EXELON GENERATION CO LLC - FORM 8-K - EX-99.1 - PRESS RELEASE AND EARNINGS RELEASE ATTACHMENTS

Attached files

file	filename
8-K - FORM 8-K - EXELON GENERATION CO LLC	d342969d8k.htm

Exhibit 99.1

LOGO

News Release


Contact:	JaCee Burnes Investor Relations 312-394-2948	FOR IMMEDIATE RELEASE

	Judy Rader Corporate Communications 312-394-7417

Exelon Announces First Quarter 2012 Results

CHICAGO (May 4, 2012) – Exelon Corporation (NYSE: EXC) announced first quarter 2012 consolidated earnings as follows:


	First Quarter
	2012		2011
Adjusted (non-GAAP) Operating Results:
Net Income ($ millions)	$	603	$	778
Diluted Earnings per Share	$	0.85	$	1.17

GAAP Results:
Net Income ($ millions)	$	200	$	668
Diluted Earnings per Share	$	0.28	$	1.01

“As expected, our lower operating earnings for first quarter 2012 reflected unfavorable market factors and mild weather,” said Christopher M. Crane, Exelon’s president and CEO. “However, I am pleased with our continued strong operational performance, such as the 93.6 percent capacity factor achieved by our nuclear operations. In the quarter’s most significant news, we successfully closed our merger with Constellation Energy on March 12 after securing all required regulatory approvals, less than one year after we first announced the transaction, and integration activities are progressing extremely well.”

First Quarter Operating Results

First quarter 2012 earnings include financial results for Constellation Energy (Constellation) and Baltimore Gas and Electric Company (BGE) beginning on March 12, 2012, the date the merger was completed. Therefore, the composition of results of operations from 2012 and 2011 are not comparable for Exelon Generation Company, LLC (Generation), BGE and Exelon.

As shown in the table above, Exelon’s adjusted (non-GAAP) operating earnings declined to $0.85 per share in the first quarter of 2012 from $1.17 per share in the first quarter of 2011. Earnings in 2012 primarily reflected the following negative factors:

•

the effect on energy margins at Generation of decreased capacity pricing related to the Reliability Pricing Model (RPM) for the PJM Interconnection, LLC (PJM) market, higher nuclear fuel costs and lower realized market prices for the sale of energy across all regions;

•

higher operating and maintenance expenses, including increased labor and contracting costs and the impact at Generation of increased scheduled nuclear refueling outage days;

•

impact on earnings per share reflecting the increase in Exelon’s average diluted common shares outstanding as a result of the Constellation merger (merger);

•

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

•

increased depreciation and amortization expense primarily due to ongoing capital expenditures.

These factors were partially offset by:

•

increased distribution revenue reflecting the effects of new distribution rates at ComEd effective June 1, 2011 and the Energy Infrastructure Modernization Act (EIMA);

•

the addition of BGE’s financial results and the contribution to Generation’s energy margins from Constellation after the merger completion date; and

•

realized gains in nuclear decommissioning trust (NDT) funds at Generation related to changes to the investment strategy and favorable market conditions in 2012.

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


	(in millions)			(per diluted share)
Mark-to-market gains primarily from Generation’s economic hedging activities, net of intercompany eliminations	$	43		$	0.06
Unrealized gains related to NDT fund investments to the extent not offset by contractual accounting	$	36		$	0.05
Financial impacts associated with the retirement of certain Generation fossil generating units	$	(4	)	$	(0.01	)
Certain costs related to the merger and integration initiatives	$	(113	)	$	(0.16	)
Costs incurred as part of Maryland commitments in connection with the merger	$	(227	)	$	(0.32	)
Non-cash amortization of intangible assets, net, related to commodity contracts recorded at fair value at the merger date	$	(78	)	$	(0.11	)
Costs incurred as part of a March 2012 settlement with the Federal Energy Regulatory Commission (FERC) related to Constellation’s prior period hedging and risk management transactions	$	(172	)	$	(0.25	)
Reassessment of state deferred income taxes	$	117		$	0.17
Revenues and operating expenses related to three generation facilities required to be sold within 180 days of the merger	$	(2	)		—
Certain costs incurred associated with other acquisitions	$	(3	)		—

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


	(in millions)			(per diluted share)
Mark-to-market losses primarily from Generation’s economic hedging activities	$	(89	)	$	(0.14	)
Unrealized gains related to NDT fund investments to the extent not offset by contractual accounting	$	24		$	0.04
Non-cash charge to remeasure deferred taxes at higher Illinois corporate tax rates	$	(29	)	$	(0.04	)
Financial impacts associated with the retirement of certain Generation fossil generating units	$	(16	)	$	(0.02	)

First Quarter and Recent Highlights

•

Nuclear Operations: Generation’s nuclear fleet, including its owned output from the Salem Generating Station, produced 35,262 gigawatt-hours (GWh) in the first quarter of 2012, compared with 35,192 GWh in the first 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 93.6 percent capacity factor for the first quarter of 2012 compared with 94.8 percent for the first quarter of 2011. The Exelon-operated nuclear plants completed two scheduled refueling outages in the first quarter of 2012 and began a third, compared with completing one scheduled refueling outage and beginning two others in the first quarter of 2011. The number of planned refueling outage days totaled 67 in the first quarter of 2012 versus 44 days in the first quarter of 2011. The number of non-refueling outage days at the Exelon-operated plants totaled 16 days in the first quarter of 2012 compared with 14 days in the first quarter of 2011.

•

Fossil and Renewables Operations: The equivalent demand forced outage rate for Generation’s fossil fleet was 1.1 percent in the first quarter of 2012, compared with 2.3 percent in the first quarter of 2011. The change was largely due to lower power prices and lower demand in 2012, attributable to the mild weather. The equivalent availability factor for the hydroelectric facilities was 99.6 percent in the first quarter of 2012, compared with 97.8 percent in the first quarter of 2011. The change was primarily due to the heavy rains and snow run-off in March 2011, which caused the dam at the Conowingo hydro station to enter spill conditions so it was unable to generate. The energy capture for the wind fleet was 95.0 percent in the first quarter of 2012, compared with 92.9 percent in the first quarter of 2011. The above statistics exclude the former Constellation plants.

•

Whitetail Wind Energy Acquisition: On March 13, 2012, Exelon completed the purchase of Whitetail Wind Energy LLC, a 92-megawatt (MW) wind project to be constructed east of Laredo, Texas. The project has a 25-year power purchase agreement with Austin Energy for its entire output. Commercial operation is expected in late 2012.

•

Antelope Valley Solar Ranch One: On April 5, 2012, Exelon and First Solar, Inc. announced that the Antelope Valley Solar Ranch One project had received the first advance of a loan guaranteed by the U.S. Department of Energy’s Loan Programs Office, finalizing Exelon’s ownership of the project. First Solar is constructing the 230-MW photovoltaic power project in northern Los Angeles County and will operate and maintain the project for Exelon. As Exelon and First Solar previously announced, the first portion of the project is expected to come online in late 2012, with full operation planned for late 2013. The project has a 25-year power purchase agreement, approved by the California Public Utilities Commission, with Pacific Gas & Electric Company for the full output of the plant.

•

ComEd Distribution Formula Rate Cases: On November 8, 2011, ComEd filed under EIMA its performance-based formula rate tariff with the Illinois Commerce Commission (ICC). This tariff embodied the formula rate model that is to govern delivery service rate-setting as well as the initial data used to set rates. The resulting initial rate, which is expected to be lower than current rates but will be subject to reconciliation, will take effect within 30 days after the ICC order, which must be issued by May 31, 2012. On May 1, 2012, the Administrative Law Judges (ALJs) issued a proposed order in the case recommending a $146 million reduction in the

revenue requirement, as opposed to ComEd’s final position that a $59 million reduction was appropriate. Certain significant provisions of the ALJs’ proposed order are consistent with ComEd’s initial filing. As a proposed order, it has no independent legal effect as the ICC must vote on a final order which may materially vary from the findings and conclusions in the proposed order. ComEd will file updated costs and a reconciliation with actual costs at the ICC each year. ComEd filed the first annual cost update and reconciliation for 2011 on April 30, 2012, and the adjusted rates are expected to take effect in January 2013 after the ICC’s review. If the ALJs’ proposed order related to the November 8, 2011 filing is implemented, the revenue requirement reduction as proposed by the ALJs would primarily delay the timing of cash flows, with a less significant impact on earnings given the annual reconciliation mechanism. ComEd does not believe it will have a material impact to the cumulative regulatory asset that has been recorded as of March 31, 2012.

OPERATING COMPANY RESULTS

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

First quarter 2012 net income was $168 million compared with $495 million in the first quarter of 2011. First quarter 2012 net income included (all after tax) mark-to-market gains of $36 million from economic hedging activities, unrealized gains of $36 million related to NDT fund investments, net costs of $4 million associated with the retirement of certain fossil generating units, certain costs incurred of $45 million associated with the merger and integration initiatives, costs of $22 million incurred as part of the Maryland commitments in connection with the merger, amortization of commodity contract intangibles of $78 million, FERC settlement costs of $172 million, benefit of $13 million for the reassessment of state deferred income taxes, net expenses of $2 million for plant divestitures and certain other acquisition costs of $3 million. First quarter 2011 net income included (all after tax) mark-to-market losses of $89 million from economic hedging activities, a non-cash charge of $21 million to remeasure deferred taxes at higher Illinois corporate tax rates, unrealized gains of $24 million related to NDT fund investments and costs of $16 million associated with the planned retirement of certain fossil generating units.

Excluding the effects of these items, Generation’s net income in the first quarter of 2012 decreased $188 million compared with the same quarter in 2011. This decrease primarily reflected:

•

the impact on energy margins of decreased capacity pricing related to RPM for the PJM market, higher nuclear fuel costs and lower realized market prices for the sale of energy across all regions;

•

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

•

increased depreciation and amortization expense primarily due to ongoing capital expenditures.

These items were partially offset by realized gains in NDT funds related to changes to the investment strategy and favorable market conditions in 2012.

Generation’s average realized margin on all electric sales, including sales to affiliates and excluding trading activity, was $32.57 per megawatt-hour (MWh) in the first quarter of 2012 compared with $44.30 per MWh in the first quarter of 2011.

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

ComEd recorded net income of $87 million in the first quarter of 2012, compared with net income of $69 million in the first quarter of 2011. First quarter net income in 2012 included certain after-tax costs incurred of $1 million associated with the merger and integration initiatives. First quarter net income in 2011 included an after-tax non-cash charge of $4 million to remeasure deferred taxes at higher Illinois corporate tax rates. Excluding the effects of these items, ComEd’s net income in the first quarter of 2012 was up $15 million from the same quarter in 2011, primarily due to increased distribution revenue reflecting the effects of new distribution rates effective June 1, 2011 and EIMA.

These favorable items were partially offset by:

•

the effect of unfavorable weather in ComEd’s service territory; and

•

higher operating and maintenance expenses reflecting increased labor and contracting costs driven, in part, by EIMA initiatives.

In the first quarter of 2012, heating degree-days in the ComEd service territory were down 28.5 percent relative to the same period in 2011 and were 24.7 percent below normal. Total retail electric deliveries decreased 3.7 percent quarter over quarter.

Weather-normalized retail electric deliveries increased 0.5 percent in the first quarter of 2012 relative to 2011, reflecting increases in deliveries to both small and large commercial and industrial (C&I) customers that were partially offset by a decrease in deliveries to residential customers. For ComEd, weather had an unfavorable after-tax effect of $11 million on first quarter 2012 earnings relative to 2011 and an unfavorable after-tax effect of $9 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 first quarter of 2012 was $96 million, compared with $125 million in the first quarter of 2011. First quarter net income in 2012 included certain after-tax costs incurred of $4 million associated with the merger and integration initiatives. Excluding the effect of this item, PECO’s net income in the first quarter of 2012 was down $25 million from the same quarter in 2011, primarily reflecting the effect of unfavorable weather in PECO’s service territory.

In the first quarter of 2012, heating degree-days in the PECO service territory were down 23.6 percent from 2011 and were 22.7 percent below normal. Total retail electric deliveries were down 7.0 percent from last year. On the retail gas side, deliveries in the first quarter of 2012 were down 21.9 percent from the first quarter of 2011.

Weather-normalized retail electric deliveries were down 2.7 percent in the first quarter of 2012 relative to 2011, reflecting declines in deliveries to all customer classes. Weather-normalized retail gas deliveries were up 1.3 percent in the first quarter of 2012. For PECO, weather had an unfavorable after-tax effect of $29 million on first quarter 2012 earnings relative to 2011 and an unfavorable after-tax effect of $30 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 loss from March 12, the date the merger was completed, to March 31, 2012 was $66 million. The net loss included certain after-tax costs of $83 million incurred as part of the Maryland commitments in connection with the merger and $1 million incurred associated with the merger and integration initiatives. Excluding the effects of these items, BGE’s net income from March 12 to March 31, 2012 was $18 million.

Adjusted (non-GAAP) Operating Earnings

Adjusted (non-GAAP) operating earnings, which generally exclude significant one-time charges or credits that are not normally associated with ongoing operations, mark-to-market adjustments from economic hedging activities and unrealized gains and losses from NDT fund investments, are provided as a supplement to results reported in accordance with GAAP. Management uses such adjusted (non-GAAP) operating earnings measures internally to evaluate the company’s performance and manage its operations. Reconciliation of GAAP to adjusted (non-GAAP) operating earnings for historical periods is attached. Additional earnings release attachments, which include the reconciliation on page 7, are posted on Exelon’s Web site: www.exeloncorp.com and have been furnished to the Securities and Exchange Commission on Form 8-K on May 4, 2012.

Cautionary Statements Regarding Forward-Looking Information

This news release includes forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995 that are subject to risks and uncertainties. The factors that could cause actual results to differ materially from these forward-looking statements include those discussed herein as well as those discussed in (1) Exelon’s 2011 Annual Report on Form 10-K in (a) ITEM 1A. Risk Factors, (b) ITEM 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations and (c) ITEM 8. Financial Statements and Supplementary Data: Note 18; (2) Constellation Energy Group, Inc.’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; and (3) other factors discussed in filings with the Securities and Exchange Commission by Exelon, Generation, BGE, ComEd and PECO (the Companies) and Constellation. Readers are cautioned not to place undue reliance on these forward-looking statements, which apply only as of the date of this news release. None of the Companies 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).

Exhibit 99.1

Earnings Release Attachments

Table of Contents



Consolidating Statements of Operations—Three Months Ended March 31, 2012 and 2011			1

Business Segment Comparative Statements of Operations—Generation and ComEd—Three Months Ended March 31, 2012 and 2011			2

Business Segment Comparative Statements of Operations—PECO and BGE—Three Months Ended March 31, 2012 and 2011			3

Business Segment Comparative Statements of Operations—Other—Three Months Ended March 31, 2012 and 2011			4

Consolidated Balance Sheets—March 31, 2012 and December 31, 2011			5

Consolidated Statements of Cash Flows—Three Months Ended March 31, 2012 and 2011			6

Reconciliation of Adjusted (non-GAAP) Operating Earnings to GAAP Consolidated Statements of Operations—Exelon—Three Months Ended March 31, 2012 and 2011			7

Reconciliation of Adjusted (non-GAAP) Operating Earnings to GAAP Earnings By Business Segment—Three Months Ended March 31, 2012 and 2011			8

Reconciliation of Adjusted (non-GAAP) Operating Earnings to GAAP Consolidated Statements of Operations—Generation—Three Months Ended March 31, 2012 and 2011			9

Reconciliation of Adjusted (non-GAAP) Operating Earnings to GAAP Consolidated Statements of Operations—ComEd—Three Months Ended March 31, 2012 and 2011			10

Reconciliation of Adjusted (non-GAAP) Operating Earnings to GAAP Consolidated Statements of Operations—PECO—Three Months Ended March 31, 2012 and 2011			11

Reconciliation of Adjusted (non-GAAP) Operating Earnings to GAAP Consolidated Statements of Operations—BGE—March 12, 2012 Through March 31, 2012			12

Reconciliation of Adjusted (non-GAAP) Operating Earnings to GAAP Consolidated Statements of Operations—Other—Three Months Ended March 31, 2012 and 2011			13

Exelon Generation Statistics—Three Months Ended March 31, 2012, December 31, 2011, September 30, 2011, June 30, 2011 and March 31, 2011			14

ComEd Statistics—Three Months Ended March 31, 2012 and 2011			15

PECO Statistics—Three Months Ended March 31, 2012 and 2011			16

BGE Statistics—March 12, 2012 Through March 31, 2012			17

EXELON CORPORATION

Consolidating Statements of Operations

(unaudited)

(in millions)


	Three Months Ended March 31, 2012 (a)
	Generation			ComEd			PECO			BGE			Other (b)			Exelon Consolidated
Operating revenues	$	2,739		$	1,388		$	875		$	52		$	(368	)	$	4,686

Operating expenses
Purchased power and fuel		1,044			620			411			68			(378	)		1,765
Operating and maintenance		1,175			318			203			60			208			1,964
Depreciation, amortization, accretion and depletion		153			149			53			19			8			382
Taxes other than income		73			75			31			9			6			194

Total operating expenses		2,445			1,162			698			156			(156	)		4,305

Equity in loss of unconsolidated affiliates		(22	)		—			—			—			—			(22	)

Operating income (loss)		272			226			177			(104	)		(212	)		359

Other income and deductions
Interest expense		(54	)		(82	)		(31	)		(8	)		(20	)		(195	)
Other, net		178			4			2			1			9			194

Total other income and deductions		124			(78	)		(29	)		(7	)		(11	)		(1	)

Income (loss) before income taxes		396			148			148			(111	)		(223	)		358

Income taxes		230			61			51			(46	)		(138	)		158

Net income (loss)		166			87			97			(65	)		(85	)		200

Net loss attributable to noncontrolling interests, preferred security dividends and preference stock dividends		(2	)		—			1			1			—			—

Net income (loss) on common stock	$	168		$	87		$	96		$	(66	)	$	(85	)	$	200


	Three Months Ended March 31, 2011
	Generation			ComEd			PECO			BGE			Other (b)			Exelon Consolidated
Operating revenues	$	2,643		$	1,466		$	1,153		$	—		$	(306	)	$	4,956

Operating expenses
Purchased power and fuel		883			789			633			—			(304	)		2,001
Operating and maintenance		754			266			206			—			(3	)		1,223
Depreciation, amortization, accretion and depletion		139			134			48			—			6			327
Taxes other than income		66			77			56			—			4			203

Total operating expenses		1,842			1,266			943			—			(297	)		3,754

Operating income (loss)		801			200			210			—			(9	)		1,202

Other income and deductions
Interest expense		(45	)		(85	)		(34	)		—			(17	)		(181	)
Other, net		75			4			6			—			9			94

Total other income and deductions		30			(81	)		(28	)		—			(8	)		(87	)

Income (loss) before income taxes		831			119			182						(17	)		1,115

Income taxes		336			50			56			—			4			446

Net income (loss)		495			69			126			—			(21	)		669

Preferred security dividends		—			—			1			—			—			1

Net income (loss) on common stock	$	495		$	69		$	125		$	—		$	(21	)	$	668

(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.

EXELON CORPORATION

Business Segment Comparative Statements of Operations

(unaudited)

(in millions)


	Generation Three Months Ended March 31,
	2012 (a)			2011			Variance
Operating revenues	$	2,739		$	2,643		$	96

Operating expenses
Purchased power and fuel		1,044			883			161
Operating and maintenance		1,175			754			421
Depreciation, amortization, accretion and depletion		153			139			14
Taxes other than income		73			66			7

Total operating expenses		2,445			1,842			603
Equity in loss of unconsolidated affiliates		(22	)		—			(22	)

Operating income		272			801			(529	)

Other income and deductions
Interest expense		(54	)		(45	)		(9	)
Other, net		178			75			103

Total other income and deductions		124			30			94

Income before income taxes		396			831			(435	)
Income taxes		230			336			(106	)

Net income		166			495			(329	)
Net loss attributable to noncontrolling interests		(2	)		—			(2	)

Net income on common stock	$	168		$	495		$	(327	)

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


	ComEd Three Months Ended March 31,
	2012			2011			Variance
Operating revenues	$	1,388		$	1,466		$	(78	)

Operating expenses
Purchased power		620			789			(169	)
Operating and maintenance		318			266			52
Depreciation and amortization		149			134			15
Taxes other than income		75			77			(2	)

Total operating expenses		1,162			1,266			(104	)

Operating income		226			200			26

Other income and deductions
Interest expense		(82	)		(85	)		3
Other, net		4			4			—

Total other income and deductions		(78	)		(81	)		3

Income before income taxes		148			119			29

Income taxes		61			50			11

Net income	$	87		$	69		$	18

EXELON CORPORATION

Business Segment Comparative Statements of Operations

(unaudited)

(in millions)


	PECO Three Months Ended March 31,
	2012			2011			Variance
Operating revenues	$	875		$	1,153		$	(278	)

Operating expenses
Purchased power and fuel		411			633			(222	)
Operating and maintenance		203			206			(3	)
Depreciation and amortization		53			48			5
Taxes other than income		31			56			(25	)

Total operating expenses		698			943			(245	)

Operating income		177			210			(33	)

Other income and deductions
Interest expense		(31	)		(34	)		3
Other, net		2			6			(4	)

Total other income and deductions		(29	)		(28	)		(1	)

Income before income taxes		148			182			(34	)

Income taxes		51			56			(5	)

Net income		97			126			(29	)

Preferred security dividends		1			1			—

Net income on common stock	$	96		$	125		$	(29	)


	BGE March 12, 2012 through March 31, 2012
	2012			2011			Variance
Operating revenues	$	52		$	—		$	52

Operating expenses
Purchased power and fuel		68			—			68
Operating and maintenance		60			—			60
Depreciation and amortization		19			—			19
Taxes other than income		9			—			9

Total operating expenses		156			—			156

Operating loss		(104	)		—			(104	)

Other income and deductions
Interest expense		(8	)		—			(8	)
Other, net		1			—			1

Total other income and deductions		(7	)		—			(7	)

Loss before income taxes		(111	)		—			(111	)

Income taxes		(46	)		—			(46	)

Net loss		(65	)		—			(65	)

Preference stock dividends		1			—			1

Net loss on common stock	$	(66	)	$	—		$	(66	)

EXELON CORPORATION

Business Segment Comparative Statements of Operations

(unaudited)

(in millions)


	Other (a) Three Months Ended March 31,
	2012 (b)			2011			Variance
Operating revenues	$	(368	)	$	(306	)	$	(62	)

Operating expenses
Purchased power and fuel		(378	)		(304	)		(74	)
Operating and maintenance		208			(3	)		211
Depreciation and amortization		8			6			2
Taxes other than income		6			4			2

Total operating expenses		(156	)		(297	)		141

Operating loss		(212	)		(9	)		(203	)

Other income and deductions
Interest expense		(20	)		(17	)		(3	)
Other, net		9			9			—

Total other income and deductions		(11	)		(8	)		(3	)

Loss before income taxes		(223	)		(17	)		(206	)

Income taxes		(138	)		4			(142	)

Net loss	$	(85	)	$	(21	)	$	(64	)

(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.

EXELON CORPORATION

Consolidated Balance Sheets

(unaudited)

(in millions)


	March 31, 2012 (a)			December 31, 2011
ASSETS

Current assets
Cash and cash equivalents	$	721		$	1,016
Restricted cash and investments		43			40
Restricted cash and investments of variable interest entities		67			—
Accounts receivable, net
Customer		2,868			1,613
Other		1,339			1,000
Accounts receivable, net, of variable interest entities		241			—
Mark-to-market derivative assets		1,490			432
Unamortized energy contracts assets		1,699			13
Inventories, net
Fossil fuel		202			208
Materials and supplies		740			656
Regulatory assets		846			390
Other		1,559			345

Total current assets		11,815			5,713

Property, plant and equipment, net		42,105			32,570

Deferred debits and other assets
Regulatory assets		6,168			4,518
Nuclear decommissioning trust (NDT) funds		6,927			6,507
Investments		827			751
Investments in affiliates		364			15
Investment in CENG		2,046			—
Goodwill		2,625			2,625
Mark-to-market derivative assets		1,389			650
Unamortized energy contracts assets		1,530			388
Pledged assets for Zion Station decommissioning		708			734
Other		1,124			524

Total deferred debits and other assets		23,708			16,712

Total assets	$	77,628		$	54,995

Liabilities and shareholders’ equity

Current liabilities
Short-term borrowings	$	339		$	163
Short-term notes payable - accounts receivable agreement		225			225
Long-term debt due within one year		670			828
Long-term debt of variable interest entities due within one year		65			—
Accounts payable		2,125			1,444
Accounts payable of variable interest entities		138			—
Accrued expenses		1,492			1,255
Deferred income taxes		517			1
Regulatory liabilities		335			197
Dividends payable		472			349
Mark-to-market derivative liabilities		1,105			112
Unamortized energy contract liabilities		707			—
Other		862			560

Total current liabilities		9,052			5,134

Long-term debt		16,293			11,799
Long-term debt to financing trusts		648			390
Long-term debt of variable interest entity		517			—

Deferred credits and other liabilities
Deferred income taxes and unamortized investment tax credits		10,705			8,253
Asset retirement obligations		4,064			3,884
Pension obligations		2,553			2,194
Non-pension postretirement benefit obligations		2,688			2,263
Spent nuclear fuel obligation		1,019			1,019
Regulatory liabilities		4,050			3,627
Mark-to-market derivative liabilities		671			126
Unamortized energy contract liabilities		897			—
Payable for Zion Station decommissioning		574			563
Other		1,708			1,268

Total deferred credits and other liabilities		28,929			23,197

Total liabilities		55,439			40,520

Commitments and contingencies
Preferred securities of subsidiary		87			87
Shareholders’ equity
Common stock		16,512			9,107
Treasury stock, at cost		(2,327	)		(2,327	)
Retained earnings		9,830			10,055
Accumulated other comprehensive loss, net		(2,199	)		(2,450	)

Total shareholders’ equity		21,816			14,385

BGE preference stock not subject to mandatory redemption		193			—
Noncontrolling interest		93			3

Total equity		22,102			14,388

Total liabilities and shareholders’ equity	$	77,628		$	54,995

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

EXELON CORPORATION

Consolidated Statements of Cash Flows

(unaudited)

(in millions)


	Three Months Ended March 31,
	2012 (a)			2011
Cash flows from operating activities
Net income	$	200		$	669
Adjustments to reconcile net income to net cash flows provided by (used in) operating activities:
Depreciation, amortization, accretion and depletion, including nuclear fuel and energy contract amortization		767			552
Deferred income taxes and amortization of investment tax credits		101			340
Net fair value changes related to derivatives		(73	)		148
Net realized and unrealized gains on NDT fund investments		(103	)		(40	)
Other non-cash operating activities		540			223
Changes in assets and liabilities:
Accounts receivable		384			53
Inventories		104			78
Accounts payable, accrued expenses and other current liabilities		(1,176	)		(526	)
Option premiums received (paid), net		(100	)		19
Counterparty collateral received (posted), net		340			(150	)
Income taxes		178			733
Pension and non-pension postretirement benefit contributions		(55	)		(2,088	)
Other assets and liabilities		(130	)		(218	)

Net cash flows provided by (used in) operating activities		977			(207	)

Cash flows from investing activities
Capital expenditures		(1,496	)		(1,150	)
Proceeds from nuclear decommissioning trust fund sales		3,680			1,195
Investment in nuclear decommissioning trust funds		(3,726	)		(1,247	)
Cash acquired from Constellation		964			—
Proceeds from sales of investments		10			1
Purchases of investments		(5	)		(1	)
Change in restricted cash		(8	)		8
Other investing activities		(42	)		15

Net cash flows used in investing activities		(623	)		(1,179	)

Cash flows from financing activities
Changes in short-term debt		141			50
Issuance of long-term debt		—			599
Retirement of long-term debt		(451	)		(1	)
Dividends paid on common stock		(350	)		(348	)
Proceeds from employee stock plans		12			8
Other financing activities		(1	)		(47	)

Net cash flows (used in) provided by financing activities		(649	)		261

Decrease in cash and cash equivalents		(295	)		(1,125	)
Cash and cash equivalents at beginning of period		1,016			1,612

Cash and cash equivalents at end of period	$	721		$	487

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

EXELON CORPORATION

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

(unaudited)

(in millions, except per share data)


	Three Months Ended March 31, 2012 (a)									Three Months Ended March 31, 2011
	GAAP (b)			Adjustments			Adjusted Non-GAAP			GAAP (b)			Adjustments			Adjusted Non-GAAP
Operating revenues	$	4,686		$	147	(c),(d),(e), (f),(g)	$	4,833		$	4,956		$	—		$	4,956

Operating expenses
Purchased power and fuel		1,765			1	(c),(d),(e), (f),(h)		1,766			2,001			(147	)(d)		1,854
Operating and maintenance		1,964			(574	)(c),(f),(g), (h),(i),(j)		1,390			1,223			(2	)(c)		1,221
Depreciation, amortization, accretion and depletion		382			(16	)(c)		366			327			(24	)(c)		303
Taxes other than income		194			1	(f),(g)		195			203			—			203

Total operating expenses		4,305			(588	)		3,717			3,754			(173	)		3,581

Equity in loss of unconsolidated affiliates		(22	)		8	(e)		(14	)		—			—			—

Operating income		359			743			1,102			1,202			173			1,375

Other income and deductions
Interest expense		(195	)		(1	)(e)		(196	)		(181	)		—			(181	)
Other, net		194			(119	)(k)		75			94			(63	)(k)		31

Total other income and deductions		(1	)		(120	)		(121	)		(87	)		(63	)		(150	)

Income before income taxes		358			623			981			1,115			110			1,225

Income taxes		158			220	(c),(d),(e), (f),(g),(h), (i),(j),(k),(l)		378			446			—	(c),(d), (k),(m)		446

Net income		200			403			603			669			110			779

Net loss attributable to noncontrolling interests, preferred security dividends and preference stock dividends		—			—			—			1			—			1

Net income on common stock	$	200		$	403		$	603		$	668		$	110		$	778

Effective tax rate		44.1	%					38.5	%		40.0	%					36.4	%

Earnings per average common share
Basic	$	0.28		$	0.57		$	0.85		$	1.01		$	0.16		$	1.17
Diluted	$	0.28		$	0.57		$	0.85		$	1.01		$	0.16		$	1.17

Average common shares outstanding
Basic		705						705			662						662
Diluted		707						707			664						664

Effect of adjustments on earnings per average diluted common share recorded in accordance with GAAP:
Retirement of fossil generating units (c)				$	0.01								$	0.02
Mark-to-market impact of economic hedging activities (d)					(0.06	)								0.14
Amortization of commodity contract intangibles (e)					0.11									—
Plant divestitures (f)					—									—
Maryland commitments (g)					0.32									—
Constellation merger and integration costs (h)					0.16									—
Federal Energy Regulatory Commission (FERC) settlement (i)					0.25									—
Other acquisition costs (j)					—									—
Unrealized (gains) related to NDT fund investments (k)					(0.05	)								(0.04	)
Reassessment of state deferred income taxes (l)					(0.17	)								—
Charge resulting from Illinois tax rate change legislation (m)					—									0.04

Total adjustments				$	0.57								$	0.16

(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 planned retirement of fossil generating units and the impacts of the FERC approved reliability-must-run rate schedule.

(d)	Adjustment to exclude the mark-to-market impact of Exelon’s economic hedging activities, 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 the revenues and operating expenses related to three generation facilities required to be sold within 180 days of the merger.

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

(h)	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.

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

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

(k)	Adjustment to exclude the unrealized gains in 2012 and 2011 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 a one-time, non-cash charge to remeasure deferred taxes at higher corporate tax rates pursuant to the Illinois tax rate change legislation.

EXELON CORPORATION (a)

Reconciliation of Adjusted (non-GAAP) Operating

Earnings to GAAP Earnings (in millions)

Three Months Ended March 31, 2012 and 2011


	Exelon Earnings per Diluted Share			Generation			ComEd			PECO			BGE			Other (b)			Exelon
2011 GAAP Earnings (Loss)	$	1.01		$	495		$	69		$	125		$	—		$	(21	)	$	668

2011 Adjusted (non-GAAP) Operating Earnings (Loss) Adjustments:
Mark-to-Market Impact of Economic Hedging Activities		0.14			89			—			—			—			—			89
Unrealized Gains Related to NDT Fund Investments (1)		(0.04	)		(24	)		—			—			—			—			(24	)
Retirement of Fossil Generating Units (2)		0.02			16			—			—			—			—			16
Non-Cash Charge Resulting From Illinois Tax Rate Change Legislation (3)		0.04			21			4			—			—			4			29

2011 Adjusted (non-GAAP) Operating Earnings (Loss)		1.17			597			73			125			—			(17	)		778

Year Over Year Effects on Earnings:
Generation Energy Margins, Excluding Mark-to-Market:
Nuclear Volume		—			1			—			—			—			—			1
Nuclear Fuel Costs (4)		(0.03	)		(19	)		—			—			—			—			(19	)
Capacity Pricing		(0.11	)		(74	)		—			—			—			—			(74	)
Market and Portfolio Conditions (5)		(0.02	)		(11	)		—			—			—			—			(11	)
ComEd, PECO and BGE Margins:
Weather		(0.06	)		—			(11	)		(29	)		—	(c)		—			(40	)
Load		(0.01	)		—			1			(5	)		—	(c)		—			(4	)
Other Energy Delivery (6)		0.17			—			64			(3	)		58			—			119
Operating and Maintenance Expense:
Labor, Contracting and Materials (7)		(0.07	)		(27	)		(16	)		1			(11	)		—			(53	)
Planned Nuclear Refueling Outages (8)		(0.01	)		(10	)		—			—			—			—			(10	)
Pension and Non-Pension Postretirement Benefits (9)		(0.03	)		(9	)		(5	)		(2	)		(1	)		(2	)		(19	)
Other Operating and Maintenance (10)		(0.03	)		(16	)		(9	)		7			(6	)		4			(20	)
Depreciation and Amortization Expense (11)		(0.05	)		(13	)		(9	)		(3	)		(11	)		(2	)		(38	)
Equity in Losses of unconsolidated Affiliates (12)		(0.01	)		(9	)		—			—			—			—			(9	)
Income Taxes (13)		(0.02	)		(14	)		(3	)		(7	)		1			8			(15	)
Interest Expense, Net		(0.02	)		(7	)		1			2			(5	)		(3	)		(12	)
Other (14)		0.04			20			2			14			(7	)		—			29
Share Differential (15)		(0.06	)		—			—			—			—			—			—

2012 Adjusted (non-GAAP) Operating Earnings (Loss)		0.85			409			88			100			18			(12	)		603

2012 Adjusted (non-GAAP) Operating Earnings (Loss) Adjustments:
Mark-to-Market Impact of Economic Hedging Activities		0.06			36			—			—			—			7			43
Unrealized Gains Related to NDT Fund Investments (1)		0.05			36			—			—			—			—			36
Retirement of Fossil Generating Units (2)		(0.01	)		(4	)		—			—			—			—			(4	)
Constellation Merger and Integration Costs (16)		(0.16	)		(45	)		(1	)		(4	)		(1	)		(62	)		(113	)
Maryland Commitments (17)		(0.32	)		(22	)		—			—			(83	)		(122	)		(227	)
Amortization of Commodity Contract Intangibles (18)		(0.11	)		(78	)		—			—			—			—			(78	)
FERC Settlement (19)		(0.25	)		(172	)		—			—			—			—			(172	)
Plant Divestitures (20)		—			(2	)		—			—			—			—			(2	)
Reassessment of State Deferred Income Taxes (21)		0.17			13			—			—			—			104			117
Other Acquisition Costs		—			(3	)		—			—			—			—			(3	)

2012 GAAP Earnings (Loss)	$	0.28		$	168		$	87		$	96		$	(66	)	$	(85	)	$	200

(a)

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

For 2011 and 2012, primarily reflects accelerated depreciation expense associated with the planned retirement of four generating units, of which two retired on May 31, 2011 and one retired on December 31, 2011. For 2012, also includes compensation for operating the remaining unit past its planned May 31, 2011 retirement date under a FERC-approved reliability-must-run rate schedule.

(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 the impact of higher nuclear fuel prices.

(5)	Primarily reflects the impact of decreased realized market prices for the sale of energy across all regions.

(6)

For ComEd, primarily reflects increased distribution revenue pursuant to the 2011 electric distribution rate case order and Energy Infrastructure Modernization Act (EIMA), and increased cost recovery for energy efficiency and demand response programs (completely offset in operating and maintenance expense below).

(7)

Primarily reflects the impacts of increased wages and other benefits and increased contracting expenses (exclusive of planned nuclear refueling outages and incremental storm costs as disclosed in numbers 8 and 10 below). At ComEd, increased contracting expenses primarily resulted from new projects related to EIMA.

(8)	Primarily reflects the impact of increased planned nuclear refueling outage days in 2012, excluding Salem and Constellation Energy Nuclear Group, LLC (CENG).

(9)	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.

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

(11)	Primarily reflects increased depreciation expense across the operating companies due to ongoing capital expenditures.

(12)	Primarily reflects the impact of increased planned nuclear refueling outage days in 2012 at CENG.

(13)	Primarily reflects a reduction in Generation’s manufacturing deduction benefits in 2012 and benefits received in 2011 related to the 2010 tax year associated with Pennsylvania bonus depreciation.

(14)

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 above) and the impact of a sales and use tax reserve reduction resulting from an audit.

(15)	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.

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

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

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

(19)	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.

(20)	Represents revenues and operating expenses related to three generation facilities required to be sold within 180 days of the merger.

(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.

EXELON CORPORATION

Reconciliation of Adjusted (non-GAAP) Operating Earnings to

GAAP Consolidated Statements of Operations

(unaudited)

(in millions)


	Generation
	Three Months Ended March 31, 2012 (a)									Three Months Ended March 31, 2011
	GAAP (b)			Adjustments			Adjusted Non -GAAP			GAAP (b)			Adjustments			Adjusted Non- GAAP
Operating revenues	$	2,739		$	45	(c),(d),(e),(f)	$	2,784		$	2,643		$	—		$	2,643

Operating expenses

Purchased power and fuel		1,044			1	(c),(d),(e), (f),(g)		1,045			883			(147	)(d)		736
Operating and maintenance		1,175			(321	)(c),(f),(g), (h),(i),(j)		854			754			(2	)(c)		752
Depreciation, amortization, accretion and depletion		153			(16	)(c)		137			139			(24	)(c)		115
Taxes other than income		73			(1	)(f)		72			66			—			66

Total operating expenses		2,445			(337	)		2,108			1,842			(173	)		1,669

Equity in loss of unconsolidated affiliates		(22	)		8			(14	)		—			—			—

Operating income		272			390			662			801			173			974

Other income and deductions
Interest expense		(54	)		(1	)(e)		(55	)		(45	)		—			(45	)
Other, net		178			(119	)(k)		59			75			(63	)(k)		12

Total other income and deductions		124			(120	)		4			30			(63	)		(33	)

Income before income taxes		396			270			666			831			110			941

Income taxes		230			29	(c),(d),(e), (f),(g),(h), (i),(j),(k),(l)		259			336			8	(c),(d), (k),(m)		344

Net income		166			241			407			495			102			597

Net loss attributable to noncontrolling interests		(2	)		—			(2	)		—			—			—

Net income on common stock	$	168		$	241		$	409		$	495		$	102		$	597

(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 planned retirement of fossil generating units and the impacts of the FERC approved reliability-must-run rate schedule.

(d)	Adjustment to exclude the mark-to-market impact of 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 the revenues and operating expenses related to three generation facilities required to be sold within 180 days of the merger.

(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 incurred as part of the Maryland order approving the merger transaction.

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

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

(k)	Adjustment to exclude the unrealized gains in 2012 and 2011 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 a one-time, non-cash charge to remeasure deferred taxes at higher corporate tax rates pursuant to the Illinois tax rate change legislation.

EXELON CORPORATION

Reconciliation of Adjusted (non-GAAP) Operating Earnings to

GAAP Consolidated Statements of Operations

(unaudited)

(in millions)


	ComEd
	Three Months Ended March 31, 2012									Three Months Ended March 31, 2011
	GAAP (a)			Adjustments			Adjusted Non- GAAP			GAAP (a)			Adjustments			Adjusted Non- GAAP
Operating revenues	$	1,388		$	—		$	1,388		$	1,466		$	—		$	1,466

Operating expenses
Purchased power		620			—			620			789			—			789
Operating and maintenance		318			(2	)(b)		316			266			—			266
Depreciation and amortization		149			—			149			134			—			134
Taxes other than income		75			—			75			77			—			77

Total operating expenses		1,162			(2	)		1,160			1,266			—			1,266

Operating income		226			2			228			200			—			200

Other income and deductions
Interest expense		(82	)		—			(82	)		(85	)		—			(85	)
Other, net		4			—			4			4			—			4

Total other income and deductions		(78	)		—			(78	)		(81	)		—			(81	)

Income before income taxes		148			2			150			119			—			119

Income taxes		61			1	(b)		62			50			(4	)(c)		46

Net income	$	87		$	1		$	88		$	69		$	4		$	73

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

EXELON CORPORATION

Reconciliation of Adjusted (non-GAAP) Operating Earnings to

GAAP Consolidated Statements of Operations

(unaudited)

(in millions)


	PECO
	Three Months Ended March 31, 2012									Three Months Ended March 31, 2011
	GAAP (a)			Adjustments			Adjusted Non- GAAP			GAAP (a)			Adjustments		Adjusted Non- GAAP
Operating revenues	$	875		$	—		$	875		$	1,153		$	—	$	1,153

Operating expenses
Purchased power and fuel		411			—			411			633			—		633
Operating and maintenance		203			(7	)(b)		196			206			—		206
Depreciation and amortization		53			—			53			48			—		48
Taxes other than income		31			—			31			56			—		56

Total operating expenses		698			(7	)		691			943			—		943

Operating income		177			7			184			210			—		210

Other income and deductions
Interest expense		(31	)		—			(31	)		(34	)		—		(34	)
Other, net		2			—			2			6			—		6

Total other income and deductions		(29	)		—			(29	)		(28	)		—		(28	)

Income before income taxes		148			7			155			182			—		182

Income taxes		51			3	(b)		54			56			—		56

Net income		97			4			101			126			—		126

Preferred security dividends		1			—			1			1			—		1

Net income on common stock	$	96		$	4		$	100		$	125		$	—	$	125

(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.

EXELON CORPORATION

Reconciliation of Adjusted (non-GAAP) Operating Earnings to

GAAP Consolidated Statements of Operations

(unaudited)

(in millions)


	BGE March 12, 2012 through March 31, 2012
	GAAP (a)			Adjustments			Adjusted Non- GAAP
Operating revenues	$	52		$	113	(b)	$	165

Operating expenses
Purchased power and fuel		68			—			68
Operating and maintenance		60			(30	)(b),(c)		30
Depreciation and amortization		19			—			19
Taxes other than income		9			2	(b)		11

Total operating expenses		156			(28	)		128

Operating income (loss)		(104	)		141			37

Other income and deductions
Interest expense		(8	)		—			(8	)
Other, net		1			—			1

Total other income and deductions		(7	)		—			(7	)

Income (loss) before income taxes		(111	)		141			30

Income taxes		(46	)		57	(b),(c)		11

Net income (loss)		(65	)		84			19

Preference stock dividends		1			—			1

Net income (loss) on common stock	$	(66	)	$	84		$	18

(a)	Results reported in accordance with GAAP.

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

(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.

EXELON CORPORATION

Reconciliation of Adjusted (non-GAAP) Operating Earnings to

GAAP Consolidated Statements of Operations

(unaudited)

(in millions)


	Other (a)
	Three Months Ended March 31, 2012 (b)									Three Months Ended March 31, 2011
	GAAP (c)			Adjustments			Adjusted Non- GAAP			GAAP (c)			Adjustments			Adjusted Non- GAAP
Operating revenues	$	(368	)	$	(11	)(d)	$	(379	)	$	(306	)	$	—		$	(306	)

Operating expenses
Purchased power and fuel		(378	)		—			(378	)		(304	)		—			(304	)
Operating and maintenance		208			(214	)(e),(f)		(6	)		(3	)		—			(3	)
Depreciation and amortization		8			—			8			6			—			6
Taxes other than income		6			—			6			4			—			4

Total operating expenses		(156	)		(214	)		(370	)		(297	)		—			(297	)

Operating loss		(212	)		203			(9	)		(9	)		—			(9	)

Other income and deductions
Interest expense		(20	)		—			(20	)		(17	)		—			(17	)
Other, net		9			—			9			9			—			9

Total other income and deductions		(11	)		—			(11	)		(8	)		—			(8	)

Loss before income taxes		(223	)		203			(20	)		(17	)		—			(17	)

Income taxes		(138	)		130	(d),(e), (f),(g)		(8	)		4			(4	)(h)		—

Net loss	$	(85	)	$	73		$	(12	)	$	(21	)	$	4		$	(17	)

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

(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 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.

(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.

EXELON CORPORATION

Exelon Generation Statistics


	Three Months Ended
	Mar. 31, 2012 (a)		Dec. 31, 2011			Sept. 30, 2011			Jun. 30, 2011			Mar. 31, 2011
Supply (in GWhs)
Nuclear Generation (b)
Mid-Atlantic		12,064		11,587			12,158			11,172			12,370
Midwest		23,198		23,306			23,887			21,995			22,822

Total Nuclear Generation		35,262		34,893			36,045			33,167			35,192
Fossil and Renewables (b)
Mid-Atlantic (b)(d)		1,791		1,637			1,722			2,052			2,162
Midwest		272		188			88			163			157
New England		889		—			2			2			4
New York		—		—			—			—			—
ERCOT (e)		840		457			1,214			207			151
Other (f)		819		394			249			431			358

Total Fossil and Renewables		4,611		2,676			3,275			2,855			2,832
Purchased Power
Mid-Atlantic (c)		2,577		739			702			707			750
Midwest		2,552		1,143			1,756			1,659			1,412
New England		1,100		—			—			—			—
New York (c)		935		—			—			—			—
ERCOT (e)		2,832		1,150			2,928			1,834			1,625
Other (f)		1,769		482			887			577			556

Total Purchased Power		11,765		3,514			6,273			4,777			4,343
Total Supply/Sales by Region (h)
Mid-Atlantic (g)		16,432		13,963			14,582			13,931			15,282
Midwest (g)		26,022		24,637			25,731			23,817			24,391
New England		1,989		—			2			2			4
New York		935		—			—			—			—
ERCOT		3,672		1,607			4,142			2,041			1,776
Other (f)		2,588		876			1,136			1,008			914

Total Supply/Sales by Region		51,638		41,083			45,593			40,799			42,367


	Three Months Ended
	Mar. 31, 2012 (a)		Dec. 31, 2011			Sept. 30, 2011			Jun. 30, 2011			Mar. 31, 2011
Average Margin ($/MWh) (i) (j)
Mid-Atlantic (k)	$	46.86	$	56.29		$	57.32		$	58.92		$	59.92
Midwest (k)		31.40		34.18			33.15			37.28			39.60
New England		19.61		n.m.			n.m.			n.m.			n.m.
New York		8.56		n.m.			n.m.			n.m.			n.m.
ERCOT		9.26		(6.02	)		24.46			(6.52	)		2.54
Other (f)		5.41		(4.13	)		(4.86	)		3.08			(8.81	)

Average Margin—Overall Portfolio	$	32.57	$	39.31		$	39.19		$	41.59		$	44.30
Around-the-clock Market Prices ($/MWh) (l)
PJM West Hub	$	31.10	$	35.07		$	46.17		$	47.27		$	45.82
NiHub		27.13		25.97			37.30			34.94			34.10
New England Mass Hub ATC Spark Spread		0.80		6.70			13.30			7.43			7.49
NYPP Zone A		27.18		32.03			40.89			37.03			37.99
ERCOT North Spark Spread		3.46		1.11			36.70			6.73			8.00

(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 319 GWhs in the Mid-Atlantic and 722 GWhs in New York as a result of the PPA with CENG.

(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 March 31, 2011, 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 1,888 GWhs, 1,235 GWhs, 1,679 GWhs, 1,496 GWhs and 1,333 GWhs for the three months ended March 31, 2012, December 31, 2011, September 30, 2011, June 30, 2011 and March 31, 2011, respectively.

(i)

Excludes Generation’s other business activities not allocated to a region, including retail and wholesale gas, upstream natural gas, proprietary trading, energy efficiency, energy management and demand response, and the design, construction and operation of renewable energy facilities. Also excludes Generation’s compensation under the reliability-must-run rate schedule, the financial results of Brandon Shores, H.A. Wagner, and C.P. Crane, the generating facilities 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.

EXELON CORPORATION

ComEd Statistics


	Three Months Ended March 31, 2012 and 2011
	Electric Deliveries (in GWhs)										Revenue (in millions)
	2012		2011		% Change			Weather- Normal % Change			2012		2011		% Change
Retail Deliveries and Sales (a)
Residential		6,406		6,953		(7.9	)%		(0.6	)%	$	775	$	834		(7.1	)%
Small Commercial & Industrial		7,916		8,074		(2.0	)%		1.1	%		348		382		(8.9	)%
Large Commercial & Industrial		6,703		6,819		(1.7	)%		0.9	%		100		90		11.1	%
Public Authorities & Electric Railroads		325		330		(1.5	)%		4.1	%		12		14		(14.3	)%

Total Retail		21,350		22,176		(3.7	)%		0.5	%		1,235		1,320		(6.4	)%

Other Revenue (b)												153		146		4.8	%

Total Electric Revenue											$	1,388	$	1,466		(5.3	)%

Purchased Power											$	620	$	789		(21.4	)%


							% Change
Heating and Cooling Degree-Days	2012		2011		Normal		From 2011			From Normal
Heating Degree-Days		2,384		3,332		3,164		(28.5	)%		(24.7	)%
Cooling Degree-Days		39		—		—		n/a			n/a


Number of Electric Customers	2012		2011
Residential		3,465,669		3,454,410
Small Commercial & Industrial		365,525		364,585
Large Commercial & Industrial		2,013		1,994
Public Authorities & Electric Railroads		4,790		5,004

Total		3,837,997		3,825,993

(a)

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

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

EXELON CORPORATION

PECO Statistics


	Three Months Ended March 31, 2012 and 2011
	Electric and Gas Deliveries										Revenue (in millions)
	2012		2011		% Change			Weather- Normal % Change			2012		2011		% Change
Electric (in GWhs)
Retail Deliveries and Sales (a)
Residential		3,166		3,590		(11.8	)%		(2.5	)%	$	407	$	493		(17.4	)%
Small Commercial & Industrial		1,951		2,144		(9.0	)%		(4.9	)%		118		169		(30.2	)%
Large Commercial & Industrial		3,637		3,691		(1.5	)%		(1.8	)%		53		108		(50.9	)%
Public Authorities & Electric Railroads		237		242		(2.1	)%		(2.1	)%		8		11		(27.3	)%

Total Retail		8,991		9,667		(7.0	)%		(2.7	)%		586		781		(25.0	)%

Other Revenue (b)												57		63		(9.5	)%

Total Electric Revenue												643		844		(23.8	)%

Gas (in mmcfs)
Retail Deliveries and Sales
Retail Sales (c)		22,427		28,734		(21.9	)%		1.3	%		222		296		(25.0	)%
Transportation and Other		7,766		8,960		(13.3	)%		(11.2	)%		10		13		(23.1	)%

Total Gas		30,193		37,694		(19.9	)%		(1.6	)%		232		309		(24.9	)%

Total Electric and Gas Revenues											$	875	$	1,153		(24.1	)%

Purchased Power and Fuel											$	411	$	633		(35.1	)%


							% Change
Heating and Cooling Degree-Days	2012		2011		Normal		From 2011			From Normal
Heating Degree-Days		1,914		2,506		2,476		(23.6	)%		(22.7	)%
Cooling Degree-Days		4		—		—		n/a			n/a


Number of Electric Customers	2012		2011		Number of Gas Customers	2012		2011
Residential		1,420,734		1,414,103	Residential		452,800		449,398
Small Commercial & Industrial		157,322		156,759	Commercial & Industrial		41,577		41,254

Large Commercial & Industrial		3,109		3,096	Total Retail		494,377		490,652
Public Authorities & Electric Railroads		1,122		1,081	Transportation		888		857

Total		1,582,287		1,575,039	Total		495,265		491,509

(a)

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

(b)	Other revenue includes transmission revenue from PJM and wholesale electric revenues.

(c)

Reflects delivery volumes and revenues from customers purchasing natural gas directly from PECO and customers purchasing natural gas directly from a competitive natural gas supplier as all customers are assessed distribution charges. The cost of natural gas is charged to customers purchasing natural gas from PECO.

EXELON CORPORATION

BGE Statistics


March 12, 2012 through March 31, 2012
	Electric and Gas Deliveries		Revenue (in millions)
Electric (in GWhs)
Retail Deliveries and Sales (a)
Residential		615	$	(13	)
Small Commercial & Industrial		143		12
Large Commercial & Industrial		843		21
Public Authorities & Electric Railroads		25		3

Total Retail		1,626		23

Other Revenues (b)				17

Total Electric Revenue				40

Gas (in mmcfs)
Retail Deliveries and Sales (c)
Retail Sales		4,867		6
Transportation and Other (d)		1,910		6

Total Gas		6,777		12

Total Electric and Gas Revenues			$	52

Purchased Power			$	52
Fuel				16

Total Purchased Power and Fuel			$	68


Heating and Cooling Degree-Days	2012
Heating Degree-Days		1,717


As of March 31, 2012
Number of Electric Customers	2012		Number of Gas Customers	2012
Residential		1,116,201	Residential		610,612
Small Commercial & Industrial		113,177	Commercial & Industrial		44,170

Large Commercial & Industrial		11,492	Total Retail		654,782
Public Authorities & Electric Railroads		298	Transportation		—

Total		1,241,168	Total		654,782

(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 directly from a competitive natural gas supplier as all customers are assessed distribution charges. The cost of natural gas is charged to customers purchasing natural gas from BGE.

(d)	Other gas revenues includes late payment charges and off-system revenue of 1,910 mmcfs ($5M) from March 12, 2012 through March 31, 2012.

EXELON GENERATION CO LLC - FORM 8-K - EX-99.1 - PRESS RELEASE AND EARNINGS RELEASE ATTACHMENTS - May 4, 2012

Attached files