			—			354
Discrete Impacts of the 2011 Distribution Rate Case Order (12)		(0.03	)		—			(22	)		—			—			—			(22	)
Operating and Maintenance Expense:
Labor, Contracting and Materials (13)		(0.33	)		(176	)		(26	)		10			(70	)		—			(262	)
Planned Nuclear Refueling Outages (14)		0.03			22			—			—			—			—			22
Pension and Non-Pension Postretirement Benefits (15)		(0.05	)		(18	)		(10	)		(4	)		(5	)		(5	)		(42	)
Other Operating and Maintenance (16)		(0.16	)		(89	)		(12	)		2			(39	)		14			(124	)
Depreciation and Amortization Expense (17)		(0.18	)		(59	)		(18	)		(5	)		(54	)		(7	)		(143	)
Nuclear Decommissioning Trust Fund Special Transfer Tax Deduction (18)		(0.07	)		(41	)		—			—			—			(2	)		(43	)
Equity in Losses of Unconsolidated Affiliates (19)		(0.02	)		(12	)		—			—			—			—			(12	)
Income Taxes (20)		(0.03	)		(16	)		(7	)		(6	)		3			9			(17	)
Interest Expense, Net		(0.07	)		(32	)		9			4			(25	)		(7	)		(51	)
Other (21)		(0.01	)		8			2			20			(35	)		—			(5	)
Share Differential (22)		(0.29	)		—			—			—			—			—			—
2012 Adjusted (non-GAAP) Operating Earnings (Loss)		1.44			808			130			182			32			(27	)		1,125
2012 Adjusted (non-GAAP) Operating Earnings (Loss) Adjustments:
Mark-to-Market Impact of Economic Hedging Activities		0.21			157			—			—			—			10			167
Unrealized Gains Related to NDT Fund Investments (1)		0.02			17			—			—			—			—			17
Plant Retirements and Divestitures (2)		(0.01	)		(7	)		—			—			—			—			(7	)
Constellation Merger and Integration Costs (5)		(0.23	)		(102	)		(1	)		(7	)		(2	)		(68	)		(180	)
Maryland Commitments (23)		(0.29	)		(22	)		—			—			(83	)		(122	)		(227	)
Amortization of Commodity Contract Intangibles (24)		(0.46	)		(358	)		—			—			—			—			(358	)
FERC Settlement (25)		(0.22	)		(172	)		—			—			—			—			(172	)
Reassessment of State Deferred Income Taxes (26)		0.16			13			—			—			—			108			121
Amortization of the Fair Value of Certain Debt (27)		—			3			—			—			—			—			3
Other Acquisition Costs		—			(3	)		—			—			—			—			(3	)
2012 GAAP Earnings (Loss)	$	0.62		$	334		$	129		$	175		$	(53	)	$	(99	)	$	486

(a) For the six months ended June 30, 2012, includes financial results for Constellation and BGE beginning on March 12, 2012, the date the merger was completed. Therefore, the results of operations from 2012 and 2011 are not comparable for Generation, BGE, Other and Exelon. The explanations below identify any 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 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, thereby recovering a specified dollar amount of distribution revenues per customer, by customer class, regardless of changes in consumption levels. Therefore, while these revenues are affected by customer growth, they will not be affected by actual weather or usage conditions.

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

(2) Primarily reflects incremental accelerated depreciation associated with the retirement of four fossil generating units and compensation for operating two of the units past their planned May 31, 2011 retirement date under a FERC-approved reliability-must-run rate schedule. For 2012, also reflects revenues and operating expenses related to three generation facilities required to be sold within 180 days of the merger.

(3) Reflects the impact of a one-time, non-cash charge to remeasure deferred taxes at higher corporate tax rates pursuant to the Illinois tax rate change legislation.

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

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

(6) Primarily reflects the impact of decreased planned nuclear outage days in 2012, excluding CENG.

(7) Primarily reflects the impact of higher nuclear fuel prices, excluding CENG.

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

(9) Reflects intercompany expense in 2011 at Generation for upgrades in transmission assets owned by ComEd, which are reflected as assets at Exelon Corporate.

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

(11) For ComEd, primarily reflects increased distribution revenue pursuant to the 2011 electric distribution rate case order and the 2012 performance based formula rate, and increased cost recovery for energy efficiency and demand response programs (completely offset in operating and maintenance expense), partially offset by updates to the 2011 performance based formula rate.

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

(13) Primarily reflects the impacts of increased wages and other benefits and increased contracting expenses (exclusive of planned nuclear refueling outages and incremental storm costs). At ComEd, increased contracting expenses primarily resulted from new projects related to EIMA. At PECO, decreased contracting expenses primarily relates to a reduction in construction and maintenance projects in 2012.

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

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

(16) Primarily reflects increased costs at ComEd associated with energy efficiency and demand response programs (completely offset by increased other energy delivery revenues at ComEd), partially offset by decreased storm costs in the ComEd and PECO service territory.

(17) Includes increased depreciation expense across the operating companies due to ongoing capital expenditures.

(18) Reflects one-time interest and tax benefits in 2011 associated with a change in the timing of the deduction for the transfer of cash or investments from nonqualified nuclear decommissioning trust funds to qualified decommissioning trust funds pursuant to the Energy Policy Act of 2005 and related Treasury Regulations.

(19) Primarily reflects the non-cash amortization of the basis difference recorded at fair value at the merger date and equity in losses in CENG.

(20) Primarily reflects a reduction in Generation’s manufacturing deduction benefits.

(21) For Generation, primarily reflects realized NDT fund gains related to changes to the investment strategy and favorable market conditions in 2012. For PECO, primarily reflects decreased gross receipts tax (completely offset by decreased PECO margins) and the impact of a 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) Reflects costs incurred as part of the Maryland order approving the merger transaction.

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

(25) 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.

(26) Reflects a change in state deferred tax rates resulting from a reassessment of anticipated apportionment of Exelon’s deferred taxes as a result of the merger.

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

11

EXELON CORPORATION

Reconciliation of Adjusted (non-GAAP) Operating Earnings to

GAAP Consolidated Statements of Operations

(unaudited)

(in millions)

	Generation
	Three Months Ended June 30, 2012									Three Months Ended June 30, 2011
	GAAP (b)			Adjustments			Adjusted Non - GAAP			GAAP (b)			Adjustments			Adjusted Non - GAAP
Operating revenues	$	3,753		$	417	(c),(d),(e)	$	4,170		$	2,455		$	(8	)(c)	$	2,447
Operating expenses
Purchased power and fuel		1,852			262	(c),(d),(e)		2,114			841			(124	)(d)		717
Operating and maintenance		1,209			(126	)(c),(f)		1,083			763			(4	)(c),(f)		759
Depreciation, amortization, accretion and depletion		204			(14	)(c),(f)		190			138			(22	)(c)		116
Taxes other than income		90			(2	)(c)		88			66			—			66
Total operating expenses		3,355			120			3,475			1,808			(150	)		1,658
Equity in loss of unconsolidated affiliates		(57	)		52	(e),(f)		(5	)		—			—			—
Operating income		341			349			690			647			142			789
Other income and deductions
Interest expense		(85	)		(5	)(g)		(90	)		(45	)		—			(45	)
Other, net		(33	)		62	(c),(f),(h)		29			76			(25	)(h)		51
Total other income and deductions		(118	)		57			(61	)		31			(25	)		6
Income before income taxes		223			406			629			678			117			795
Income taxes		58			173	(c),(d),(e),  (f),(g),(h)		231			235			37	(c),(d),  (f),(h)		272
Net income		165			233			398			443			80			523
Net loss attributable to noncontrolling interests		(1	)		—			(1	)		—			—			—
Net income on common stock	$	166		$	233		$	399		$	443		$	80		$	523
	Six Months Ended June 30, 2012 (a)									Six Months Ended June 30, 2011
	GAAP (b)			Adjustments			Adjusted Non - GAAP			GAAP (b)			Adjustments			Adjusted Non - GAAP
Operating revenues	$	6,492		$	462	(c),(d),(e)	$	6,954		$	5,098		$	(8	)(c)	$	5,090
Operating expenses
Purchased power and fuel		2,896			262	(c),(d),(e),(f)		3,158			1,724			(272	)(d)		1,452
Operating and maintenance		2,382			(447	)(c),(e),(f),  (i),(j),(k)		1,935			1,517			(6	)(c),(f)		1,511
Depreciation, amortization, accretion and depletion		357			(30	)(c),(f)		327			277			(46	)(c)		231
Taxes other than income		164			(3	)(c)		161			132			—			132
Total operating expenses		5,799			(218	)		5,581			3,650			(324	)		3,326
Equity in earnings of unconsolidated affiliates		(79	)		60	(e),(f)		(19	)		—			—			—
Operating income		614			740			1,354			1,448			316			1,764
Other income and deductions
Interest expense		(138	)		(6	)(g)		(144	)		(91	)		—			(91	)
Other, net		145			(57	)(c),(f),(h)		88			152			(88	)(h)		64
Total other income and deductions		7			(63	)		(56	)		61			(88	)		(27	)
Income before income taxes		621			677			1,298			1,509			228			1,737
Income taxes		289			203	(c),(d),(e),  (f),(g),(h),  (i),(j),(k),(l)		492			571			45	(c),(d),(f),  (h),(m)		616
Net income		332			474			806			938			183			1,121
Net income attributable to noncontrolling interests		(2	)		—			(2	)		—			—			—
Net income on common stock	$	334		$	474		$	808		$	938		$	183		$	1,121

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

(b) Results reported in accordance with GAAP.

(c) Adjustment to exclude costs associated with the retirement of fossil generating units, the impacts of the FERC approved reliability-must-run rate schedule, and the revenues and operating expenses related to three generation facilities required to be sold within 180 days of the merger.

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

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

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

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

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

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

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

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

(l) Adjustment to exclude a one-time, non-cash benefit associated with a change in state deferred tax rates resulting from a reassessment of anticipated apportionment of Exelon’s deferred taxes as a result of the merger.

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

12

EXELON CORPORATION

Reconciliation of Adjusted (non-GAAP) Operating Earnings to

GAAP Consolidated Statements of Operations

(unaudited)

(in millions)

	ComEd
	Three Months Ended June 30, 2012									Three Months Ended June 30, 2011
	GAAP (a)			Adjustments			Adjusted Non- GAAP			GAAP (a)			Adjustments			Adjusted Non- GAAP
Operating revenues	$	1,281		$	—		$	1,281		$	1,444		$	—		$	1,444
Operating expenses
Purchased power		587			—			587			716			—			716
Operating and maintenance		331			—			331			268			13	(b)		281
Depreciation and amortization		152			—			152			136			—			136
Taxes other than income		69			—			69			70			—			70
Total operating expenses		1,139			—			1,139			1,190			13			1,203
Operating income		142			—			142			254			(13	)		241
Other income and deductions
Interest expense		(74	)		—			(74	)		(86	)		—			(86	)
Other, net		3			—			3			4			—			4
Total other income and deductions		(71	)		—			(71	)		(82	)		—			(82	)
Income before income taxes		71			—			71			172			(13	)		159
Income taxes		29			—			29			58			4	(b)		62
Net income	$	42		$	—		$	42		$	114		$	(17	)	$	97
	Six Months Ended June 30, 2012									Six Months Ended June 30, 2011
	GAAP (a)			Adjustments			Adjusted Non- GAAP			GAAP (a)			Adjustments			Adjusted Non- GAAP
Operating revenues	$	2,670		$	—		$	2,670		$	2,910		$	—		$	2,910
Operating expenses
Purchased power		1,208			—			1,208			1,505			—			1,505
Operating and maintenance		650			(2	)(c)		648			534			13	(b)		547
Depreciation and amortization		300			—			300			270			—			270
Taxes other than income		144			—			144			147			—			147
Total operating expenses		2,302			(2	)		2,300			2,456			13			2,469
Operating income		368			2			370			454			(13	)		441
Other income and deductions
Interest expense		(156	)		—			(156	)		(172	)		—			(172	)
Other, net		7			—			7			8			—			8
Total other income and deductions		(149	)		—			(149	)		(164	)		—			(164	)
Income before income taxes		219			2			221			290			(13	)		277
Income taxes		90			1	(c)		91			107			—	(b),(d)		107
Net income	$	129		$	1		$	130		$	183		$	(13	)	$	170

(a) Results reported in accordance with GAAP.

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

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

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

13

EXELON CORPORATION

Reconciliation of Adjusted (non-GAAP) Operating Earnings to

GAAP Consolidated Statements of Operations

(unaudited)

(in millions)

	PECO
	Three Months Ended June 30, 2012									Three Months Ended June 30, 2011
	GAAP (a)			Adjustments			Adjusted Non- GAAP			GAAP (a)			Adjustments		Adjusted Non- GAAP
Operating revenues	$	715		$	—		$	715		$	842		$	—	$	842
Operating expenses
Purchased power and fuel		296			—			296			408			—		408
Operating and maintenance		172			(4	)(b)		168			172			—		172
Depreciation and amortization		54			—			54			50			—		50
Taxes other than income		42			—			42			51			—		51
Total operating expenses		564			(4	)		560			681			—		681
Operating income		151			4			155			161			—		161
Other income and deductions
Interest expense		(31	)		—			(31	)		(34	)		—		(34	)
Other, net		2			—			2			3			—		3
Total other income and deductions		(29	)		—			(29	)		(31	)		—		(31	)
Income before income taxes		122			4			126			130			—		130
Income taxes		42			2	(b)		44			47			—		47
Net income		80			2			82			83			—		83
Preferred security dividends		1			—			1			1			—		1
Net income on common stock	$	79		$	2		$	81		$	82		$	—	$	82
	Six Months Ended June 30, 2012									Six Months Ended June 30, 2011
	GAAP (a)			Adjustments			Adjusted Non- GAAP			GAAP (a)			Adjustments		Adjusted Non- GAAP
Operating revenues	$	1,590		$	—		$	1,590		$	1,996		$	—	$	1,996
Operating expenses
Purchased power and fuel		707			—			707			1,042			—		1,042
Operating and maintenance		375			(10	)(b)		365			378			—		378
Depreciation and amortization		107			—			107			98			—		98
Taxes other than income		74			—			74			106			—		106
Total operating expenses		1,263			(10	)		1,253			1,624			—		1,624
Operating income		327			10			337			372			—		372
Other income and deductions
Interest expense		(62	)		—			(62	)		(68	)		—		(68	)
Other, net		5			—			5			8			—		8
Total other income and deductions		(57	)		—			(57	)		(60	)		—		(60	)
Income before income taxes		270			10			280			312			—		312
Income taxes		93			3	(b)		96			102			—		102
Net income		177			7			184			210			—		210
Preferred security dividends		2			—			2			2			—		2
Net income on common stock	$	175		$	7		$	182		$	208		$	—	$	208

(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, relocation and retention bonuses) and integration initiatives.

14

EXELON CORPORATION

Reconciliation of Adjusted (non-GAAP) Operating Earnings to

GAAP Consolidated Statements of Operations

(unaudited)

(in millions)

	BGE
	Three Months Ended June 30, 2011
	GAAP (a)			Adjustments			Adjusted Non- GAAP
Operating revenues	$	616		$	—		$	616
Operating expenses
Purchased power and fuel		285			—			285
Operating and maintenance		161			(3	)(b)		158
Depreciation and amortization		71			—			71
Taxes other than income		47			—			47
Total operating expenses		564			(3	)		561
Operating income (loss)		52			3			55
Other income and deductions
Interest expense		(34	)		—			(34	)
Other, net		7			—			7
Total other income and deductions		(27	)		—			(27	)
Income (loss) before income taxes		25			3			28
Income taxes		9			2	(b)		11
Net income (loss)		16			1			17
Preference stock dividends		3			—			3
Net income (loss) on common stock	$	13		$	1		$	14
	March 12, 2012 through June 30, 2012
	GAAP (a)			Adjustments			Adjusted Non- GAAP
Operating revenues	$	668		$	113	(c)	$	781
Operating expenses
Purchased power and fuel		352			—			352
Operating and maintenance		222			(32	)(b),(c)		190
Depreciation and amortization		90			—			90
Taxes other than income		57			2	(c)		59
Total operating expenses		721			(30	)		691
Operating income (loss)		(53	)		143			90
Other income and deductions
Interest expense		(42	)		—			(42	)
Other, net		8			—			8
Total other income and deductions		(34	)		—			(34	)
Income (loss) before income taxes		(87	)		143			56
Income taxes		(38	)		58	(b),(c)		20
Net income (loss)		(49	)		85			36
Preference stock dividends		4			—			4
Net income (loss) on common stock	$	(53	)	$	85		$	32

(a) Results reported in accordance with GAAP.

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

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

15

EXELON CORPORATION

Reconciliation of Adjusted (non-GAAP) Operating Earnings to

GAAP Consolidated Statements of Operations

(unaudited)

(in millions)

	Other (a)
	Three Months Ended June 30, 2012 (b)									Three Months Ended June 30, 2011
	GAAP (c)			Adjustments			Adjusted Non- GAAP			GAAP (c)			Adjustments			Adjusted Non- GAAP
Operating revenues	$	(411	)	$	(5	)(d)	$	(416	)	$	(245	)	$	—		$	(245	)
Operating expenses
Purchased power and fuel		(414	)		—			(414	)		(249	)		—			(249	)
Operating and maintenance		(2	)		(11	)(e)		(13	)		23			(24	)(e)		(1	)
Depreciation and amortization		13			—			13			5			—			5
Taxes other than income		6			—			6			4			—			4
Total operating expenses		(397	)		(11	)		(408	)		(217	)		(24	)		(241	)
Operating loss		(14	)		6			(8	)		(28	)		24			(4	)
Other income and deductions
Interest expense		(32	)		—			(32	)		(17	)		—			(17	)
Other, net		20			—			20			18			—			18
Total other income and deductions		(12	)		—			(12	)		1			—			1
Loss before income taxes		(26	)		6			(20	)		(27	)		24			(3	)
Income taxes		(12	)		6	(d),(e),(f)		(6	)		(8	)		10	(e)		2
Net loss	$	(14	)	$	—		$	(14	)	$	(19	)	$	14		$	(5	)
	Six Months Ended June 30, 2012 (b)									Six Months Ended June 30, 2011
	GAAP (c)			Adjustments			Adjusted Non- GAAP			GAAP (c)			Adjustments			Adjusted Non- GAAP
Operating revenues	$	(780	)	$	(16	)(d)	$	(796	)	$	(553	)	$	—		$	(553	)
Operating expenses
Purchased power and fuel		(792	)		—			(792	)		(555	)		—			(555	)
Operating and maintenance		206			(225	)(e),(g)		(19	)		20			(24	)(e)		(4	)
Depreciation and amortization		22			—			22			11			—			11
Taxes other than income		9			—			9			9			—			9
Total operating expenses		(555	)		(225	)		(780	)		(515	)		(24	)		(539	)
Operating loss		(225	)		209			(16	)		(38	)		24			(14	)
Other income and deductions
Interest expense		(53	)		—			(53	)		(32	)		—			(32	)
Other, net		29			—			29			28			—			28
Total other income and deductions		(24	)		—			(24	)		(4	)		—			(4	)
Loss before income taxes		(249	)		209			(40	)		(42	)		24			(18	)
Income taxes		(150	)		137	(d),(e),  (f),(g)		(13	)		(1	)		6	(e),(h)		5
Net loss	$	(99	)	$	72		$	(27	)	$	(41	)	$	18		$	(23	)

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

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

(c) Results reported in accordance with GAAP.

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

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

(f) Adjustment to exclude a one-time, non-cash benefit associated with a change in state deferred tax rates resulting from a reassessment of anticipated apportionment of Exelon’s deferred taxes as a result of the merger.

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

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

16

EXELON CORPORATION

Exelon Generation Statistics

	Three Months Ended
	Jun. 30, 2012 (a)		Mar. 31, 2012 (a)		Dec. 31, 2011			Sept. 30, 2011			Jun. 30, 2011
Supply (in GWhs)
Nuclear Generation (b)
Mid-Atlantic		12,277		12,064		11,587			12,158			11,172
Midwest		22,860		23,198		23,306			23,887			21,995
Total Nuclear Generation		35,137		35,262		34,893			36,045			33,167
Fossil and Renewables (b)
Mid-Atlantic (b)(d)		2,316		1,791		1,637			1,722			2,052
Midwest		228		272		188			88			163
New England		2,755		889		—			2			2
New York		—		—		—			—			—
ERCOT (e)		2,177		840		457			1,214			207
Other (f)		1,923		819		394			249			431
Total Fossil and Renewables		9,399		4,611		2,676			3,275			2,855
Purchased Power
Mid-Atlantic (c)		7,111		2,577		739			702			707
Midwest		1,558		2,552		1,143			1,756			1,659
New England		3,905		1,100		—			—			—
New York (c)		2,818		935		—			—			—
ERCOT (e)		6,686		2,832		1,150			2,928			1,834
Other (f)		6,012		1,769		482			887			577
Total Purchased Power		28,090		11,765		3,514			6,273			4,777
Total Supply/Sales by Region (h)
Mid-Atlantic (g)		21,704		16,432		13,963			14,582			13,931
Midwest (g)		24,646		26,022		24,637			25,731			23,817
New England		6,660		1,989		—			2			2
New York		2,818		935		—			—			—
ERCOT		8,863		3,672		1,607			4,142			2,041
Other (f)		7,935		2,588		876			1,136			1,008
Total Supply/Sales by Region		72,626		51,638		41,083			45,593			40,799
	Three Months Ended
	Jun. 30, 2012 (a)		Mar. 31, 2012 (a)		Dec. 31, 2011			Sept. 30, 2011			Jun. 30, 2011
Average Margin ($/MWh) (i) (j)
Mid-Atlantic (k)	$	40.68	$	46.86	$	56.08		$	57.19		$	58.79
Midwest (k)		31.00		31.40		34.18			33.15			37.28
New England		9.01		19.61		n.m.			n.m.			n.m.
New York		13.84		8.56		n.m.			n.m.			n.m.
ERCOT		13.43		9.26		(6.02	)		24.46			(6.52	)
Other (f)		4.28		5.41		(4.13	)		(4.86	)		3.08
Average Margin—Overall Portfolio	$	26.15	$	32.57	$	39.31		$	39.19		$	41.59
Around-the-clock Market Prices ($/MWh) (l)
PJM West Hub	$	30.40	$	31.10	$	35.07		$	46.17		$	47.27
NiHub		26.02		27.13		25.97			37.30			34.94
New England Mass Hub ATC Spark Spread		7.77		0.80		6.70			13.30			7.43
NYPP Zone A		27.87		27.18		32.03			40.89			37.03
ERCOT North Spark Spread		6.01		3.46		1.11			36.70			6.73

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

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

(c) Purchased power includes physical volumes of 3,225 GWhs and 319 GWhs in the Mid-Atlantic and 2,817 GWhs and 722 GWhs in New York as a result of the PPA with CENG for the three months ended 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 planned for divestiture as a result of the Exelon and Constellation merger.

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

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

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

(h) Total sales do not include physical proprietary trading volumes of 4,248 GWhs, 1,888 GWhs, 1,235 GWhs, 1,679 GWhs and 1,496 GWhs for the three months ended June 30, 2012, March 31, 2012, December 31, 2011, September 30, 2011 and June 30, 2011, respectively.

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

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

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

(l) Represents the average for the quarter.

17

EXELON CORPORATION

Exelon Generation Statistics

Six Months Ended June 30, 2012 and 2011

	June 30, 2012 (a)		June 30, 2011
Supply (in GWhs)
Nuclear Generation (b)
Mid-Atlantic		24,341		23,543
Midwest		46,058		44,816
Total Nuclear Generation		70,399		68,359
Fossil and Renewables (b)
Mid-Atlantic (b)(d)		4,107		4,214
Midwest		500		320
New England		3,644		6
ERCOT (e)		3,017		358
Other (f)		2,742		789
Total Fossil and Renewables		14,010		5,687
Purchased Power
Mid-Atlantic (c)		9,688		1,457
Midwest		4,110		3,071
New England		5,005		—
New York (c)		3,753		—
ERCOT (e)		9,518		3,459
Other (f)		7,781		1,134
Total Purchased Power		39,855		9,121
Total Supply/Sales by Region (h)
Mid-Atlantic(g)		38,136		29,214
Midwest (g)		50,668		48,207
New England		8,649		6
New York		3,753		—
ERCOT		12,535		3,817
Other (f)		10,523		1,923
Total Supply/Sales by Region		124,264		83,167
	June 30, 2012 (a)		June 30, 2011
Average Margin ($/MWh) (i) (j)
Mid-Atlantic (k)	$	43.35	$	59.29
Midwest (k)		31.20		38.40
New England		11.45		n.m.
New York		12.52		n.m.
ERCOT		12.21		(2.10	)
Other (f)		4.56		(2.60	)
Average Margin—Overall Portfolio	$	28.82	$	42.97
Around-the-clock Market Prices ($/MWh) (l)
PJM West Hub	$	30.75	$	46.55
NiHub		26.57		34.52
NEPOOL Mass Hub		6.17		7.46
NYPP Zone A		29.55		37.51
ERCOT North Spark Spread		4.78		3.34

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

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

(c) Purchased power includes physical volumes of 3,554 GWhs in the Mid-Atlantic and 3,539 GWhs in New York as a result of the PPA with CENG for the six months ended June 30, 2012.

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

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

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

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

(h) Total sales do not include physical proprietary trading volumes of 6,077 GWhs and 2,829 GWhs for the six months ended June 30, 2012 and 2011, respectively.

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

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

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

(l) Represents the average for the quarter.

18

EXELON CORPORATION

ComEd Statistics

	Three Months Ended June 30, 2012 and 2011
	Electric Deliveries (in GWhs)										Revenue (in millions)
	2012		2011		% Change			Weather- Normal %  Change			2012		2011		% Change
Retail Deliveries and Sales (a)
Residential		6,674		6,277		6.3	%		(2.7	)%	$	720	$	800		(10.0	)%
Small Commercial & Industrial		7,888		7,763		1.6	%		(1.8	)%		306		386		(20.7	)%
Large Commercial & Industrial		6,839		6,698		2.1	%		0.4	%		94		95		(1.1	)%
Public Authorities & Electric Railroads		293		286		2.4	%		2.4	%		9		12		(25.0	)%
Total Retail		21,694		21,024		3.2	%		(1.3	)%		1,129		1,293		(12.7	)%
Other Revenue (b)												152		151		0.7	%
Total Electric Revenue											$	1,281	$	1,444		(11.3	)%
Purchased Power											$	587	$	716		(18.0	)%

							% Change
Heating and Cooling Degree-Days	2012		2011		Normal		From 2011			From Normal
Heating Degree-Days		544		823		765		(33.9	)%		(28.9	)%
Cooling Degree-Days		423		237		218		78.5	%		94.0	%

	Six Months Ended June 30, 2012 and 2011
	Electric Deliveries (in GWhs)										Revenue (in millions)
	2012		2011		% Change			Weather- Normal %  Change			2012		2011		% Change
Retail Deliveries and Sales (a)
Residential		13,080		13,231		(1.1	)%		(1.6	)%	$	1,496	$	1,634		(8.4	)%
Small Commercial & Industrial		15,804		15,837		(0.2	)%		(0.3	)%		654		767		(14.7	)%
Large Commercial & Industrial		13,542		13,517		0.2	%		0.6	%		194		186		4.3	%
Public Authorities & Electric Railroads		617		616		0.2	%		3.3	%		21		26		(19.2	)%
Total Retail		43,043		43,201		(0.4	)%		(0.4	)%		2,365		2,613		(9.5	)%
Other Revenue (b)												305		297		2.7	%
Total Electric Revenue											$	2,670	$	2,910		(8.2	)%
Purchased Power											$	1,208	$	1,505		(19.7	)%

							% Change
Heating and Cooling Degree-Days	2012		2011		Normal		From 2011			From Normal
Heating Degree-Days		2,928		4,155		3,929		(29.5	)%		(25.5	)%
Cooling Degree-Days		462		237		218		94.9	%		111.9	%

Number of Electric Customers	2012		2011
Residential		3,456,312		3,447,194
Small Commercial & Industrial		365,474		364,902
Large Commercial & Industrial		1,990		2,007
Public Authorities & Electric Railroads		4,793		4,914
Total		3,828,569		3,819,017

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

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

19

EXELON CORPORATION

PECO Statistics

	Three Months Ended June 30, 2012 and 2011
	Electric and Gas Deliveries										Revenue (in millions)
	2012		2011		% Change			Weather- Normal %  Change			2012		2011		% Change
Electric (in GWhs)
Retail Deliveries and Sales (a)
Residential		2,929		3,075		(4.7	)%		(0.7	)%	$	393	$	451		(12.9	)%
Small Commercial & Industrial		1,959		2,026		(3.3	)%		(1.9	)%		119		165		(27.9	)%
Large Commercial & Industrial		3,743		3,954		(5.3	)%		(4.9	)%		58		67		(13.4	)%
Public Authorities & Electric Railroads		237		229		3.5	%		3.5	%		8		9		(11.1	)%
Total Retail		8,868		9,284		(4.5	)%		(2.7	)%		578		692		(16.5	)%
Other Revenue (b)												57		61		(6.6	)%
Total Electric Revenue												635		753		(15.7	)%
Gas (in mmcfs)
Retail Deliveries and Sales
Retail Sales (c)		6,228		6,561		(5.1	)%		(1.1	)%		73		82		(11.0	)%
Transportation and Other		5,835		6,278		(7.1	)%		(6.7	)%		7		7		0.0	%
Total Gas		12,063		12,839		(6.0	)%		(3.7	)%		80		89		(10.1	)%
Total Electric and Gas Revenues											$	715	$	842		(15.1	)%
Purchased Power and Fuel											$	296	$	408		(27.5	)%

							% Change
Heating and Cooling Degree-Days	2012		2011		Normal		From 2011			From Normal
Heating Degree-Days		337		331		463		1.8	%		(27.2	)%
Cooling Degree-Days		430		494		348		(13.0	)%		23.6	%

	Six Months Ended June 30, 2012 and 2011
	Electric and Gas Deliveries										Revenue (in millions)
	2012		2011		% Change			Weather- Normal %  Change			2012		2011		% Change
Electric (in GWhs)
Retail Deliveries and Sales (a)
Residential		6,095		6,665		(8.6	)%		(1.7	)%	$	800	$	944		(15.3	)%
Small Commercial & Industrial		3,910		4,165		(6.1	)%		(3.5	)%		237		334		(29.0	)%
Large Commercial & Industrial		7,380		7,642		(3.4	)%		(3.4	)%		111		175		(36.6	)%
Public Authorities & Electric Railroads		474		471		0.6	%		0.6	%		16		20		(20.0	)%
Total Retail		17,859		18,943		(5.7	)%		(2.7	)%		1,164		1,473		(21.0	)%
Other Revenue (b)												114		126		(9.5	)%
Total Electric Revenue												1,278		1,599		(20.1	)%
Gas (in mmcfs)
Retail Deliveries and Sales
Retail Sales (c)		28,655		35,295		(18.8	)%		0.8	%		295		378		(22.0	)%
Transportation and Other		13,601		15,238		(10.7	)%		(9.4	)%		17		19		(10.5	)%
Total Gas		42,256		50,533		(16.4	)%		(2.2	)%		312		397		(21.4	)%
Total Electric and Gas Revenues											$	1,590	$	1,996		(20.3	)%
Purchased Power and Fuel											$	707	$	1,042		(32.1	)%

							% Change
Heating and Cooling Degree-Days	2012		2011		Normal		From 2011			From Normal
Heating Degree-Days		2,251		2,837		2,939		(20.7	)%		(23.4	)%
Cooling Degree-Days		434		494		348		(12.1	)%		24.7	%

Number of Electric Customers	2012		2011		Number of Gas Customers	2012		2011
Residential		1,417,346		1,412,692	Residential		452,478		449,066
Small Commercial & Industrial		148,837		148,116	Commercial & Industrial		41,383		40,956
Large Commercial & Industrial		3,107		3,127	Total Retail		493,861		490,022
Public Authorities & Electric Railroads		9,680		9,661	Transportation		888		864
Total		1,578,970		1,573,596	Total		494,749		490,886

(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.

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EXELON CORPORATION

BGE Statistics

Three Months Ended June 30, 2012
	Electric and Gas Deliveries		Revenue (in millions)
Electric (in GWhs)
Retail Deliveries and Sales (a)
Residential		2,663	$	295
Small Commercial & Industrial		4,035		149
Large Commercial & Industrial		637		10
Public Authorities & Electric Railroads		48		7
Total Retail		7,383		461
Other Revenues (b)				57
Total Electric Revenue				518
Gas (in mmcfs)
Retail Deliveries and Sales (c)
Retail Sales		15,535		84
Transportation and Other (d)		4,854		14
Total Gas		20,389		98
Total Electric and Gas Revenues			$	616
Purchased Power			$	246
Fuel				38
Total Purchased Power and Fuel			$	284

Heating and Cooling Degree-Days	2012
Heating Degree-Days		402
Cooling Degree-Days		289

March 12, 2012 through June 30, 2012
	Electric and Gas Deliveries		Revenue (in millions)
Electric (in GWhs)
Retail Deliveries and Sales (a)
Residential		3,278	$	282
Small Commercial & Industrial		4,178		161
Large Commercial & Industrial		1,480		31
Public Authorities & Electric Railroads		73		10
Total Retail		9,009		484
Other Revenues (b)				74
Total Electric Revenue				558
Gas (in mmcfs)
Retail Deliveries and Sales (c)
Retail Sales		20,402		90
Transportation and Other (d)		6,764		20
Total Gas		27,166		110
Total Electric and Gas Revenues			$	668
Purchased Power			$	299
Fuel				53
Total Purchased Power and Fuel			$	352

Heating and Cooling Degree-Days	2012
Heating Degree-Days		2,119
Cooling Degree-Days		289

As of June 30, 2012
Number of Electric Customers	2012		Number of Gas Customers	2012
Residential		1,115,107	Residential		610,073
Small Commercial & Industrial		119,338	Commercial & Industrial		44,011
Large Commercial & Industrial		5,432	Total Retail		654,084
Public Authorities & Electric Railroads		296	Transportation		—
Total		1,240,173	Total		654,084

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

(b) Other revenues 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 4,854 mmcfs ($12M) for the three months ended June 30, 2012 and off-system revenue of 6,764 mmcfs ($17M) from March 12, 2012 through June 30, 2012.

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