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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

FORM 10-Q

QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF
THE SECURITIES EXCHANGE ACT OF 1934

For The Quarterly Period Ended ~~September 30, 2009~~March 31, 2010


Commission File Number	Exact name of registrant as specified in its charter	IRS Employer Identification No.
1-12869	CONSTELLATION ENERGY GROUP, INC.	52-1964611

100 CONSTELLATION WAY, BALTIMORE, MARYLAND 21202
(Address of principal executive offices) (Zip Code)

410-470-2800
(Registrant's telephone number, including area code)


1-1910		BALTIMORE GAS AND ELECTRIC COMPANY		52-0280210

2 CENTER PLAZA, 110 WEST FAYETTE STREET, BALTIMORE, MARYLAND 21202
(Address of principal executive offices) (Zip Code)

410-234-5000
(Registrant's telephone number, including area code)

MARYLAND
(State of Incorporation of both registrants)

NOT APPLICABLE
(Former name, former address and former fiscal year, if changed since last report)

Indicate by check mark whether the registrants (1) have filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months, and (2) have been subject to such filing requirements for the past 90 days. Yes ý No o

Indicate by check mark whether Constellation Energy Group, Inc. has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes ý No o

Indicate by check mark whether Baltimore Gas and Electric Company has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes o No o

Indicate by check mark whether Constellation Energy Group, Inc. is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company. See definitions of "large accelerated filer," "accelerated filer" and "smaller reporting company" in Rule 12b-2 of the Exchange Act.
~~(Check~~

(Check one):


Large accelerated filerý		Accelerated filero		Non-accelerated filero		Smaller reporting companyo

Indicate by check mark whether Baltimore Gas and Electric Company is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company. See definitions of "large accelerated filer," "accelerated filer" and "smaller reporting company" in Rule 12b-2 of the Exchange Act.
~~(Check~~

(Check one):


Large accelerated filero		Accelerated filero		Non-accelerated filerý		Smaller reporting companyo

Indicate by check mark whether Constellation Energy Group, Inc. is a shell company (as defined in Rule 12b-2 of the Exchange Act) Yes o No ý

Indicate by check mark whether Baltimore Gas and Electric Company is a shell company (as defined in Rule 12b-2 of the Exchange Act) Yes o No ý

Common Stock, without par value ~~200,899,295~~201,681,394 shares outstanding
of Constellation Energy Group, Inc. on ~~October~~April 30, ~~2009.~~2010.

Baltimore Gas and Electric Company meets the conditions set forth in General Instruction H(1)(a) and (b) of Form 10-Q and is therefore filing this form in the reduced disclosure format.

Table of Contents

TABLE OF CONTENTS

			Page

Part I—Financial Information			3
	Item 1—Financial Statements		3
		Constellation Energy Group, Inc. and Subsidiaries
		Consolidated Statements of Income (Loss)	3
		Consolidated Statements of Comprehensive Income ~~(Loss)~~	3
		Consolidated Balance Sheets	4
		Consolidated Statements of Cash Flows	6
		Baltimore Gas and Electric Company and Subsidiaries
		Consolidated Statements of Income ~~(Loss)~~	7
		Consolidated Balance Sheets	8
		Consolidated Statements of Cash Flows	10
		Notes to Consolidated Financial Statements	11
	Item 2—Management's Discussion and Analysis of Financial Condition and Results of Operations		4438
		Introduction and Overview	4438
		Business Environment	4438
		Events of ~~2009~~2010	4539
		Results of Operations	4740
		Financial Condition	6452
		Capital Resources	7055
	Item 3—Quantitative and Qualitative Disclosures About Market Risk		7661
	Items 4 and 4(T)—Controls and Procedures		7661
Part II—Other Information			7762
	Item 1—Legal Proceedings		7762
	Item 2—Issuer Purchases of Equity Securities		7762
	Item 5—Other Information		7863
	Item 6—Exhibits		7964
	Signature		8065

Table of Contents

PART 1—I—FINANCIAL INFORMATION

Item 1—Financial Statements

CONSOLIDATED STATEMENTS OF INCOME (LOSS) (UNAUDITED)

Constellation Energy Group, Inc. and Subsidiaries

		Three Months Ended September 30,						Nine Months Ended September 30,							Three Months Ended March 31,

		2009			2008			2009			2008				2010			2009

		(In millions, except per share amounts)													(In millions, except per share amounts)
Revenues	Revenues													Revenues
	Nonregulated revenues	$	3,161.7		$	4,351.0		$	9,371.3		$	12,187.2		Nonregulated revenues	$	2,518.2		$	3,112.3
	Regulated electric revenues		788.3			822.3			2,250.8			1,980.3		Regulated electric revenues		751.3			806.8
	Regulated gas revenues		77.7			150.3			573.1			724.4		Regulated gas revenues		317.1			384.3

	Total revenues		4,027.7			5,323.6			12,195.2			14,891.9		Total revenues		3,586.6			4,303.4
Expenses	Expenses													Expenses
	Fuel and purchased energy expenses		2,650.4			4,318.0			8,555.2			11,620.5		Fuel and purchased energy expenses		2,362.1			3,273.2
	Operating expenses		587.7			482.9			1,730.6			1,784.5		Fuel and purchased energy expenses from affiliate		198.5			—
	Merger termination and strategic alternatives costs		4.9			39.2			51.2			39.2		Operating expenses		396.4			581.7
	Impairment losses and other costs		7.5			477.1			103.3			477.1		Merger termination and strategic alternatives costs		—			42.3
	Workforce reduction costs		0.4			2.2			11.6			2.2		Impairment losses and other costs		—			28.6
	Depreciation, depletion, and amortization		149.3			134.3			446.8			424.5		Workforce reduction costs		—			10.8
	Accretion of asset retirement obligations		18.5			17.2			54.6			50.8		Depreciation, depletion, and amortization		131.4			148.6
	Taxes other than income taxes		74.4			81.1			224.7			227.0		Accretion of asset retirement obligations		0.5			17.9
														Taxes other than income taxes		66.8			77.9
	Total expenses		3,493.1			5,552.0			11,178.0			14,625.8
Net (loss) gain on divestitures			(0.3	)		—			(464.4	)		91.5
														Total expenses		3,155.7			4,181.0
Equity Investment Losses														Equity Investment Losses		(20.7	)		—
Net Gain (Loss) on Divestitures														Net Gain (Loss) on Divestitures		4.9			(334.5	)

Income (Loss) from Operations	Income (Loss) from Operations		534.3			(228.4	)		552.8			357.6		Income (Loss) from Operations		415.1			(212.1	)
Other Income (Expense)			38.7			(15.8	)		23.3			42.2
Other Expense														Other Expense		(22.3	)		(56.3	)
Fixed Charges	Fixed Charges													Fixed Charges
	Interest expense		129.7			100.0			406.8			252.3		Interest expense		121.5			115.1
	Interest capitalized and allowance for borrowed funds used during construction		(22.5	)		(10.5	)		(65.7	)		(26.2	)	Interest capitalized and allowance for borrowed funds used during construction		(15.6	)		(21.6	)

	Total fixed charges		107.2			89.5			341.1			226.1		Total fixed charges		105.9			93.5

Income (Loss) from Operations Before Income Taxes			465.8			(333.7	)		235.0			173.7
Income (Loss) from Continuing Operations Before Income Taxes														Income (Loss) from Continuing Operations Before Income Taxes		286.9			(361.9	)
Income Tax Expense (Benefit)	Income Tax Expense (Benefit)		298.4			(111.6	)		159.0			71.4		Income Tax Expense (Benefit)		95.6			(242.2	)

Net Income (Loss)	Net Income (Loss)		167.4			(222.1	)		76.0			102.3		Net Income (Loss)		191.3			(119.7	)
Less: Net Income Attributable to Noncontrolling Interests and BGE Preference Stock Dividends			29.8			3.6			53.8			10.8
Less: Net (Loss) Income Attributable to Noncontrolling Interests and BGE Preference Stock Dividends														Less: Net (Loss) Income Attributable to Noncontrolling Interests and BGE Preference Stock Dividends		(0.2	)		3.8

Net Income (Loss) Attributable to Common Stock	Net Income (Loss) Attributable to Common Stock	$	137.6		$	(225.7	)	$	22.2		$	91.5		Net Income (Loss) Attributable to Common Stock	$	191.5		$	(123.5	)

Average Shares of Common Stock Outstanding—Basic	Average Shares of Common Stock Outstanding—Basic		199.6			178.4			199.1			178.3		Average Shares of Common Stock Outstanding—Basic		200.3			198.5
Average Shares of Common Stock Outstanding—Diluted	Average Shares of Common Stock Outstanding—Diluted		200.8			179.5			199.9			180.0		Average Shares of Common Stock Outstanding—Diluted		201.9			198.5

Earnings (Loss) Per Common Share—Basic	Earnings (Loss) Per Common Share—Basic	$	0.69		$	(1.27	)	$	0.11		$	0.51		Earnings (Loss) Per Common Share—Basic	$	0.96		$	(0.62	)

Earnings (Loss) Per Common Share—Diluted	Earnings (Loss) Per Common Share—Diluted	$	0.69		$	(1.27	)	$	0.11		$	0.51		Earnings (Loss) Per Common Share—Diluted	$	0.95		$	(0.62	)

Dividends Declared Per Common Share	Dividends Declared Per Common Share	$	0.24		$	0.4775		$	0.72		$	1.4325		Dividends Declared Per Common Share	$	0.24		$	0.24

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME ~~(LOSS)~~ (UNAUDITED)

Constellation Energy Group, Inc. and Subsidiaries

				Three Months Ended September 30,						Nine Months Ended September 30,									Three Months Ended March 31,

				2009			2008			2009			2008						2010			2009

				(In millions)															(In millions)
Net Income (Loss)	Net Income (Loss)			$	167.4		$	(222.1	)	$	76.0		$	102.3		Net Income (Loss)			$	191.3		$	(119.7	)
	Other comprehensive income (OCI)															Other comprehensive income (OCI)
		Hedging instruments:															Hedging instruments:
			Reclassification of net loss (gain) on hedging instruments from OCI to net (loss) income, net of taxes		358.9			(166.4	)		1,218.3			(88.4	)			Reclassification of net loss on hedging instruments from OCI to net income (loss), net of taxes		108.5			457.2
			Net unrealized loss on hedging instruments, net of taxes		(29.9	)		(1,059.4	)		(414.8	)		(186.0	)			Net unrealized loss on hedging instruments, net of taxes		(232.9	)		(339.2	)
		Available-for-sale securities:															Available-for-sale securities:
			Reclassification of net (gain) loss on sales of securities from OCI to net (loss) income, net of taxes		(2.6	)		8.9			26.9			10.5				Reclassification of net (gain) loss on sales of securities from OCI to net income (loss), net of taxes		(0.1	)		29.7
			Net unrealized gain (loss) on securities, net of taxes		56.7			(79.1	)		75.6			(107.8	)			Net unrealized gain (loss) on securities, net of taxes		0.2			(26.7	)
		Defined benefit obligations:															Defined benefit obligations:
			Amortization of net actuarial loss, prior service cost, and transition obligation included in net periodic benefit cost, net of taxes		7.4			5.4			29.5			15.9				Amortization of net actuarial loss, prior service cost, and transition obligation included in net periodic benefit cost, net of taxes		5.9			7.9
		Net unrealized gain on foreign currency, net of taxes			2.4			0.5			6.9			0.1			Net unrealized gain on foreign currency, net of taxes			1.7			2.0
																	Other comprehensive income—equity investment in CENG, net of taxes			9.9			—
	Comprehensive income (loss)				560.3			(1,512.2	)		1,018.4			(253.4	)		Other comprehensive (loss) income—other equity method investees, net of taxes			(0.2	)		5.7
		Less: Comprehensive income attributable to noncontrolling interests, net of taxes			29.8			3.6			53.8			10.8
																Comprehensive income				84.3			16.9
Comprehensive Income (Loss) Attributable to Common Stock				$	530.5		$	(1,515.8	)	$	964.6		$	(264.2	)
																	Less: Comprehensive (loss) income attributable to noncontrolling interests, net of taxes			(0.2	)		3.8

Comprehensive Income Attributable to Common Stock																Comprehensive Income Attributable to Common Stock			$	84.5		$	13.1

See Notes to Consolidated Financial Statements.
Certain prior-period amounts have been reclassified to conform with the current period's presentation.

Table of Contents

CONSOLIDATED BALANCE SHEETS

Constellation Energy Group, Inc. and Subsidiaries

			*September 30,* 2009*			December 31, 2008					*March 31,* 2010*			December 31, 2009


			(In millions)								(In millions)
Assets	Assets								Assets
									Current Assets
										Cash and cash equivalents	$	1,937.8		$	3,440.0
	Current Assets									Accounts receivable (net of allowance for uncollectibles of$71.9 and $80.4, respectively)		1,913.2			1,778.2
		Cash and cash equivalents	$	742.6		$	202.2			Accounts receivable—consolidated variable interest entities (net of allowance for uncollectibles of$90.4 and $80.2, respectively)		319.3			359.4
		Accounts receivable (net of allowance for uncollectibles of$180.9 and $240.6, respectively)		2,217.1			3,389.9			Fuel stocks		268.3			314.9
		Fuel stocks		303.8			717.9			Materials and supplies		99.9			93.3
		Materials and supplies		224.4			224.5			Derivative assets		686.0			639.1
		Derivative assets		582.8			1,465.0			Unamortized energy contract assets (includes$376.9 and $371.3, respectively, related to CENG)		427.1			436.5
		Unamortized energy contract assets		89.8			81.3			Restricted cash		2.2			2.7
		Restricted cash		48.9			1,030.5			Restricted cash—consolidated variable interest entities		109.8			24.3
		Deferred income taxes		346.0			268.0			Deferred income taxes		172.1			127.9
		Other		264.7			815.5			Other		186.4			244.4

		Total current assets		4,820.1			8,194.8			Total current assets		6,122.1			7,460.7

Investments and Other Noncurrent Assets	Investments and Other Noncurrent Assets								Investments and Other Noncurrent Assets
		Nuclear decommissioning trust funds		1,200.4			1,006.3			Investment in CENG		5,222.4			5,222.9
		Other investments		350.0			421.0			Other investments		414.2			424.3
		Regulatory assets (net)		434.1			494.7			Regulatory assets (net)		399.8			414.4
		Goodwill		25.4			4.6			Goodwill		25.5			25.5
		Derivative assets		917.7			851.8			Derivative assets		731.4			633.9
		Unamortized energy contract assets		212.5			173.1			Unamortized energy contract assets (includes$311.0 and $400.9, respectively, related to CENG)		467.2			604.7
		Other		292.0			421.3			Other		258.3			304.2

		Total investments and other noncurrent assets		3,432.1			3,372.8			Total investments and other noncurrent assets		7,518.8			7,629.9

Property, Plant and Equipment	Property, Plant and Equipment								Property, Plant and Equipment
		Property, plant and equipment		16,148.0			15,285.6			Property, plant and equipment		12,623.7			12,534.5
		Nuclear fuel (net of amortization)		528.4			443.0			Accumulated depreciation		(4,127.5	)		(4,080.7	)
		Accumulated depreciation		(5,222.6	)		(5,012.1	)
										Net property, plant and equipment		8,496.2			8,453.8
		Net property, plant and equipment		11,453.8			10,716.5
									Total Assets		$	22,137.1		$	23,544.4
	Total Assets		$	19,706.0		$	22,284.1

* Unaudited
See Notes to Consolidated Financial Statements.
Certain prior-period amounts have been reclassified to conform with the current period's presentation.

Table of Contents

CONSOLIDATED BALANCE SHEETS

Constellation Energy Group, Inc. and Subsidiaries

September 30,
2009*
December 31,
2008

(In millions)

Liabilities and Equity

Current Liabilities

Short-term borrowings
$ 334.9 $ 855.7

Current portion of long-term debt
1,333.6 2,591.5

Accounts payable and accrued liabilities
1,368.9 2,370.1

Customer deposits and collateral
105.4 120.3

Derivative liabilities
823.1 1,241.8

Unamortized energy contract liabilities
397.4 393.5

Accrued expenses
393.9 373.1

Other
447.7 514.2

Total current liabilities
5,204.9 8,460.2

Deferred Credits and Other Noncurrent Liabilities

Deferred income taxes
1,223.2 677.0

Asset retirement obligations
1,040.8 987.3

Derivative liabilities
964.8 1,115.0

Unamortized energy contract liabilities
682.3 906.4

Defined benefit obligations
1,049.5 1,354.3

Deferred investment tax credits
39.6 44.1

Other
365.8 249.6

Total deferred credits and other noncurrent liabilities
5,366.0 5,333.7

Long-term Debt, Net of Current Portion

4,839.6
5,098.7

Equity

Common shareholders' equity:

Common stock
3,213.0 3,164.5

Retained earnings
2,089.4 2,228.7

Accumulated other comprehensive loss
(1,269.4 ) (2,211.8 )

Total common shareholders' equity
4,033.0 3,181.4

BGE preference stock not subject to mandatory redemption
190.0 190.0

Noncontrolling interests
72.5 20.1

Total equity
4,295.5 3,391.5

Commitments and Contingencies (see Notes)

Total Liabilities and Equity

$
19,706.0
$
22,284.1

				*March 31,* 2010*			December 31, 2009


				(In millions)
Liabilities and Equity
	Current Liabilities
		Short-term borrowings		$	21.1		$	46.0
		Current portion of long-term debt			0.2			0.4
		Current portion of long-term debt—consolidated variable interest entities			56.5			56.5
		Accounts payable and accrued liabilities			996.8			1,019.6
		Accounts payable and accrued liabilities—consolidated variable interest entities			228.5			242.8
		Derivative liabilities			906.7			632.6
		Unamortized energy contract liabilities			299.5			390.1
		Accrued taxes			168.2			877.3
		Accrued expenses			187.7			297.9
		Other			363.3			477.5

		Total current liabilities			3,228.5			4,040.7

	Deferred Credits and Other Noncurrent Liabilities
		Deferred income taxes			3,181.0			3,205.5
		Asset retirement obligations			29.4			29.3
		Derivative liabilities			812.9			674.1
		Unamortized energy contract liabilities			510.0			653.7
		Defined benefit obligations			742.9			743.9
		Deferred investment tax credits			30.9			32.0
		Other			375.3			388.8

		Total deferred credits and other noncurrent liabilities			5,682.4			5,727.3

	Long-term Debt, Net of Current Portion				3,765.8			4,359.6
	Long-term Debt, Net of Current Portion—consolidated variable interest entities				454.4			454.4
	Equity
		Common shareholders' equity:
			Common stock		3,270.8			3,229.6
			Retained earnings		6,591.4			6,461.0
			Accumulated other comprehensive loss		(1,100.5	)		(993.5	)

		Total common shareholders' equity			8,761.7			8,697.1
		BGE preference stock not subject to mandatory redemption			190.0			190.0
		Noncontrolling interests			54.3			75.3

		Total equity			9,006.0			8,962.4

	Commitments, Guarantees, and Contingencies (see Notes)
	Total Liabilities and Equity			$	22,137.1		$	23,544.4

* Unaudited
See Notes to Consolidated Financial Statements.
Certain prior-period amounts have been reclassified to conform with the current period's presentation.

Table of Contents

CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)

Constellation Energy Group, Inc. and Subsidiaries

				(In millions)									(In millions)

Nine Months Ended September 30,				2009			2008
Three Months Ended March 31,										Three Months Ended March 31,			2010			2009

Cash Flows From Operating Activities	Cash Flows From Operating Activities									Cash Flows From Operating Activities
	Net income			$	76.0		$	102.3
	Adjustments to reconcile to net cash provided by operating activities
		Depreciation, depletion, and amortization			446.8			424.5		Net income (loss)			$	191.3		$	(119.7	)
		Amortization of nuclear fuel			102.7			91.2		Adjustments to reconcile to net cash (used in) provided by operating activities
		Amortization of energy contracts			(149.7	)		(193.8	)		Depreciation, depletion, and amortization			131.4			148.6
		All other amortization			93.2			18.2			Amortization of nuclear fuel			—			30.8
		Accretion of asset retirement obligations			54.6			50.8			Amortization of energy contracts and derivatives designated as hedges			17.4			(43.3	)
		Deferred income taxes			(63.8	)		45.0			All other amortization			6.0			35.1
		Investment tax credit adjustments			(4.5	)		(4.8	)		Accretion of asset retirement obligations			0.5			17.9
		Deferred fuel costs			55.4			40.8			Deferred income taxes			(2.4	)		(308.8	)
		Defined benefit obligation expense			83.5			77.2			Investment tax credit adjustments			(1.1	)		(1.5	)
		Defined benefit obligation payments			(361.2	)		(111.4	)		Deferred fuel costs			23.9			16.6
		Workforce reduction costs			11.6			2.2			Defined benefit obligation expense			20.6			30.7
		Impairment losses and other costs			103.3			477.1			Defined benefit obligation payments			(15.5	)		(282.2	)
		Impairment losses on nuclear decommissioning trust assets			62.6			43.6			Workforce reduction costs			—			10.8
		Merger termination and strategic alternatives costs			37.2			—			Impairment losses and other costs			—			28.6
		Loss (gain) on divestitures			464.4			(103.8	)		Impairment losses on nuclear decommissioning trust assets			—			60.5
		Gains on termination of contracts			—			(81.6	)		Merger termination and strategic alternatives costs			—			37.2
		Equity in earnings of affiliates less than dividends received			17.8			1.1			(Gain) loss on divestitures			(4.9	)		334.5
		Derivative contracts classified as financing activities			1,007.0			(37.1	)		Equity in earnings of affiliates less than dividends received			31.3			5.7
		Changes in:									Derivative contracts classified as financing activities			39.1			296.8
			Accounts receivable, excluding margin		754.2			221.2			Changes in:
			Derivative assets and liabilities, excluding collateral		125.0			(935.0	)			Accounts receivable, excluding margin		87.0			219.9
			Net collateral and margin		1,504.8			(568.6	)			Derivative assets and liabilities, excluding collateral		(75.9	)		67.6
			Materials, supplies, and fuel stocks		239.8			(328.5	)			Net collateral and margin		(109.1	)		211.6
			Other current assets		223.9			(134.7	)			Materials, supplies, and fuel stocks		38.2			270.0
			Accounts payable and accrued liabilities		(1,010.9	)		57.2				Other current assets		35.3			240.9
			Liability for uncertain tax expense		96.7			—				Accounts payable and accrued liabilities		(33.0	)		(345.9	)
			Other current liabilities		(47.9	)		(173.8	)			Accrued taxes and other current liabilities		(931.0	)		7.5
		Other			53.1			6.6			Other			(12.5	)		19.9

	Net cash provided by (used in) operating activities				3,975.6			(1,014.1	)	Net cash (used in) provided by operating activities				(563.4	)		989.8

Cash Flows From Investing Activities	Cash Flows From Investing Activities									Cash Flows From Investing Activities
	Investments in property, plant and equipment				(1,243.2	)		(1,360.5	)	Investments in property, plant and equipment				(190.9	)		(392.1	)
	Asset and business acquisitions, net of cash acquired				(20.8	)		(316.5	)	Investments in nuclear decommissioning trust fund securities				—			(135.4	)
	Investments in nuclear decommissioning trust fund securities				(349.5	)		(365.4	)	Proceeds from nuclear decommissioning trust fund securities				—			116.7
	Proceeds from nuclear decommissioning trust fund securities				330.8			346.7		Proceeds from sales of investments and other assets				24.8			31.4
	Proceeds from sales of investments and other assets				81.1			241.2		Contract and portfolio acquisitions				(3.4	)		(866.3	)
	Contract and portfolio acquisitions				(2,153.7	)		—		(Increase) decrease in restricted funds				(66.1	)		979.3
	Repayments of loans receivable				—			26.0		Other				1.5			(0.9	)
	Decrease in restricted funds				979.9			8.3
	Other				(15.8	)		(4.1	)	Net cash used in investing activities				(234.1	)		(267.3	)

	Net cash used in investing activities				(2,391.2	)		(1,424.3	)

Cash Flows From Financing Activities	Cash Flows From Financing Activities									Cash Flows From Financing Activities
	Net (repayment) issuance of short-term borrowings				(520.8	)		1,207.5		Net (repayment) issuance of short-term borrowings				(24.9	)		207.2
	Proceeds from issuance of common stock				24.4			17.6		Proceeds from issuance of common stock				11.0			5.8
	Proceeds from issuance of long-term debt				121.1			2,100.0		Proceeds from issuance of long-term debt				—			109.0
	Repayment of long-term debt				(1,680.6	)		(265.7	)	Repayment of long-term debt				(600.7	)		(1,119.6	)
	Debt issuance costs				(67.8	)		(50.6	)	Debt issuance costs				(4.0	)		(62.7	)
	Common stock dividends paid				(179.6	)		(250.7	)	Common stock dividends paid				(46.3	)		(85.7	)
	Reacquisition of common stock				—			(16.2	)	BGE preference stock dividends paid				(3.3	)		(3.3	)
	BGE preference stock dividends paid				(9.9	)		(9.9	)	Proceeds from contract and portfolio acquisitions				—			863.8
	Proceeds from contract and portfolio acquisitions				2,263.1			—		Derivative contracts classified as financing activities				(39.1	)		(296.8	)
	Derivative contracts classified as financing activities				(1,007.0	)		37.1		Other				2.6			4.3
	Other				13.1			7.4
										Net cash used in financing activities				(704.7	)		(378.0	)
	Net cash (used in) provided by financing activities				(1,044.0	)		2,776.5

Net Increase in Cash and Cash Equivalents					540.4			338.1
Net (Decrease) Increase in Cash and Cash Equivalents										Net (Decrease) Increase in Cash and Cash Equivalents				(1,502.2	)		344.5
Cash and Cash Equivalents at Beginning of Period	Cash and Cash Equivalents at Beginning of Period				202.2			1,095.9		Cash and Cash Equivalents at Beginning of Period				3,440.0			202.2

Cash and Cash Equivalents at End of Period	Cash and Cash Equivalents at End of Period			$	742.6		$	1,434.0		Cash and Cash Equivalents at End of Period			$	1,937.8		$	546.7

See Notes to Consolidated Financial Statements.

Table of Contents

CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED)

Baltimore Gas and Electric Company and Subsidiaries

			Three Months Ended March 31,

			2010			2009

			(In millions)
Revenues
	Electric revenues		$	751.3		$	806.8
	Gas revenues			318.0			386.9

	Total revenues			1,069.3			1,193.7
Expenses
	Operating expenses
		Electricity purchased for resale		349.6			320.9
		Electricity purchased for resale from affiliate		124.0			204.3
		Gas purchased for resale		194.5			258.1
		Operations and maintenance		120.5			105.1
		Operations and maintenance from affiliate		28.5			21.9
	Depreciation and amortization			67.7			66.9
	Taxes other than income taxes			47.6			47.8

	Total expenses			932.4			1,025.0

Income from Operations				136.9			168.7
Other Income				6.5			7.5
Fixed Charges
	Interest expense			34.4			36.7
	Allowance for borrowed funds used during construction			(1.3	)		(1.0	)

	Total fixed charges			33.1			35.7

Income Before Income Taxes				110.3			140.5
Income Taxes				45.9			55.5

Net Income				64.4			85.0
Preference Stock Dividends				3.3			3.3

Net Income Attributable to Common Stock			$	61.1		$	81.7

See Notes to Consolidated Financial Statements.
Certain prior-period amounts have been reclassified to conform with the current period's presentation.

~~Table of Contents~~

~~CONSOLIDATED STATEMENTS OF INCOME (LOSS) (UNAUDITED)~~

~~Baltimore Gas and Electric Company and Subsidiaries~~

Three Months Ended
September 30,
Nine Months Ended
September 30,

2009
2008
2009
2008

(In millions)

Revenues

Electric revenues
$ 788.3 $ 822.4 $ 2,250.8 $ 1,980.5

Gas revenues
78.2 155.5 576.8 740.0

Total revenues
866.5 977.9 2,827.6 2,720.5
Expenses

Operating expenses

Electricity purchased for resale
508.2 556.6 1,435.9 1,416.2

Gas purchased for resale
31.2 107.5 340.9 505.2

Operations and maintenance
142.6 139.5 418.5 409.9

Merger termination and strategic alternatives costs
— 11.1 — 11.1

Depreciation and amortization
61.7 49.5 194.3 171.2

Taxes other than income taxes
44.1 44.1 136.3 130.7

Total expenses
787.8 908.3 2,525.9 2,644.3

Income from Operations
78.7 69.6 301.7 76.2
Other Income
7.0 9.3 21.7 23.5
Fixed Charges

Interest expense
35.9 38.6 108.6 105.6

Allowance for borrowed funds used during construction
(1.1 ) (1.2 ) (3.2 ) (3.3 )

Total fixed charges
34.8 37.4 105.4 102.3

Income (Loss) Before Income Taxes
50.9 41.5 218.0 (2.6 )
Income Taxes
18.6 18.0 84.7 1.9

Net Income (Loss)
32.3 23.5 133.3 (4.5 )
Preference Stock Dividends
3.3 3.3 9.9 9.9

Net Income (Loss) Attributable to Common Stock before Noncontrolling Interests
29.0 20.2 123.4 (14.4 )
Net Income Attributable to Noncontrolling Interests
(0.4 ) (0.3 ) (0.4 ) (0.1 )

Net Income (Loss) Attributable to Common Stock
$ 28.6 $ 19.9 $ 123.0 $ (14.5 )

~~See Notes to Consolidated Financial Statements.~~
~~Certain prior-period amounts have been reclassified to conform with the current period's presentation.~~

Table of Contents

CONSOLIDATED BALANCE SHEETS

Baltimore Gas and Electric Company and Subsidiaries

September 30,
2009*
December 31,
2008

(In millions)

Assets

Current Assets

Cash and cash equivalents
$ 9.2 $ 10.7

Accounts receivable (net of allowance for uncollectibles of$52.0 and $33.3, respectively)
328.1 327.0

Accounts receivable, unbilled (net of allowance for uncollectibles of$0.9 and $0.9, respectively)
156.0 232.3

Investment in cash pool, affiliated company
77.3 148.8

Accounts receivable, affiliated companies
1.7 4.3

Income taxes receivable (net)
187.0 2.4

Fuel stocks
89.1 143.7

Materials and supplies
32.3 38.4

Prepaid taxes other than income taxes
64.2 51.0

Regulatory assets (net)
73.7 79.7

Restricted cash
46.0 23.7

Other
2.3 8.4

Total current assets
1,066.9 1,070.4

Investments and Other Assets

Regulatory assets (net)
434.1 494.7

Receivable, affiliated company
322.5 161.1

Other
117.0 131.6

Total investments and other assets
873.6 787.4

Utility Plant

Plant in service

Electric
4,656.1 4,493.7

Gas
1,243.3 1,221.1

Common
496.7 476.3

Total plant in service
6,396.1 6,191.1

Accumulated depreciation
(2,285.7 ) (2,191.0 )

Net plant in service
4,110.4 4,000.1

Construction work in progress
253.3 225.7

Plant held for future use
2.3 2.6

Net utility plant
4,366.0 4,228.4

Total Assets

$
6,306.5
$
6,086.2

				*March 31,* 2010*			December 31, 2009


				(In millions)
Assets
	Current Assets
		Cash and cash equivalents		$	310.5		$	13.6
		Accounts receivable (net of allowance for uncollectibles of$35.9 and $46.2, respectively)			367.8			311.7
		Accounts receivable, unbilled (net of allowance for uncollectibles of$1.0 and $1.0, respectively)			194.7			252.7
		Investment in cash pool, affiliated company			—			314.7
		Accounts receivable, affiliated companies			1.7			15.4
		Fuel stocks			28.7			73.8
		Materials and supplies			36.4			31.9
		Prepaid taxes other than income taxes			24.5			49.5
		Regulatory assets (net)			45.3			72.5
		Restricted cash—consolidated variable interest entity			48.1			24.3
		Deferred income taxes			—			11.2
		Other			10.0			11.3

		Total current assets			1,067.7			1,182.6

	Investments and Other Assets
		Regulatory assets (net)			399.8			414.4
		Receivable, affiliated company			319.9			326.2
		Other			59.0			98.2

		Total investments and other assets			778.7			838.8

	Utility Plant
		Plant in service
			Electric		4,816.3			4,772.4
			Gas		1,267.9			1,260.6
			Common		496.8			499.0

			Total plant in service		6,581.0			6,532.0
		Accumulated depreciation			(2,343.5	)		(2,318.2	)

		Net plant in service			4,237.5			4,213.8
		Construction work in progress			232.7			215.5
		Plant held for future use			3.7			2.4

		Net utility plant			4,473.9			4,431.7

	Total Assets			$	6,320.3		$	6,453.1

* Unaudited
See Notes to Consolidated Financial Statements.
~~Certain prior-period amounts have been reclassified to conform with the current period's presentation.~~

Table of Contents

CONSOLIDATED BALANCE SHEETS

Baltimore Gas and Electric Company and Subsidiaries

September 30,
2009*
December 31,
2008

(In millions)

Liabilities and Equity

Current Liabilities

Short-term borrowings
$ 334.9 $ 370.0

Current portion of long-term debt
66.5 90.0

Accounts payable and accrued liabilities
124.2 231.0

Accounts payable and accrued liabilities, affiliated companies
76.7 97.0

Customer deposits
74.6 72.3

Current portion of deferred income taxes
31.8 40.2

Accrued taxes
21.6 18.8

Accrued expenses and other
103.9 98.4

Total current liabilities
834.2 1,017.7

Deferred Credits and Other Liabilities

Deferred income taxes
1,074.2 843.3

Payable, affiliated company
244.4 243.2

Deferred investment tax credits
9.8 10.6

Liability for uncertain tax positions
74.8 5.5

Other
22.8 23.1

Total deferred credits and other liabilities
1,426.0 1,125.7

Long-term Debt

Rate stabilization bonds
537.8 564.4

Other long-term debt
1,443.0 1,443.0

6.20% deferrable interest subordinated debentures due October 15, 2043 to wholly owned BGE Capital Trust II relating to trust preferred securities
257.7 257.7

Long-term debt of nonregulated businesses
— 25.0

Unamortized discount and premium
(2.2 ) (2.4 )

Current portion of long-term debt
(66.5 ) (90.0 )

Total long-term debt
2,169.8 2,197.7

Equity

Common shareholder's equity:

Common stock
912.2 912.2

Retained earnings
748.4 625.4

Accumulated other comprehensive income
0.6 0.6

Total common shareholder's equity
1,661.2 1,538.2

Preference stock not subject to mandatory redemption
190.0 190.0

Noncontrolling interest
25.3 16.9

Total equity
1,876.5 1,745.1

Commitments and Contingencies (see Notes)

Total Liabilities and Equity

$
6,306.5
$
6,086.2

			*March 31,* 2010*			December 31, 2009


			(In millions)
Liabilities and Equity
	Current Liabilities
		Short-term borrowings	$	—		$	46.0
		Current portion of long-term debt—consolidated variable interest entity		56.5			56.5
		Accounts payable and accrued liabilities		130.9			166.0
		Accounts payable and accrued liabilities, affiliated companies		80.3			98.3
		Customer deposits		76.9			76.0
		Deferred income taxes		25.6			—
		Accrued taxes		79.6			80.2
		Residential customer rate credit		—			112.4
		Accrued expenses and other		97.7			96.1

		Total current liabilities		547.5			731.5

	Deferred Credits and Other Liabilities
		Deferred income taxes		1,099.5			1,087.6
		Payable, affiliated company		244.1			243.4
		Deferred investment tax credits		9.2			9.5
		Liability for uncertain tax positions		71.4			73.3
		Other		17.2			20.0

		Total deferred credits and other liabilities		1,441.4			1,433.8

	Long-term Debt
		Rate stabilization bonds—consolidated variable interest entity		510.9			510.9
		Other long-term debt		1,431.5			1,431.5
		6.20% deferrable interest subordinated debentures due October 15, 2043 to wholly owned BGE Capital Trust II relating to trust preferred securities		257.7			257.7
		Unamortized discount and premium		(2.1	)		(2.2	)
		Current portion of long-term debt—consolidated variable interest entity		(56.5	)		(56.5	)

		Total long-term debt		2,141.5			2,141.4

	Equity
		Common shareholder's equity		1,999.9			1,938.8
		Preference stock not subject to mandatory redemption		190.0			190.0
		Noncontrolling interest		—			17.6

		Total equity		2,189.9			2,146.4

	Commitments, Guarantees, and Contingencies (see Notes)
	Total Liabilities and Equity		$	6,320.3		$	6,453.1

* Unaudited
See Notes to Consolidated Financial Statements.
~~Certain prior-period amounts have been reclassified to conform with the current period's presentation.~~

Table of Contents

CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)

Baltimore Gas and Electric Company and Subsidiaries

				(In millions)									(In millions)

Nine Months Ended September 30,				2009			2008
Three Months Ended March 31,										Three Months Ended March 31,			2010			2009

Cash Flows From Operating Activities	Cash Flows From Operating Activities									Cash Flows From Operating Activities
	Net income (loss)			$	133.3		$	(4.5	)
	Adjustments to reconcile to net cash provided by operating activities									Net income			$	64.4		$	85.0
		Depreciation and amortization			194.4			171.2		Adjustments to reconcile to net cash provided by operating activities
		Other amortization			6.5			10.2			Depreciation and amortization			67.7			66.9
		Deferred income taxes			289.7			20.5			Other amortization			(0.3	)		0.9
		Investment tax credit adjustments			(0.8	)		(1.0	)		Deferred income taxes			45.6			9.0
		Deferred fuel costs			55.4			40.8			Investment tax credit adjustments			(0.3	)		(0.3	)
		Defined benefit plan expenses			25.7			27.3			Deferred fuel costs			23.9			16.6
		Allowance for equity funds used during construction			(6.1	)		(6.1	)		Defined benefit plan expenses			8.2			9.2
		Changes in:									Allowance for equity funds used during construction			(2.5	)		(2.0	)
			Accounts receivable		75.2			177.1			Changes in
			Accounts receivable, affiliated companies		2.6			1.9				Accounts receivable		0.1			(45.7	)
			Materials, supplies, and fuel stocks		60.7			(73.7	)			Accounts receivable, affiliated companies		13.7			1.3
			Income tax receivable (net)		(184.6	)		(94.4	)			Materials, supplies, and fuel stocks		40.6			113.2
			Other current assets		(7.0	)		(11.6	)			Other current assets		25.8			29.3
			Accounts payable and accrued liabilities		(106.8	)		6.1				Accounts payable and accrued liabilities		(34.5	)		(66.7	)
			Accounts payable and accrued liabilities, affiliated companies		(20.3	)		(51.3	)			Accounts payable and accrued liabilities, affiliated companies		(18.0	)		14.8
			Other current liabilities		(66.9	)		12.2				Other current liabilities		(73.0	)		102.2
			Long-term receivables and payables, affiliated companies		(185.8	)		(44.1	)			Long-term receivables and payables, affiliated companies		(1.2	)		(1.9	)
			Other		38.9			(36.8	)			Other		(38.6	)		16.5

	Net cash provided by operating activities				304.1			143.8		Net cash provided by operating activities				121.6			348.3

Cash Flows From Investing Activities	Cash Flows From Investing Activities									Cash Flows From Investing Activities
	Utility construction expenditures (excluding equity portion of allowance for funds used during construction)				(265.8	)		(319.0	)	Utility construction expenditures (excluding equity portion of allowance for funds used during construction)				(87.2	)		(79.3	)
	Change in cash pool at parent				71.6			15.3		Change in cash pool at parent				314.7			(238.9	)
	Sales of investments and other assets				—			12.9		Proceeds from sales of investments and other assets				20.9			—
	Increase in restricted funds				(22.3	)		(5.4	)	Increase in restricted funds				(23.8	)		(24.5	)

	Net cash used in investing activities				(216.5	)		(296.2	)	Net cash provided by (used in) investing activities				224.6			(342.7	)

Cash Flows From Financing Activities	Cash Flows From Financing Activities									Cash Flows From Financing Activities
	Net (repayment) issuance of short-term borrowings				(35.1	)		189.0		Repayment of short-term borrowings				(46.0	)		—
	Proceeds from issuance of long-term debt				—			400.0		Preference stock dividends paid				(3.3	)		(3.3	)
	Repayment of long-term debt				(51.6	)		(259.5	)
	Debt issuance costs				(0.5	)		(2.5	)	Net cash used in financing activities				(49.3	)		(3.3	)
	Contribution from noncontrolling interest				8.0			—
	Preference stock dividends paid				(9.9	)		(9.9	)
	Distribution to parent				—			(171.7	)

	Net cash (used in) provided by financing activities				(89.1	)		145.4

Net Decrease in Cash and Cash Equivalents					(1.5	)		(7.0	)
Net Increase in Cash and Cash Equivalents										Net Increase in Cash and Cash Equivalents				296.9			2.3
Cash and Cash Equivalents at Beginning of Period	Cash and Cash Equivalents at Beginning of Period				10.7			17.6		Cash and Cash Equivalents at Beginning of Period				13.6			10.7

Cash and Cash Equivalents at End of Period	Cash and Cash Equivalents at End of Period			$	9.2		$	10.6		Cash and Cash Equivalents at End of Period			$	310.5		$	13.0

See Notes to Consolidated Financial Statements.
~~Certain prior-period amounts have been reclassified to conform with the current period's presentation.~~

Table of Contents

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

Basis of Presentation

This Quarterly Report on Form 10-Q is a combined report of Constellation Energy Group, Inc. (Constellation Energy) and Baltimore Gas and Electric Company (BGE). References in this report to "we" and "our" are to Constellation Energy and its subsidiaries, collectively. References in this report to the "regulated business(es)" are to BGE.

Various factors can have a significant impact on our results for interim periods. This means that the results for this quarter are not necessarily indicative of future quarters or full year results given the seasonality of our business.

Our interim financial statements on the previous pages reflect all adjustments that management believes are necessary for the fair statement of the results of operations for the interim periods presented. These adjustments are of a normal recurring nature.

~~We have evaluated events or transactions that occurred after September 30, 2009 for inclusion in these financial statements through November 6, 2009, the date these financial statements were issued.~~

Reclassifications

In accordance with the presentation requirements for ~~the presentation of noncontrolling interests,~~consolidated variable interest entities (VIEs), which ~~were effective~~we adopted on January 1, ~~2009 (see page 41 for more details),~~2010, we have separately ~~presented:~~presented the following material assets and liabilities of these VIEs on our, and/or BGE's, Consolidated Balance Sheets:

•: "~~Net income (loss) attributable to noncontrolling interests" on our, and BGE's, Consolidated Statements of Income (Loss),~~Accounts receivable—consolidated variable interest entities,"
•: "~~Noncontrolling interests" and "BGE Preference Stock Not Subject to Mandatory Redemption" as noncontrolling interests on our Consolidated Balance Sheets,~~Restricted cash—consolidated variable interest entities,"
•: "~~Comprehensive income attributable to noncontrolling interests, net~~Current portion of ~~taxes" in our Statements of Comprehensive Income (Loss),~~long-term debt—consolidated variable interest entities,"
•: "Accounts payable and accrued liabilities—consolidated variable interest entities," and
•: "~~BGE preference stock dividends paid"~~Long-term Debt, Net of Current Portion—consolidated variable interest entities."

We discuss our adoption of the reporting requirements for consolidated variable interest entities below in the ~~financing section of our Consolidated Statements of Cash Flows.~~Variable Interest Entities section.

We have also ~~made the following reclassifications:~~reclassified certain prior-period amounts:

•: We have separately presented ~~"Income taxes receivable (net)" that were previously reported within~~ "Other ~~current assets" on BGE's Consolidated Balance Sheets.~~
•: ~~We have also separately presented "Liability for uncertain tax positions"~~comprehensive income—other equity method investees, net of taxes" that was previously reported within ~~"Other long-term liabilities"~~"Reclassification of net loss on ~~BGE's Consolidated Balance Sheets.~~

~~Investment Agreement with EDF Group~~

~~On December 17, 2008, we entered into an Investment Agreement with EDF Group~~hedging instruments from OCI to net income (loss), net of taxes" and related entities (EDF) under which EDF will purchase from us a 49.99% membership interest in our nuclear generation and operation business for $4.5 billion (subject to certain adjustments). We discuss the Investment Agreement with EDF in more detail in~~Note 15~~"Net unrealized gain (loss) on hedging instruments, net of ~~our 2008 Annual Report on Form 10-K.~~

~~In October 2009, the Maryland PSC issued an order approving our transaction with EDF subject to the following conditions:~~

•: Constellation Energy is to fund a one-time per customer distribution rate credit for BGE residential customers, before the end of March 2010, totaling $110.5 million, for which we will record a liability upon closing.
•: ~~Constellation Energy will make a $250 million cash capital contribution to BGE by no later than June 30, 2010.~~
•: BGE will not pay dividends to Constellation Energy if (a) after the dividend payment, BGE's equity ratio would be below 48% or (b) BGE's senior unsecured credit rating is rated by two of the three major credit rating agencies below investment grade.
•: BGE may file an electric distribution rate case at any time beginning in January 2010 and may not file a subsequent electric distribution rate case until January 2011. Any rate increase in the first electric distribution rate case will be capped at 5% as agreed to by Constellation Energy in its 2008 settlement with the Maryland PSC. The timing of any gas distribution rate filing will also occur no earlier than the electric cases.
•: ~~Constellation Energy will be limited to allocating no more than 31% of its holding company costs to BGE until the Maryland PSC reviews cost allocation in the context of BGE's next rate case.~~
•: Upon closing the EDF transaction, Constellation Energy and BGE will begin to implement "ring fencing" measures to ensure the bankruptcy protection and credit rating separation of BGE from Constellation Energy including the formation of a new special purpose subsidiary by Constellation Energy to hold all of the common equity interests in BGE. Timing for implementation of these measures will be proposed at a Maryland PSC hearing in December 2009.

~~With the receipt of the Maryland PSC's order, Constellation Energy and EDF are proceeding with closing this transaction. Upon closing of the transaction, we will~~

~~Table of Contents~~

sell a 49.99% membership interest in Constellation Energy Nuclear Group LLC and its affiliates (CENG), our nuclear generation and operation business, to EDF for total consideration of approximately $4.7 billion (includes $4.5 billion at close and expense reimbursements). As a result, we will cease to have a controlling financial interest in CENG and will deconsolidate CENG in the fourth quarter of 2009. The following summarizes the estimated impact of this transaction upon closing:

•: We receive total cash consideration of approximately $3.5 billion and redeem the $1.0 billion of the Series B Preferred Stock held by EDF as additional purchase price resulting in net proceeds of approximately $2.2 billion after the payment of taxes.
•: ~~We remove the individual assets and liabilities of CENG from our balance sheet with a net asset value of approximately $2.6 billion.~~
•: ~~We record our retained investment in CENG at its estimated fair value of approximately $4.7 billion.~~
•: ~~We recognize a pre-tax gain on sale of approximately $6.8 billion, calculated as follows:~~

(In billions)

Fair value of the consideration received from EDF
$ 4.7
Estimated fair value of our retained interest in CENG
4.7
Carrying amount of CENG's assets and liabilities prior to deconsolidation
(2.6 )

Estimated pre-tax gain
$ 6.8

Upon closing, we will account for our retained investment in CENG using the equity method and report our share of its earnings in the merchant energy segment. As a result, we will no longer record the individual income statement line items, but instead will record our share of the investment's earnings in a single line in our Consolidated Statements of Income (Loss).

Immediately prior to the closing of the sale, we will execute a power purchase agreement (PPA) with CENG with a fair value of approximately $0.7 billion. We will report the PPA on our Consolidated Balance Sheets within "Unamortized energy contract assets" and amortize its valuetaxes" on our Consolidated Statements of Comprehensive Income (Loss) ~~to "Fuel~~.

•

We have separately presented "Electricity purchased for resale from affiliate" that was previously reported within "Electricity purchased for resale" on BGE's Consolidated Statements of Income.

•

We have separately presented "Operations and ~~purchased energy expense" over a period~~maintenance from affiliate" that was previously reported within "Operations and maintenance" on BGE's Consolidated Statements of ~~approximately two years.~~

~~In addition, the completion of the transaction with EDF will impact our credit facilities as discussed in the~~~~Financing~~ ~~section beginning on page 21.~~

~~Merger Termination and Strategic Alternatives Costs~~

We incurred costs during the quarter ended September 30, 2009 primarily related to the transactions related to EDF, and other strategic alternatives costs. For the nine months ended September 30, 2009, we incurred costs related to the terminated merger agreement with MidAmerican Energy Holdings Company (MidAmerican), the conversion of our Series A Preferred Stock, the transactions related to EDF, and other strategic alternatives costs. These costs totaled $4.9 million pre-tax and $51.2 million pre-tax for the quarter and nine months ended September 30, 2009, respectively, and primarily relate to the first quarter of 2009 write-off of the unamortized debt discount associated with the 14% Senior Notes (Senior Notes) that were repaid in full to MidAmerican in January 2009.

Income.

Variable Interest Entities

Effective January 1, 2010, we adopted new accounting, presentation, and disclosure requirements related to VIEs. As a result of ~~September 30, 2009, we~~our assessment and implementation of the new requirements, our accounting and disclosures related to VIEs were impacted as follows:

•: We have presented separately on our Consolidated Balance Sheets, to the extent material, the assets of our consolidated VIEs that can only be used to settle specific obligations of the consolidated VIE, and the liabilities of our consolidated VIEs for which creditors do not have recourse to our general credit.
•: The new requirements emphasize a qualitative assessment of whether the equity holders of the entity have the power to direct matters that most significantly impact the entity. We have evaluated all existing entities under the new VIE accounting requirements, both those previously considered VIEs and those considered potential VIEs. Our accounting for and disclosure about VIEs did not change materially as a result of these assessments.

We consolidate three ~~variable interest entities (VIE) in~~VIEs for which we ~~were~~are the primary beneficiary, and we ~~had~~have significant interests in six VIEs for which we ~~did~~do not have controlling financial interests and, accordingly, ~~were~~are not the primary beneficiary. ~~We discuss our VIEs in more detail in~~~~Note 4~~ ~~of our 2008 Annual Report on Form 10-K.~~

Consolidated Variable Interest Entities

In 2007, BGE formed RSB BondCo LLC (BondCo), a special purpose bankruptcy-remote limited liability company, to acquire and hold rate stabilization property and to issue and service bonds secured by the rate stabilization property. In June 2007, BondCo purchased rate stabilization property from BGE, including the right to assess, collect, and receive non-bypassable rate stabilization charges payable by all residential electric customers of BGE. These charges are being assessed in order to recover previously incurred power purchase costs that BGE deferred pursuant to Maryland Senate Bill 1. ~~We discuss Senate Bill 1 in more detail in~~~~Management's Discussion and Analysis~~ ~~section of our 2008 Annual Report on Form 10-K.~~

BGE determined that BondCo is a VIE for which it is the primary beneficiary. As a result, BGE, and we, consolidated BondCo.

The BondCo assets are restricted and can only be used to settle the obligations of BondCo. Further, BGE is required to remit all payments it receives from customers for rate stabilization charges to BondCo. During the quarter ~~and nine months~~ ended ~~September 30, 2009,~~March 31, 2010, BGE remitted ~~$23.0~~$23.8 million ~~and $65.1 million, respectively,~~ to BondCo.

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BGE did not provide any additional financial support to BondCo during the quarter ~~and nine months~~ ended

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~~September 30, 2009.~~ March 31, 2010. Further, BGE does not have any contractual commitments or obligations to provide additional financial support to BondCo unless additional rate stabilization bonds are issued. The BondCo creditors do not have any recourse to the general credit of BGE in the event the rate stabilization charges are not sufficient to cover the bond principal and interest payments of BondCo.

During ~~the second quarter of~~ 2009, our retail gas ~~customer supply~~ operation formed two new entities and combined them with our existing retail gas ~~customer supply~~ operation into a retail gas entity group for the purpose of entering into a collateralized gas supply agreement ~~(GSA)~~ with a third party gas supplier. While we own 100% of these entities, we determined that the retail gas entity group is a VIE because there is not sufficient equity to fund the group's activities without the additional credit support we provide in the form of a letter of credit and a parental guarantee. We are the primary beneficiary of the retail gas entity group; accordingly, we consolidate the retail gas entity group as a VIE, including the existing retail gas customer supply operation, which we formerly consolidated as a voting interest entity.

The gas supply arrangement is collateralized as follows:

•: The assets of the retail gas entity group must be used to settle obligations under the third party gas supply agreement before it can make any distributions to us,
•: The third party gas supplier has a collateral interest in all of the assets and equity of the retail gas entity group, and
•: ~~We currently have~~As of March 31, 2010, we provided a $100 million parental guarantee and a ~~$100~~$49 million letter of credit to the third party gas supplier in support of the retail gas entity group.

Other than credit support provided by the parental guarantee and the letter of credit, we do not have any contractual or other obligations to provide additional financial support to the retail gas entity group. The retail gas entity group creditors do not have any recourse to our general credit. Finally, we did not provide any financial support to the retail gas entity group during the first quarter ~~and nine months ended September 30, 2009,~~of 2010, other than the ~~equity contributions,~~ parental guarantee and the letter of credit.

We also consolidate a retail power supply VIE for which we became the primary beneficiary in 2008 as a result of a modification to its contractual arrangements that changed the allocation of the economic risks and rewards of the VIE among the variable interest holders. The consolidation of this VIE did not have a material impact on our financial results or financial condition.

The carrying amounts and classification of the above three consolidated VIEs' assets and liabilities included in our consolidated financial statements at ~~September 30, 2009~~March 31, 2010 are as follows:

			(In millions)

	(In millions)
Current assets	$	605.0	$	662.2
Noncurrent assets		317.1		43.9

Total Assets	$	922.1	$	706.1

Current liabilities	$	540.1	$	414.2
Noncurrent liabilities		686.6		431.6

Total Liabilities	$	1,226.7	$	845.8

All of the assets in the table above are restricted for settlement of the VIE obligations and all of the liabilities in the table above can only be settled using VIE resources.

Unconsolidated Variable Interest Entities

As of ~~September 30, 2009,~~March 31, 2010, we had significant interests in six VIEs for which we were not the primary beneficiary. WeOther than the obligations listed in the table below, we have not provided any material financial or other support to these entities during the quarter ended March 31, 2010 and ~~nine months ended September 30, 2009.~~we do not intend to provide any additional financial or other support to these entities in the future.

~~We describe the~~The nature of these entities and our involvement with them are described in the following table:

VIE Category	Nature of Entity Financing	Nature of Constellation Energy Involvement	Obligations or Requirement to Provide Financial Support	Date of Involvement


Power contract monetization entities (2 entities)	Combination of debt and equity financing	Power sale agreements, loans, and guarantees	$~~37.7~~33.0 million in letters of credit	March 2005
Power projects and fuel supply entities (4 entities)	Combination of debt and equity financing	Equity investments and guarantees	$~~2.0~~5.0 million debt guarantee and working capital funding	Prior to 2003

For purposes of aggregating the various VIEs for disclosure, we evaluated the risk and reward characteristics for, and the significance of, each VIE. We discuss the nature of our involvement with the power contract monetization VIEs in detail inNote 4 of our ~~2008~~2009 Annual Report on Form 10-K.

We concluded that power over the most economically significant activities of two of the power project VIEs is shared equally among the equity holders. Accordingly, neither of the equity holders consolidate these VIEs. The equity holders own 50% interests in these VIEs and all of

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the significant decisions require the mutual consent of the equity holders.

The following is summary information available as of ~~September 30, 2009~~March 31, 2010 about these entities:

		Power Contract Monetization VIEs		All Other VIEs		Total			Power Contract Monetization VIEs		All Other VIEs		Total


		(In millions)							(In millions)
Total assets	Total assets	$	571.3	$	316.8	$	888.1	Total assets	$	566.6	$	344.6	$	911.2
Total liabilities	Total liabilities		463.4		72.2		535.6	Total liabilities		458.7		114.3		573.0
Our ownership interest	Our ownership interest		—		58.8		58.8	Our ownership interest		—		59.4		59.4
Other ownership interests	Other ownership interests		107.9		185.8		293.7	Other ownership interests		107.9		170.9		278.8
Our maximum exposure to loss	Our maximum exposure to loss		37.7		60.8		98.5	Our maximum exposure to loss		33.0		65.4		98.4
Carrying amount and location of variable interest on balance sheet:	Carrying amount and location of variable interest on balance sheet:							Carrying amount and location of variable interest on balance sheet:
	-Other investments		—		58.8		58.8	-Other investments		—		60.4		60.4

Our maximum exposure to loss is the loss that we would incur in the unlikely event that our interests in all of these entities were to become worthless and we were required to fund the full amount of all ~~guarantees~~obligations associated with these entities. Our maximum exposure to loss as of ~~September 30, 2009~~March 31, 2010 consists of the following:

•: ~~outstanding receivables, loans, and letters of credit totaling $37.7 million,~~
•: the carrying amount of our investment totaling ~~$58.8~~$60.4 million, and
•: debt and payment guarantees totaling ~~$2.0~~$38.0 million.

We assess the risk of a loss equal to our maximum exposure to be remote and, accordingly have not recognized a liability associated with any portion of the maximum exposure to loss. In addition, there are no agreements with, or commitments by, third parties that would affect the fair value or risk of our variable interests in these ~~variable interest entities.~~

~~Impairment Losses and Other Costs~~

~~Available for Sale Securities~~

We evaluated for impairment certain of our investments in equity securities during the nine months ended September 30, 2009. The investments we evaluated included our nuclear decommissioning trust fund assets and other marketable securities. We record an impairment charge if an investment has experienced a decline in fair value to a level less than its carrying value and the decline is "other than temporary."

In making this determination, we evaluate the reasons for an investment's decline in value, the extent and duration of that decline, and factors that indicate whether and when the value will recover. For securities held in our nuclear decommissioning trust fund for which the market value is below book value, the decline in fair value is considered other than temporary and we write them down to fair value. We discuss our impairment policy for our nuclear decommissioning trust fund assets and other marketable securities in more detail in~~Note 1~~ ~~to our 2008 Annual Report on Form 10-K.~~

The fair values of certain of our marketable securities and certain of the securities held in our nuclear decommissioning trust fund declined below book value. As a result, we recorded a $0.2 million pre-tax impairment charge for the quarter ended September 30, 2009 and a $62.6 million pre-tax impairment charge for the nine months ended September 30, 2009 for our nuclear decommissioning trust fund assets in the "Other income (expense)" line in our Consolidated Statements of Income (Loss). In addition, we recorded all other changes in the fair value of our nuclear decommissioning trust fund assets that are not impaired in other comprehensive (loss) income. We also recorded an impairment charge of $0.5 million for other marketable securities during the nine months ended September 30, 2009.

The estimates we utilize in evaluating impairment of our available for sale securities require judgment and the evaluation of economic and other factors that are subject to variation, and the impact of such variations could be material.

~~Equity Method Investments~~

~~Shipping Joint Venture~~

We record an impairment if an equity method investment has experienced a decline in fair value to a level less than our carrying value and the decline is "other than temporary." During the quarter ended June 30, 2009, we contemplated several potential courses of action together with our partner relating to the strategic direction of our shipping joint venture and our continuing involvement. This led to a decision to explore a plan to sell our 50% interest to a party related to our joint venture partner for negligible proceeds. During July 2009, a definitive purchase and sale agreement was executed between the parties and the transaction closed in the third quarter of 2009. We have no further involvement in the activities of the joint venture.

As a result of the events that occurred during the second quarter of 2009, we concluded that the fair value of our investment had declined to a level below the carrying value at June 30, 2009 and that this decline was "other than temporary." As such, we recorded a pre-tax impairment charge at June 30, 2009 of $59.0 million associated with our equity investment in our shipping joint

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venture within the "Impairment losses and other costs" line in our Consolidated Statements of Income (Loss), and reported the charge in our merchant energy business results for the second quarter of 2009.

~~Constellation Energy Partners LLC~~

As of March 31, 2009, the fair value of our investment in Constellation Energy Partners LLC (CEP) based upon its closing unit price was $10.0 million, which was lower than its carrying value of $24.0 million.

~~The decline in fair value of our investment in CEP reflected a number of other factors, including:~~

•: ~~continuing difficulties in the financial and credit markets in the United States,~~
•: ~~decreases in the market price of natural gas and oil,~~
•: ~~the effect of these factors on market perceptions of gas exploration and production master limited partnerships, and~~
•: ~~factors related to Constellation Energy's financial condition and possible sale of its investment in CEP.~~

As a result of evaluating these factors, we determined that the decline in the value of our investment was other than temporary. Therefore, we recorded a $14.0 million pre-tax impairment charge at March 31, 2009 to write-down our investment to fair value. We recorded this charge in "Impairment losses and other costs" in our Consolidated Statements of Income (Loss). We did not record an impairment charge in the second or third quarters of 2009.

~~Other Costs~~

During the quarter and nine months ended September 30, 2009, we recorded $7.5 million and $29.8 million pre-tax charges, respectively, in the "Impairment losses and other costs" line in our Consolidated Statements of Income (Loss) primarily related to:

•: ~~divested operations—long-lived assets no longer used and lease terminations, and~~
•: ~~the write-off of an uncollectible advance to an affiliate.~~

~~Workforce Reduction Costs~~

We incurred workforce reduction costs during the fourth quarter of 2008, primarily related to workforce reduction efforts across all of our operations (Q4 2008 Program), and during the first quarter of 2009, primarily related to the divestiture of a majority of our international commodities operation as well as some smaller restructurings elsewhere in our organization (Q1 2009 Program). For the Q1 2009 Program, we recognized an $11.6 million pre-tax charge during the nine months ended September 30, 2009 related to the elimination of approximately 180 positions. We expect both of these restructurings will be completed within 12 months of their initiation. The following table summarizes the status of the involuntary severance liabilities at September 30, 2009:

Q1 2009
Program
Q4 2008
Program

Initial severance liability balance
$ 10.8 $ 19.7
Additional expense recorded in the second quarter of 2009
0.4 —
Additional expense recorded in the third quarter of 2009
0.4 —
Amounts recorded as pension and postretirement liabilities
— (3.0 )

Net cash severance liability
11.6 16.7
Cash severance payments
(11.4 ) (12.5 )

Severance liability balance at September 30, 2009
$ 0.2 $ 4.2

~~We discuss our 2008 workforce reduction costs in more detail in~~~~Note 2~~ ~~of our 2008 Annual Report on Form 10-K.~~VIEs.

Earnings Per Share

Basic earnings per common share (EPS) is computed by dividing net income (loss) attributable to common stock by the weighted-average number of common shares outstanding for the period. Diluted EPS reflects the potential dilution of common stock equivalent shares that could occur if securities or other contracts to issue common stock were exercised or converted into common stock.

Our dilutive common stock equivalent shares consist of stock options and other stock-based compensation awards. The following table presents stock options that were not dilutive and were excluded from the computation of diluted EPS in each period, as well as the dilutive common stock equivalent shares:

	Quarter Ended September 30,				Nine Months Ended September 30,				Quarter Ended March 31,

	2009		2008		2009		2008		2010		2009

	(In millions)								(In millions)
Non-dilutive stock options		4.7		2.6		5.2		1.5		4.9		5.5
Dilutive common stock equivalent shares		1.2		1.1		0.8		1.7		1.6		0.4

As a result of the Company incurring a loss for the ~~three months~~quarter ended ~~September 30, 2008,~~March 31, 2009, dilutive common stock equivalent shares were not included in calculating diluted ~~EPS.~~EPS for that reporting period.

Acquisitions

Criterion Wind Project

In April 2010, we completed the acquisition of the Criterion wind project in Garrett County, Maryland. The completed cost of this project is expected to be approximately $140 million. This 70 MW wind energy project will be developed, constructed, owned, and operated by us. We expect this facility to be in commercial operation by the end of 2010.

Texas Combined Cycle Generation Facilities

In April 2010, we signed an agreement to purchase the 550 MW Colorado Bend Energy Center and the 550 MW Quail Run Energy Center natural gas combined cycle generation facilities in Texas for $365 million, subject to normal closing adjustments. The transaction is expected to close in the second quarter of 2010, subject to certain state and federal regulatory approvals.

Divestiture

In January 2010, BGE completed the sale of its interest in a nonregulated subsidiary that owns a district chilled water facility to a third party. BGE received net cash proceeds of $20.9 million. No gain or loss was recorded on this transaction in 2010. BGE has no further involvement in the activities of this entity.

Investment in Constellation Energy Nuclear Group, LLC (CENG)

On November 6, 2009, we completed the sale of a 49.99% membership interest in CENG, our nuclear generation and operation business, to EDF Group and affiliates (EDF). As a result of this transaction, we retained a 50.01% economic interest in CENG, but we and EDF have equal voting rights over the activities of CENG. Accordingly, we deconsolidated CENG and began to record our investment

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~~We issued to MidAmerican 19,897,322 shares~~in CENG under the equity method of ~~Constellation Energy's common stock upon~~accounting. For the ~~conversion~~quarter ended March 31, 2010, we recorded $19.2 million of equity investment losses in CENG, which represents our share of earnings from CENG of $23.4 million, net of the ~~Series A Preferred Stock, which occurred upon the termination~~amortization of the ~~merger agreement with MidAmerican on December 17, 2008. We discuss~~basis difference in CENG of $42.6 million. Our equity investment earnings in CENG include $1.2 million of expense related to the ~~conversion feature~~portion of the ~~Series A Preferred Stock~~cost of certain share-based awards that we fund on behalf of EDF. The basis difference is the difference between the fair value of our investment in ~~more detail~~CENG at closing and our share of the underlying equity in CENG, because the underlying assets of CENG were retained at their carrying value. SeeNote 92 ofto our ~~2008~~2009 Annual Report on Form ~~10-K. These additional shares impacted our earnings per share~~10-K for a more detailed discussion.

Summarized income statement information for CENG for the quarter ~~and nine months~~ ended ~~September 30, 2009.~~

~~Accretion of Asset Retirement Obligations~~

~~We discuss our asset retirement obligations in more detail in~~~~Note 1~~ ~~of our 2008 Annual Report on Form 10-K. The change in our "Asset retirement obligations" liability during 2009 was as follows:~~

(In millions)

Liability at January 1, 2009
$ 987.3
Accretion expense
54.6
Liabilities incurred
0.1
Liabilities settled
(0.7 )
Revisions to cash flows
(0.4 )
Other
(0.1 )

Liability at September 30, 2009
$ 1,040.8

~~Acquisition~~

~~CLT Efficient Technologies Group~~

On July 1, 2009, we acquired CLT Efficient Technologies Group (CLT). We include CLT as part of our other nonregulated businesses and have reported its results of operations in our consolidated financial statements since the date of acquisition. CLTMarch 31, 2010 is ~~an energy services company that provides energy performance contracting and energy efficiency engineering services.~~

~~We acquired 100% ownership of CLT for $21.8 million, including direct costs, of which $20.8 million was paid in cash at closing.~~

~~The total consideration was allocated to the net assets acquired~~ as follows:

At July 1, 2009

(In millions)

Current assets
$ 5.7
Goodwill¹
18.5
Other assets
2.3

Total assets acquired
26.5

Current liabilities
(4.7 )

Net assets acquired
$ 21.8

~~1 Goodwill is 100% deductible for tax purposes.~~

~~Our initial purchase price allocation is based on preliminary estimates, and the purchase price is subject to adjustments, which could impact our purchase price allocation.~~

~~The pro-forma impact of the CLT acquisition would not have been material to our results of operations for the quarter and nine months ended September 30, 2009 and 2008.~~

~~Divestitures~~

~~In 2009, we continued to implement many of the strategic initiatives we identified in 2008 to improve liquidity and reduce our business risk. We discuss these initiatives in the~~~~Strategy~~ ~~section of our 2008 Annual Report on Form 10-K.~~

~~The transactions to sell a majority of our international commodities, our Houston-based gas trading and other operations were structured in two parts:~~

•: ~~the assignment and transfer of a majority of the portfolio, and~~
•: ~~the execution of a Total Return Swap (TRS) mechanism for the remainder of the portfolio.~~

Under the TRS, we entered into offsetting trades with the buyers that matched the terms of the remaining third party contracts for which we were unable to complete assignment to the buyers as of the transaction dates. This structure transferred the risks associated with changes in commodity prices as of the transaction dates to the buyers in all instances. However, the trades under the TRS are newly executed transactions, and we remain the principal under both the unassigned third party trades and the matching trades with the buyers under the TRS with no right of either financial or legal offset. We continue to pursue the assignment of these remaining contracts to the buyers.

The matching contracts under the TRS include both derivatives and non-derivatives and were executed at prices that differed from market prices at closing, which resulted in a net cash payment to/from the buyers. We recorded the underlying contracts at fair value on a gross basis as assets or liabilities in our Consolidated Balance Sheets depending on whether the contract prices were above- or below-market prices at closing. As a result, the derivative contracts have been included in "Derivative Assets and Liabilities" and the nonderivative contracts have been included in "Unamortized Energy Contract Assets and Liabilities." The derivative contracts are subject to mark-to-market accounting until they are realized or assigned. The nonderivative contracts will be amortized into earnings as the underlying contracts are realized, or sooner if those contracts are assigned.

~~We record the cash proceeds we pay or receive at the inception of energy purchase and sale contracts based upon~~

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~~whether the contracts are in-the-money or out-of-the-money as follows:~~



~~In-the-money contracts—proceeds paid~~		~~Investing Outflow~~
~~Out-of-the-money contracts—proceeds received~~		~~Financing Inflow~~

After inception, we record the cash flows from all energy purchase and sale contracts as operating activities, except for out-of-the-money derivative contracts that were liabilities at inception. We record the ongoing cash flows from these out-of-the-money derivative contracts as financing activities, regardless of whether they are purchase or sale contracts.

~~International Commodities Operation~~

In January 2009, we entered into a definitive agreement to sell a majority of our international commodities operation. We completed this transaction on March 23, 2009 and recognized the following impacts during the nine months ended September 30, 2009:

•: ~~a pre-tax loss of approximately $334.5 million representing net consideration paid to the buyer, the book value of net assets sold, and transaction costs,~~
•: a reclassification of $165.7 million in losses on previously designated cash-flow hedge contracts, for which the forecasted transactions are now deemed probable of not occurring, from "Accumulated Other Comprehensive Loss" to "Nonregulated revenues" in the Consolidated Statements of Income (Loss),
•: ~~workforce reduction costs of $10.2 million, recorded as part of "Workforce reduction costs" in the Consolidated Statements of Income (Loss), and~~
•: other costs of $17.6 million related to leasehold improvements, furniture and computer hardware and software, recorded as part of "Impairment losses and other costs" in the Consolidated Statements of Income (Loss).

We removed the contracts that were assigned from our Consolidated Balance Sheet, paid the buyer approximately $90 million, and reflected the impact of this payment on our working capital in the operating activities section of our Consolidated Statements of Cash Flows.

The net cash payment to the buyer upon completion of the TRS was $2.5 million. As part of the consideration, we acquired matching nonderivative contracts that resulted in a net liability of approximately $75 million, which will be amortized into earnings as the underlying contracts are realized, or sooner if the original nonderivative contracts are assigned.

~~We have reflected the contracts under the TRS on a gross basis in cash flows from investing and financing activities in our Consolidated Statements of Cash Flows as follows:~~

Nine Months Ended September 30, 2009

(In millions)

Investing activities—Contract and portfolio acquisitions
$ (866.3 )
Financing activities—Proceeds from contract and portfolio acquisitions
863.8

Net cash flows from contract and portfolio acquisitions
$ (2.5 )

In addition to the March 23, 2009 transaction for a majority of our international commodities operation, on June 30, 2009 we completed the sale of a uranium market participant that we owned. We received cash proceeds of approximately $43 million and recorded a $27.2 million loss on this sale. This loss from our merchant energy segment is included in the "Net (loss) gain on divestitures" line in our Consolidated Statements of Income (Loss) for the nine months ended September 30, 2009.

~~Houston-Based Gas and Other Trading Operations~~

On February 3, 2009, we entered into a definitive agreement to sell our Houston-based gas trading operation. We transferred control of this operation on April 1, 2009. In addition, in the second quarter of 2009 we also sold certain other trading operations. In total, we received proceeds of approximately $61 million, and recorded a $102.7 million net loss on these sales in the nine months ended September 30, 2009. The net loss on sale primarily relates to nonderivative accrual contracts, which were not recorded on our Consolidated Balance Sheet, the cost associated with disposing of an entire portfolio and not merely individual contracts, and the cost of capital, including contingent capital, to support the operation.

The matching derivative and nonderivative transactions under the TRS discussed above were executed at prices that differed from market prices at closing. As a result, we record the ongoing cash flows related to the out-of-the-money derivative contracts that were liabilities at inception as financing cash flows. This resulted in cash outflows related to financing activities of $818.7 million in our Consolidated Statements of Cash Flows for the nine months ended September 30, 2009 associated with derivative liabilities that were out-of-the-money.

~~The net cash receipt from the buyers upon completion of the TRS was $91.9 million in the second quarter of 2009. We have reflected these contracts on a gross basis in~~

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~~cash flows from investing and financing activities in our Consolidated Statements of Cash Flows as follows:~~

Nine Months Ended September 30, 2009

(In millions)

Investing activities—Contract and portfolio acquisitions
$ (1,287.4 )
Financing activities—Proceeds from contract and portfolio acquisitions
1,379.3

Net cash flows from contract and portfolio acquisitions
$ 91.9

In addition, we incurred other costs of $5.5 million for the nine months ended September 30, 2009, respectively, related to leasehold improvements, furniture, computer hardware and software costs, which are recorded as part of "Impairment losses and other costs" on our Consolidated Statements of Income (Loss).

On April 1, 2009, we executed an agreement with the buyer of our Houston-based gas trading operation under which the buyer will provide us with the gas supply needed to support our retail gas customer supply business through March 31, 2011. This agreement was structured such that our requirements to post collateral are reduced. The supplier has liens on the assets of the retail gas supply business as well as our investment in the stock of these entities to secure our obligations under the gas supply agreement. In connection with this agreement, we posted approximately $160 million of collateral. This was subsequently reduced to $100 million. The initial $160 million posted represents approximately 25 percent of the previous collateral requirements to support this operation. We discuss the impact of the gas supply agreement on our retail gas customer supply business in more detail on page 13.

~~Shipping Joint Venture~~

~~As previously discussed in the~~~~Impairment Losses and Other Costs~~ ~~footnote, we completed the sale of our equity investment in a shipping joint venture during the third quarter of 2009. No gain or loss was recognized on the sale.~~

~~Investments Classified as Available-for-Sale~~

~~We classify the following investments as available-for-sale:~~

•: ~~nuclear decommissioning trust funds,~~
•: ~~marketable equity securities, and~~
•: ~~trust assets securing certain executive benefits.~~

~~This means we do not expect to hold these investments to maturity, and we do not consider them trading securities. We record these investments at fair value on our Consolidated Balance Sheets.~~

We show the fair values, gross unrealized gains and losses, and adjusted cost basis for all of our available-for-sale securities in the following tables. We use specific identification to determine cost in computing realized gains and losses.

At September 30, 2009
Adjusted
Cost
Unrealized
Gains
Unrealized
Losses
Fair
Value

(In millions)

Money market funds
$ 20.2 $ — $ — $ 20.2
Marketable equity securities
214.7 109.9 — 324.6
Mutual fund / common collective trusts
479.6 109.1 — 588.7
Corporate debt securities
144.9 24.3 — 169.2
U.S. Government agencies
42.5 2.5 — 45.0
U.S. Treasuries
18.9 1.1 — 20.0
State municipal bonds
46.4 5.2 — 51.6

Totals
$ 967.2 $ 252.1 $ — $ 1,219.3

~~The unrealized gains in the preceding table consist primarily of $249.4 million associated with the nuclear decommissioning trust funds.~~

The investments in our nuclear decommissioning trust funds are managed by third parties who have independent discretion over the purchases and sales of securities. We recognize impairments for any of these investments for which the fair value declines below our book value. We recognized $0.2 million and $62.6 million in pre-tax impairment losses on our nuclear decommissioning trust investments during the quarter and nine months ended September 30, 2009, respectively. These impairments are included as part of gross realized losses in the following table.

~~Gross and net realized gains and losses on available-for-sale securities were as follows:~~

Quarter Ended
September 30,
2009
Nine Months
Ended
September 30,
2009

(In millions)

Gross realized gains
$ 10.0 $ 25.2
Gross realized losses
(3.5 ) (75.5 )

Net realized gains
$ 6.5 $ (50.3 )

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~~The corporate debt securities, U.S. Government agency obligations, U.S. Treasuries, and state municipal bonds mature on the following schedule:~~

At September 30, 2009

(In millions)

Less than 1 year
$ 9.6
1-5 years
87.5
5-10 years
86.0
More than 10 years
102.7

Total maturities of debt securities
$ 285.8

Quarter Ended March 31, 2010

	(In millions)
Revenues	$	360.9
Fuel and purchased energy expenses		58.4
Income from operations		37.6
Net income		49.1

Information by Operating Segment

In connection with the strategic initiatives that were undertaken in 2008 and 2009, we decided to re-align our reporting structure, beginning January 1, 2010, to reflect our current view of managing the business. As a result, as of January 1, 2010, we changed our reportable segments and have recast prior period information to conform with the current presentation.

Our reportable operating segments ~~are—Merchant Energy,~~are Generation, NewEnergy (referred to as Customer Supply in our 2009 Annual Report on Form 10-K), Regulated Electric, and Regulated Gas:

•

Our ~~merchant energy~~Generation business is nonregulated and includes:

—: a power generation and development operation that owns, operates and maintains fossil ~~nuclear,~~ and ~~interests in hydroelectric~~renewable generating facilities, ~~and~~a fuel processing facility, qualifying facilities, and power projects in the United States,
—: an operation that manages certain contractually owned physical assets, including generating facilities,
—: an interest in a nuclear generation joint venture (CENG) that owns, operates, and maintains five nuclear generating units, and
—: an interest in a joint venture (UniStar Nuclear Energy, LLC (UNE)) to develop, own, and operate new nuclear projects in the United States.

•

Our NewEnergy business is nonregulated and includes:

—: full requirements load-serving sales of energy and capacity to utilities, cooperatives, and commercial, industrial, and governmental customers,
—: ~~gas~~sales of retail energy products and services to residential, commercial, industrial, and governmental customers,
—: structured transactions and risk management services for various customers (including hedging of output from generating facilities and fuel costs), and trading in energy and energy-related commodities to facilitate portfolio management,
—: risk management services for our Generation business,
—: design, construction, and operation of renewable energy, heating, cooling, and cogeneration facilities for commercial, industrial, and governmental customers throughout North America, including energy performance contracting and energy efficiency engineering services,
—: upstream (exploration and production) natural gas ~~operations,~~activities, and
—: ~~generation operations~~sales of home improvements, servicing of electric and ~~maintenance.~~gas appliances, and heating, air conditioning, plumbing, electrical, and indoor air quality systems, and providing electric and natural gas to residential customers in central Maryland.

•

Our regulated electric business purchases, transmits, distributes, and sells electricity in Central Maryland.

•

Our regulated gas business purchases, transports, and sells natural gas in Central Maryland.

Our ~~remaining nonregulated businesses:~~

•: ~~design, construct, and operate renewable energy, heating, cooling, and cogeneration facilities for commercial, industrial, and governmental customers throughout North America,~~
•: ~~provide energy performance contracting and energy efficiency engineering services,~~
•: provide home improvements, service electric and gas appliances, service heating, air conditioning, plumbing, electrical, and indoor air quality systems, and provide natural gas marketing to residential customers in Central Maryland, and
•: ~~develop and deploy new nuclear plants in North America.~~

Prior to June 30, 2009, our merchant energy business segment included additional activities that have been divested as part of our strategy to improve our liquidity and reduce our business risk. The divested activities include:

•: ~~our international commodities operation, which was divested in March 2009,~~
•: ~~our gas trading operation, which was divested on April 1, 2009,~~
•: ~~our ownership of a uranium market participant, which was divested on June 30, 2009, and~~
•: ~~our investment in a shipping joint venture, which was divested in the third quarter of 2009.~~

~~See page 11 for discussion of our transaction with EDF.~~

We believe that the successful execution of these divestitures, as well as our other initiatives that we have undertaken to reduce risk in our merchant energy business, have reduced our exposure to activities that require contingent capital support and improved our liquidity. As a result of these divestitures and other initiatives, as well as the closing of our transaction with EDF, the results for our merchant energy business segment will be materially different from prior periods. We discuss these strategies and their effect on liquidity in~~Note 8~~ ~~of our 2008 Annual Report on Form 10-K.~~

~~Our Merchant Energy,~~Generation, NewEnergy, Regulated Electric, and Regulated Gas reportable segments are strategic businesses based principally upon regulations, products, and services that require different technologies and marketing strategies. We evaluate the performance of these segments based on net income. We account for intersegment revenues using market prices. A summary of information by operating segment is shown in the table below.

Table of Contents

	Reportable Segments																		Reportable Segments

	Reportable Segments									Holding Company and Other Nonregulated Businesses									Reportable Segments									Holding Company and Other
	Merchant Energy Business			Regulated Electric Business			Regulated Gas Business			Holding Company and Other Nonregulated Businesses			Eliminations			Consolidated			Generation		NewEnergy			Regulated Electric		Regulated Gas		Holding Company and Other			Eliminations			Consolidated

	(In millions)																		(In millions)
For the quarter ended September 30,
Quarter ended March 31,
2010
Unaffiliated revenues																			$	291.2	$	2,227.0		$	751.3	$	317.1	$	—		$	—		$	3,586.6
Intersegment revenues																				288.7		123.9			—		0.9		—			(413.5	)		—

Total revenues																				579.9		2,350.9			751.3		318.0		—			(413.5	)		3,586.6
Net income (loss)																				27.1		104.1			27.2		37.2		(4.3	)		—			191.3
Net income (loss) attributable to common stock																				27.1		107.6			24.6		36.5		(4.3	)		—			191.5
2009
Unaffiliated revenues	$	3,101.6		$	788.3		$	77.7		$	60.1		$	—		$	4,027.7		$	181.8		2,928.0		$	806.8	$	384.3	$	2.5		$	—		$	4,303.4
Intersegment revenues		156.4			—			0.5			0.1			(157.0	)		—			603.7		86.8			—		2.6		—			(693.1	)		—

Total revenues		3,258.0			788.3			78.2			60.2			(157.0	)		4,027.7			785.5		3,014.8			806.8		386.9		2.5			(693.1	)		4,303.4
Net income (loss)		142.1			42.3			(10.5	)		(6.5	)		—			167.4			41.5		(246.3	)		45.4		39.6		0.1			—			(119.7	)
Net income (loss) attributable to common stock		116.0			39.8			(11.3	)		(6.9	)		—			137.6			41.5		(246.8	)		42.9		38.8		0.1			—			(123.5	)
2008
Unaffiliated revenues	$	4,300.8		$	822.3		$	150.3		$	50.2		$	—		$	5,323.6
Intersegment revenues		191.8			0.1			5.2			—			(197.1	)		—

Total revenues		4,492.6			822.4			155.5			50.2			(197.1	)		5,323.6
Net (loss) income		(246.0	)		34.3			(11.5	)		1.1			—			(222.1	)
Net (loss) income attributable to common stock		(246.0	)		31.7			(12.2	)		0.8			—			(225.7	)
For the nine months ended September 30,
2009
Unaffiliated revenues	$	9,202.3		$	2,250.8		$	573.1		$	169.0		$	—		$	12,195.2
Intersegment revenues		536.2			—			3.7			0.1			(540.0	)		—

Total revenues		9,738.5			2,250.8			576.8			169.1			(540.0	)		12,195.2
Net (loss) income		(39.7	)		109.8			22.9			(17.0	)		—			76.0
Net (loss) income attributable to common stock		(83.1	)		102.2			20.6			(17.5	)		—			22.2
2008
Unaffiliated revenues	$	12,011.9		$	1,980.3		$	724.4		$	175.3		$	—		$	14,891.9
Intersegment revenues		707.8			0.2			15.6			0.2			(723.8	)		—

Total revenues		12,719.7			1,980.5			740.0			175.5			(723.8	)		14,891.9
Net income (loss)		106.7			(31.2	)		26.4			0.4			—			102.3
Net income (loss) attributable to common stock		105.9			(38.8	)		24.1			0.3			—			91.5

Certain prior-period amounts have been ~~reclassified~~restated to conform with the current period's reportable segment presentation.

Our ~~merchant energy~~Generation business operating results for the quarter ~~and nine months~~ ended ~~September 30, 2009~~March 31, 2010 include the following after-tax charges. Amounts for the quarter ended September 30, 2009 include income tax adjustments relating to activity during the quarters ended March 31, 2009 and June 30, 2009 based on updated estimates of our 2009 annual effective tax rate.charges:

•: ~~impairment losses and other costs~~deferred income tax expense relating to federal subsidies for providing post-employment prescription drug benefits of ~~$8.2~~$0.8 million ~~and $81.5 million, respectively,~~as a result of healthcare reform legislation enacted in March 2010,
•: ~~merger termination and strategic alternatives costs~~amortization of ~~$4.9~~basis difference in investment in CENG of $25.7 million, ~~and $51.2 million, respectively,~~
•: ~~net loss on sale~~impact of ~~a majority~~power purchase agreement with CENG of $25.7 million (amount represents the amortization of our ~~international commodities operation,~~"unamortized energy contract asset" less our ~~Houston-based gas trading operation, certain other trading operations, and a uranium market participant, the reclassification~~50.01% equity in CENG's amortization of losses on previously designated cash-flow hedges from Accumulated Other Comprehensive Loss, and earnings that are no longer part of our core business totaling $62.9 million (primarily related to income tax adjustments) and $370.9 million, respectively,its "unamortized energy contract liability"),
•: ~~impairment charge related to our nuclear decommissioning trust fund assets~~loss on early retirement of ~~$19.7~~2012 Notes of $30.9 million, ~~(primarily related to income tax adjustments) and $49.5 million, respectively,~~
•: ~~workforce reduction costs of $1.6 million and $7.0 million, respectively,~~ and
•: amortization of credit facility amendment fees in connection with the EDF transaction of ~~$8.2 million and $17.1 million, respectively.~~$1.9 million.

Our NewEnergy business operating results for the quarter ended March 31, 2010 include the following after-tax charges:

•: deferred income tax expense relating to federal subsidies for providing post-employment prescription drug benefits of $0.1 million as a result of healthcare reform legislation enacted in March 2010, and
•: amortization of credit facility amendment fees in connection with the EDF transaction of $1.0 million.

Our Regulated Electric business operating results for the quarter ended March 31, 2010 include an after-tax charge for the deferred income tax expense relating to federal subsidies for providing post-employment prescription drug benefits of $3.1 million as a result of healthcare reform legislation enacted in March 2010.

Our Holding Company and Other ~~Nonregulated~~ businesses operating results for the quarter ~~and nine months~~ ended ~~September 30, 2009 reflect impairment losses and other costs~~March 31, 2010 include an after-tax charge for the deferred income tax expense relating to federal subsidies for providing post-employment prescription drug benefits of ~~$0.8~~$4.8 million ~~and $3.9 million after-tax, respectively.~~as a result of healthcare reform legislation enacted in March 2010.

Total assets ~~decreased~~declined approximately ~~$2.6~~$1.4 billion during ~~the nine months ended September 30, 2009. The~~2010 due primarily to a decrease ~~primarily relates to:~~

•: ~~our Holding Company~~in cash and ~~Other Nonregulated Businesses and is primarily related to the approximately $1 billion decline in restricted~~ cash equivalents as a result of income taxes paid on the ~~repayment of the 14% Senior Notes to MidAmerican in January 2009, and~~
•: our Merchant Energy Business and is primarily related to the decrease in derivative assets, net of fair value collateral, of $816.3 million and a decrease in other net collateral and margin posted of $1.0 billion, primarily associatedtransaction with ~~the divestitures~~EDF and the ~~activities to reduce risk in our Global Commodities portfolio.~~

~~These decreases were offset by a $194.1 million increase in the value~~retirement of ~~our nuclear decommissioning trust fund assets.~~

Our allowance for uncollectible accounts receivable decreased $59.7 million from December 31, 2008 to September 30, 2009. This decrease is primarily attributable to a decrease of $80.3 million at our merchant energy business, partially offset by an increase of $18.7 million at our regulated electric and gas businesses. The decrease in the allowance for uncollectibles at our merchant energy business is primarily driven by a write-off of accounts receivable balances of certain customers and the related allowance balance that were established primarily during 2008 for certain counterparties that encountered financial difficulty. This decrease is partially offset by an increase at our regulated electric and gas businesses primarily due to a second quarter 2009 Maryland PSC ruling and the economic downturn which continues to cause a decreased ability of customers to pay their utility bills. The Maryland PSC ruling in the second quarter of 2009 delayed BGE's ability to terminate service to customers with arrearages and required BGE to offer those customers the option to enter into extended payment plans.debt.

Table of Contents

Pension and Postretirement Benefits

We show the components of net periodic pension benefit cost in the following table:

	Quarter Ended September 30,						Nine Months Ended September 30,						Quarter Ended March 31,

	2009			2008			2009			2008			2010			2009

	(In millions)												(In millions)
Components of net periodic pension benefit cost
Service cost	$	12.2		$	14.6		$	41.8		$	42.4		$	9.5		$	15.2
Interest cost		26.3			26.6			84.6			76.8			21.7			27.2
Expected return on plan assets		(28.6	)		(29.6	)		(97.1	)		(85.5	)		(26.7	)		(29.6	)
Recognized net actuarial loss		7.5			6.6			29.2			19.0			8.1			10.6
Amortization of prior service cost		2.8			2.8			8.6			8.3			1.0			3.3
Amount capitalized as construction cost		(2.5	)		(2.3	)		(7.9	)		(7.1	)		(1.9	)		(2.6	)

Net periodic pension benefit cost¹	$	17.7		$	18.7		$	59.2		$	53.9		$	11.7		$	24.1

1 BGE's portion of our net periodic pension benefit cost, excluding amounts capitalized, was $4.7 million for the quarter ended September 30, 2009 and $4.5 million for the quarter ended September 30, 2008. BGE's portion of our net periodic pension benefit cost, excluding amounts capitalized, was $14.6 million for the nine months ended September 30, 2009 and $13.2 million for the nine months ended September 30, 2008. Net periodic pension benefit costs exclude settlement charges of $1.0 million and $8.7$6.3 million in ~~the quarter~~2010 and ~~nine months ended September 30, 2009, respectively.~~$7.2 million in 2009.

We show the components of net periodic postretirement benefit cost in the following table:

	Quarter Ended September 30,						Nine Months Ended September 30,						Quarter Ended March 31,

	2009			2008			2009			2008			2010			2009

	(In millions)												(In millions)
Components of net periodic postretirement benefit cost
Service cost	$	1.8		$	1.3		$	5.4		$	4.9		$	0.7		$	1.6
Interest cost		6.0			5.4			18.1			19.3			4.7			5.8
Amortization of transition obligation		0.6			0.5			1.7			1.7			0.5			0.5
Recognized net actuarial loss		0.6			0.5			1.7			1.6			0.3			0.7
Amortization of prior service cost		(0.9	)		(0.8	)		(2.7	)		(2.8	)		(0.7	)		(0.8	)
Amount capitalized as construction cost		(1.6	)		(1.5	)		(4.9	)		(5.5	)		(1.3	)		(1.5	)

Net periodic postretirement benefit cost¹	$	6.5		$	5.4		$	19.3		$	19.2		$	4.2		$	6.3

1 BGE's portion of our net periodic postretirement benefit cost, excluding amounts capitalized, was ~~$3.1~~$4.8 million ~~for the quarter ended September 30, 2009~~in 2010 and ~~$3.3~~$4.6 million for the quarter ended September 30, 2008. BGE's portion of our net periodic postretirement benefit costs, excluding amounts capitalized, was $9.8 million for the nine months ended September 30, 2009 and $11.0 million for the nine months ended September 30, 2008.in 2009.

Our non-qualified pension plans and our postretirement benefit programs are not funded; however, we have trust assets securing certain executive pension benefits. We estimate that we will incur approximately ~~$22~~$9.3 million in pension benefit payments for our non-qualified pension plans and approximately ~~$29.5~~$25.7 million for retiree health and life insurance ~~benefit payments during 2009. As of September 30, 2009, we~~costs in 2010. We contributed ~~$317~~$12.2 million to our qualified pension ~~plans. We contributed an~~plans in April 2010.

Healthcare Reform Legislation

During March 2010, the Patient Protection and Affordable Care Act and the Healthcare and Education Reconciliation Act of 2010 were signed into law. These laws eliminate the tax exempt status of drug subsidies provided to companies under Medicare Part D after December 31, 2012. As a result of this new legislation, we recorded a noncash charge to reflect additional ~~$2.5~~deferred income tax expense of $8.8 million in ~~October 2009.~~the quarter ended March 31, 2010.

Financing Activities

Credit Facilities and Short-term Borrowings

Our short-term borrowings may include bank loans, commercial paper, and bank lines of credit. Short-term borrowings mature within one year from the date of issuance. We pay commitment fees to banks for providing us lines of credit. When we borrow under the lines of credit, we pay market interest rates.

~~Table of Contents~~

~~Constellation Energy~~

~~Constellation Energy had bank and other lines of credit under committed unsecured credit facilities totaling $5.8 billion at September 30, 2009 for short-term financial needs.~~ We enter into these facilities to ensure adequate liquidity to support our operations.

Constellation Energy

Our liquidity requirements are funded with credit facilities and cash. We fund our short-term working capital needs with existing cash and with our credit facilities, ~~many of~~ which support direct cash borrowings and the issuance of commercial paper, if available. We also use our credit facilities to support the issuance of letters of credit, primarily for our ~~merchant energy~~NewEnergy business.

~~We have included in the table below our~~Constellation Energy had bank lines of credit under committed credit facilities totaling $4.0 billion at March 31, 2010 for short-term financial needs as ~~of September 30, 2009 and pro forma following the completion of the transaction with EDF:~~follows:

Facility Expiration
Facility
Size
as of
September 30,
2009²
Facility Size
Pro Forma
upon Completion
of the EDF
Transaction²

(In billions)

July 2012
$ 3.85 $ 2.32
November 2009¹
1.23 —
September 2013
0.35 —
December 2009
0.15 —
September 2014
0.25 0.50

Total
$ 5.83 $ 2.82

Type of Credit Facility		Amount (In billions)		Expiration Date	Capacity Type


Syndicated Revolver		$	2.32	July 2012	Letters of credit and cash
Commodity-linked			0.50	August 2014	Letter of credit
Bilateral			0.55	September 2014	Letters of credit
Bilateral			0.25	December 2014	Letters of credit and cash
Bilateral			0.25	June 2014	Letters of credit and cash
Bilateral			0.15	September 2013	Letters of credit

	Total	$	4.02

~~1 Size~~ Collectively, these facilities currently support the issuance of ~~facility may be reduced by proceeds received from certain securities offerings~~ letters of credit and/or ~~asset sales.~~

~~2 Excludes~~cash borrowings up to $4.0 billion. At March 31, 2010, we had approximately $1.9 billion in letters of credit issued including $0.4 billion in letters of credit issued under the commodity-linked credit facility discussed below ~~due to its contingent nature.~~and no commercial paper outstanding or direct borrowings under these facilities.

~~During the third quarter~~Table of 2009, we executed a committed five year bilateral credit facility that allows for a maximum capacity of $500 million. This facility can be used to issue letters of credit in support of our collateral obligations. At September 30, 2009 and November 3, 2009, this facility had committed capacity of $250 million and $500 million, respectively. The facility partially replaces a portion of our credit facilities that terminate upon closing of the transaction with EDF.Contents

~~During the third quarter of 2009, we also entered into a five year~~The commodity-linked credit facility ~~that~~currently allows for the issuance of letters of credit up to a maximum capacity of $500 million. We could increase the maximum facility size to $750 million or alternatively enter into an additional $250 million bilateral facility if certain conditions are met, including the closing of the transaction with EDF.$0.5 billion. This commodity-linked facility is designed to help manage our contingent collateral requirements associated with the hedging of our ~~Customer Supply operations~~NewEnergy business because its capacity increases as natural gas price levels decrease compared to a reference price that is adjusted periodically. As

At March 31, 2010, Constellation Energy had $21.1 million of ~~September 30, 2009, there were no letters~~short-term notes outstanding with a weighted average effective interest rate of ~~credit outstanding under this facility.~~6.33%.

BGE

~~As of September 30, 2009,~~ BGE has a ~~$400.0~~$600.0 million ~~five-year~~ revolving credit facility expiring in 2011. BGE can borrow directly from the banks, use the facility to allow commercial paper to be issued, if available, or issue letters of credit. On October 29, 2009, BGE expanded its borrowing capacity to $575 million. The size of the facility may be increased up to $600 million with additional commitments by lenders. As of September 30, 2009,At March 31, 2010, BGE had ~~$0.5 million in~~no commercial paper or direct borrowings outstanding. There were immaterial letters of credit ~~issued under this facility.~~

~~In addition,~~outstanding at ~~September 30, 2009, BGE had $334.9 million in commercial paper outstanding.~~March 31, 2010.

Debt

Constellation Energy

As part of our voluntary commitment to reduce our debt by $1 billion with funds received from the EDF transaction, we retired the following debt during the quarter ended March 31, 2010 completing this commitment.

7.00% Notes due April 1, 2012

In ~~July 2009,~~February 2010, we ~~entered into a three year asset-based lending agreement associated with certain upstream gas properties that we own. At September 30, 2009, the borrowing base committed under the facility was $30~~retired an aggregate principal amount of $486.5 million of ~~which $12.1~~our 7.00% Notes due April 1, 2012 pursuant to a cash tender offer, at a premium of approximately 11%. We recorded a loss on this transaction of $50.1 million ~~has been utilized and reflected in "Long-term debt" in~~within "Interest expense" on our Consolidated ~~Balance Sheets. The size~~Statements of ~~the facility may be increased up to $200~~Income (Loss).

Tax-Exempt Notes

In March 2010, we repurchased our outstanding $47 million ~~with additional commitments by the lenders. At October 30, 2009, the borrowing base of the facility increased to $100~~and $65 million with the commitments of additional lenders. Any debt issued under this facility is secured by the upstream gas properties, and the lenders do not have recourse against Constellation Energy in the event of a default. Interest is payable quarterly in March, June, September, and December.

~~This asset-based lending agreement contains a provision that requires certain of our entities that own our upstream gas properties to maintain a current ratio of one-to-one. As of September 30, 2009,~~variable rate tax-exempt notes. Since these ~~entities were in compliance with this provision.~~

~~Table of Contents~~notes are variable rate instruments, there was no gain or loss recorded upon repurchase.

Net Available Liquidity

The following table provides a summary of our, and BGE's, net available liquidity at ~~September 30, 2009:~~March 31, 2010.



	As of September 30, 2009
	Constellation Energy			BGE			Total Consolidated
At March 31, 2010										Constellation Energy			BGE
	(In billions)									(In billions)
Credit facilities¹	$	5.8		$	0.4		$	6.2		$	3.5		$	0.6
Less: Letters of credit issued		(2.0	)		—			(2.0	)
Less: Letters of credit issued¹											(1.5	)		—
Less: Cash drawn on credit facilities		—			—			—			—			—

Undrawn facilities		3.8			0.4			4.2			2.0			0.6
Less: Commercial paper outstanding		—			(0.3	)		(0.3	)		—			—

Net available facilities		3.8			0.1			3.9			2.0			0.6
Add: Cash		0.7			—			0.7
Add: Cash and cash equivalents											1.6			0.3

Cash and facility liquidity											3.6			0.9
Add: EDF put arrangement		1.1			—			1.1			1.1			—

Net available liquidity	$	5.6		$	0.1		$	5.7		$	4.7		$	0.9

1 Excludes $0.5 billion commodity-linked credit facility due to its contingent ~~nature.~~nature and $0.4 billion in letters of credit posted against it.

Upon the close of the EDF transaction, the amount and composition of our liquidity will change due to the reduction in credit facilities discussed on the previous page, as well as the receipt of net cash proceeds from the transaction.

The net proceeds from this transaction are expected to be approximately $2.2 billion after repayment of the EDF preferred stock and the payment of taxes. We anticipate using these proceeds to reduce up to $850 million of our long-term debt, as well as for other general corporate purposes, including payments related to BGE under the Maryland PSC order dated October 30, 2009. These net proceeds will partially offset the reduction in credit facilities, although our net available liquidity will be reduced.

Other Sources of Liquidity

~~In December 2008, we executed an~~Our Investment Agreement with EDF ~~that~~ includes an asset put arrangement that provides us with an option at any time through December 31, 2010 ~~(or the termination of the Investment Agreement by EDF if we breach that agreement)~~ to sell certain non-nuclear generation assets, at pre-agreed prices, to EDF for aggregate proceeds of no more than $2 billion pre-tax, or approximately $1.4 billion after-tax. The amount of after-tax proceeds will be impacted by the assets actually sold and the related tax impacts at that time.

Exercise of the put arrangement is conditioned upon the receipt of regulatory approvals and ~~third-party~~third party consents, the absence of any material liens on such assets, and the absence of a material adverse effect, as defined in the Investment Agreement. ~~During April 2009, we~~We have received regulatory approvals and consents for the majority of the assets covered by the put arrangement. As of ~~September 30, 2009,~~March 31, 2010, we have approximately $1.1 billion after-tax of liquidity available through the put arrangement. We expect to receive regulatory approval for an additional asset in the ~~first~~second quarter of 2010, which will increase the net after-tax liquidity from the put arrangement to approximately $1.4 billion.

We continue to increase available liquidity and to reduce our business risk. Specifically, we are reducing capital spending and ongoing expenses, scaling down the expected variability in long-term earnings and short-term collateral usage, and limiting our exposure to business activities that require contingent capital support. During 2009, we made progress on several of these initiatives as discussed in more detail in the~~Divestitures~~ ~~section beginning on page 16 and the~~~~Variable Interest Entities~~ ~~section on page 13. As of September 30, 2009, we have realized substantially all of the $1 billion of the net reduction in collateral that was expected from the divestiture of these operations.~~

Credit Facility Compliance and Covenants

~~The credit facilities of Constellation Energy and BGE have limited material adverse change clauses, none of which would prohibit draws under the existing facilities.~~

Certain credit facilities of Constellation Energy contain a provision requiring Constellation Energy to maintain a ratio of debt to capitalization equal to or less than 65%. At ~~September 30, 2009,~~March 31, 2010, the debt to capitalization ratio as defined in the credit agreements was ~~46%~~32%.

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~~Upon the closing of~~Under our ~~transaction with EDF, under our $3.85~~$2.32 billion credit facility, ~~(which reduces to $2.32 billion),~~ we ~~will grant~~granted a lien on certain of our generating facilities and ~~pledge~~pledged our ownership interests in our nuclear business to the ~~lenders.~~

Our $1.23 billion credit facility requires us to maintain consolidated earnings before interest, taxes, depreciation, and amortization to consolidated interest expense ratio of at least 2.75 when our S&P senior

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unsecured debt rating is BBB- or lower and our Moody's senior unsecured debt rating is Baa3 or lower. Compliance with the covenant was not required as of September 30, 2009 as S&P's senior unsecured debt rating was above BBB-. Since the $1.23 billion credit facility expireslenders upon the ~~earlier~~completion of the ~~closing of the EDF~~ transaction ~~or November 12, 2009, the recent change in rating by S&P to BBB- will not require compliance~~ with ~~this covenant.~~EDF.

The credit agreement of BGE contains a provision requiring BGE to maintain a ratio of debt to capitalization equal to or less than 65%. At ~~September 30, 2009,~~March 31, 2010, the debt to capitalization ratio for BGE as defined in this credit agreement was ~~52%~~44%.

~~The~~Decreases in Constellation Energy's or BGE's credit ratings would not trigger an early payment on any of our, or BGE's, credit facilities. However, the impact of a credit ratings downgrade on our financial ratios associated with our credit facility covenants would depend on our financial condition at the time of such a downgrade and on the source of funds used to satisfy the incremental collateral obligation resulting from a credit ratings downgrade. For example, if we were to use existing cash balances or exercise the put option with EDF to fund the cash portion of any additional collateral obligations resulting from a credit ratings downgrade, we would not expect a material impact on our financial ratios. However, if we were to issue long-term debt or use our credit facilities to fund any additional collateral obligations, our financial ratios could be materially affected. Failure by Constellation Energy, or BGE, to comply with these covenants could result in the acceleration of the maturity of the borrowings outstanding and preclude us from issuing letters of credit under these facilities.

The credit facilities of Constellation Energy and BGE contain a material adverse change representation but draws on the facilities are not conditioned upon Constellation Energy and BGE making this representation at the time of the draw. However, to the extent a material adverse change has occurred and prevents Constellation Energy or BGE from making other representations that are required at the time of the draw, the draw would be prohibited.

Income Taxes

We compute the income tax expense (benefit) for each quarter based on the estimated annual effective tax rate for the year. The effective tax rate was ~~64.1% and 67.7%~~33.3% for the quarter ~~and nine months~~ ended ~~September 30, 2009, respectively,~~March 31, 2010 compared to ~~33.4% and 41.1%~~66.9% for the same ~~periods~~period of ~~2008.~~2009. The lower effective tax rate for 2010 reflects the impact of favorable adjustments (primarily related to reductions of uncertain tax positions and higher deductions for qualified production activities). The higher effective tax rate ~~for the quarter and nine months ended September 30,~~in 2009 reflects the impact of unfavorable nondeductible adjustments (primarily related to nondeductible dividends on the Series B Preferred Stock and the write-off of the unamortized debt discount on the 14% Senior Notes) in relation to the lower estimated 2009 taxable income (primarily attributable to losses on the divestiture of a majority of our international commodities and our Houston-based gas trading operations).

The BGE effective tax rate was ~~36.5% and 38.9%~~41.6% for the quarter ~~and nine months~~ ended ~~September 30, 2009, respectively,~~March 31, 2010 compared to ~~43.4% and (73.1)%~~39.5% for the same ~~periods~~period of ~~2008. This reflects~~2009. The higher effective tax rate for 2010 is primarily due to the impact of the ~~lower 2008 taxable income related to~~healthcare reform legislation enacted in the ~~Maryland settlement agreement,~~first quarter of 2010, which ~~increased~~eliminates the ~~relative impact~~tax exempt status of ~~favorable permanent tax adjustments on BGE's 2008 effective tax rate.~~prescription drug subsidies received under Medicare Part D.

Unrecognized Tax Benefits

The following table summarizes the change in unrecognized tax benefits during ~~2009~~2010 and our total unrecognized tax benefits at ~~September 30, 2009:~~March 31, 2010:

	(In millions)				(In millions)

At September 30, 2009
At March 31, 2010				At March 31, 2010
Total unrecognized tax benefits, January 1, 2009	$	189.7
Total unrecognized tax benefits, January 1, 2010					$	312.5
Increases in tax positions related to the current year		6.1				4.3
Increases in tax positions related to prior years		118.4				2.8
Reductions in tax positions related to prior years		(16.2	)			(28.8	)
Reductions in tax positions as a result of a lapse of the applicable statute of limitations		(0.8	)			(0.6	)

Total unrecognized tax benefits, September 30, 2009¹	$	297.2
Total unrecognized tax benefits, March 31, 2010¹					$	290.2

1 BGE's portion of our total unrecognized tax benefits at ~~September 30, 2009~~March 31, 2010 was ~~$90.6~~$104.3 million.

Increases in tax positions related to the current year ~~tax positions~~and prior years are primarily due to unrecognized tax benefits for repair and depreciation deductions measured at amounts consistent with prior ~~Internal Revenue Service (IRS)~~IRS examination results and state income tax accruals. ~~Increases~~

Decreases in ~~prior year~~ tax positions related to prior years are primarily due to ~~BGE~~the resolution of the tax treatment of distributions received from our shipping joint venture in July 2008 and repair deductions.

Total unrecognized tax benefits as of March 31, 2010 of $290.2 million include outstanding claims of approximately $63.0 million, including $51.6 million in state tax credits, for which no tax benefit was recorded on our Consolidated Balance Sheet because refunds were not received and ~~depreciation deductions, which have~~the claims do not ~~been~~meet the ~~subject of an IRS examination.~~"more-likely-than-not" threshold.

If the total amount of unrecognized tax benefits of ~~$297.2~~$290.2 million were ultimately realized, our income tax

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expense would decrease by approximately ~~$173~~$167 million. However, the ~~$173~~$167 million includes state tax refund claims of ~~approximately $51~~$51.6 million that have been disallowed by tax authorities and ~~we believe that there is a remote likelihood of ultimately realizing any benefit from these refund claim amounts.~~are subject to appeals. These state refund claims may be resolved by ~~December~~March 31, ~~2009.~~2011. For this reason, we believe it is reasonably possible that reductions to our total unrecognized tax benefits ~~in the range~~ of ~~$40 to~~approximately $50 million may occur by March 31, ~~2010,~~2011, although these reductions are not expected to materially impact income tax expense.

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Interest and penalties recorded in our Consolidated Statements of Income (Loss) as tax expense (benefit) relating to liabilities for unrecognized tax benefits were as follows:

Quarter Ended
September 30,
Nine Months
Ended
September 30,

2009
2008
2009
2008

(In millions)

Interest and penalties recorded as tax expense
$ 8.5 $ 0.2 $ 9.2 $ 1.9

	For the Quarter Ended March 31,

	2010		2009

	(In millions)
Interest and penalties recorded as tax expense (benefit)	$	3.4	$	(0.7	)

BGE's portion of interest and penalties was immaterial for both periods presented.

Accrued interest and penalties recognized in our Consolidated Balance Sheets were ~~$19.5~~$26.5 million, of which BGE's portion was ~~$0.9~~$2.6 million, at ~~September 30, 2009,~~March 31, 2010, and ~~$10.3~~$23.1 million, of which BGE's portion was ~~$0.7~~$1.6 million, at December 31, ~~2008.~~2009.

Taxes Other Than Income Taxes

~~BGE collects from certain customers~~Taxes other than income taxes primarily include property and gross receipts taxes along with franchise taxes and other non-income taxes, surcharges, and fees.

BGE and our NewEnergy operations collect certain taxes from customers such as sales and gross receipts taxes, along with other taxes, surcharges, and fees that are levied by state or local governments on the sale or distribution of gas and electricity. ~~We include these types of taxes in "Taxes other than income taxes" in our Consolidated Statements of Income (Loss).~~ Some of these taxes are imposed on the customer and others are imposed on ~~BGE. We account for the~~BGE and our NewEnergy business. Where these taxes, such as sales taxes, are imposed on the customer, we account for these taxes on a net basis which means we do not recognize revenue and an offsetting tax expense for the taxes collected from customers. We account for the taxes imposed on BGE on a gross basis, which means we recognize revenue for the taxes collected from customers. Accordingly, we record the taxes accounted for on a gross basis as revenues in the accompanyingwith no impact to our Consolidated Statements of Income (Loss). However, where these taxes, such as gross receipts taxes or other surcharges or fees, are imposed on BGE or our NewEnergy business, we account for ~~BGE~~these taxes on a gross basis. Accordingly, we recognize revenues for these taxes collected from customers along with an offsetting tax expense, which are both included in our and BGE's Consolidated Statements of Income (Loss). The taxes, surcharges, or fees that are included in revenues were as follows:

Quarter Ended
September 30,
Nine Months
Ended
September 30,

2009
2008
2009
2008

(In millions)

Taxes other than income taxes included in revenues—BGE
$ 19.3 $ 19.1 $ 59.4 $ 54.3

Quarter Ended March 31,	2010		2009


	(In millions)
Constellation Energy (including BGE)	$	31.0	$	30.7
BGE		21.9		21.6

Guarantees

Our guarantees do not represent incremental Constellation Energy obligations; rather they primarily represent parental guarantees of subsidiary obligations. The following table summarizes the maximum exposure by guarantor based on the stated limit of our outstanding guarantees:



At September 30, 2009	Stated Limit
At March 31, 2010			Stated Limit
	(In billions)		(In billions)
Constellation Energy guarantees	$	11.5	$	9.6
Merchant energy business guarantees		0.1
BGE guarantees		0.3		0.3

Total guarantees	$	11.9	$	9.9

At ~~September 30, 2009,~~March 31, 2010, Constellation Energy had a total of ~~$11.9~~$9.9 billion in guarantees outstanding related to loans, credit facilities, and contractual performance of certain of its subsidiaries as described below.

•

Constellation Energy guaranteed a face amount of ~~$11.5~~$9.6 billion as follows:

•: $~~10.5~~8.8 billion on behalf of our ~~merchant energy subsidiaries~~Generation and NewEnergy businesses to allow ~~those subsidiaries~~them the flexibility needed to conduct business with counterparties without having to post other forms of collateral. Our estimated net exposure for obligations under commercial transactions covered by these guarantees was approximately $2 billion at ~~September 30, 2009,~~March 31, 2010, which represents the total amount the parent company could be required to fund based on ~~September 30, 2009~~March 31, 2010 market prices. For those guarantees related to our derivative liabilities, the fair value of the obligation is recorded in our Consolidated Balance Sheets.
•: $~~0.9~~0.6 billion primarily on behalf of ~~our~~CENG's nuclear generating facilities for nuclear insurance and credit support to ensure these plants have funds to meet expenses and obligations to safely operate and maintain the plants. We recorded the fair value of $12.3 million for these guarantees on our Consolidated Balance Sheets.
•: $~~0.1~~0.2 billion to its other nonregulated businesses.

•

~~Our merchant energy business guaranteed $73.0 million for loans, performance guarantees and other payment obligations primarily related to certain power projects in which we have an investment.~~

•

BGE guaranteed the Trust Preferred Securities of $250.0 million of BGE Capital Trust II.

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Commitments and Contingencies

We have made substantial commitments in connection with our ~~merchant energy,~~Generation, NewEnergy, regulated electric and gas, and other nonregulated businesses. These commitments relate to:

•: purchase of electric generating capacity and energy,
•: procurement and delivery of fuels,
•: the capacity and transmission and transportation rights for the physical delivery of energy to meet our obligations to our customers, and
•: long-term service agreements, capital for construction programs, and other.

Our ~~merchant energy business enters~~Generation and NewEnergy businesses enter into various long-term contracts for the procurement and delivery of fuels to supply our generating plant requirements. In most cases, our contracts contain provisions for price escalations, minimum purchase levels, and other financial commitments. These contracts expire in various years between ~~2009~~2010 and ~~2028.~~2018. In addition, our ~~merchant energy~~NewEnergy business enters into long-term contracts for the capacity and transmission rights for the delivery of energy to meet our physical obligations to our customers. These contracts expire in various years between ~~2009~~2010 and 2030.

Our ~~merchant energy business~~Generation and NewEnergy businesses also ~~has~~have committed to long-term service agreements and other purchase commitments for our plants.

Our regulated electric business enters into various long-term contracts for the procurement of electricity. ~~As of September 30, 2009, these~~These contracts expire between 2010 and 2012 and represent BGE's estimated requirements ~~for residential customers~~ as follows:

Contract Duration


From ~~September 30, 2009 to September 2010~~	~~100~~	%
~~From October~~April 1, 2010 to May 2011	75100	%
From June 2011 to September 2011	5075
From October 2011 to May 2012	50
From June 2012 to September 2012	25

The cost of power under these contracts is recoverable under the Provider of Last Resort ~~settlement approved by~~agreement reached with the Maryland ~~PSC and in accordance with Maryland law.~~PSC.

Our regulated gas business enters into various long-term contracts for the procurement, transportation, and storage of gas. Our regulated gas business has gas procurement contracts that expire between ~~2009~~2010 and 2011, and transportation and storage contracts that expire between 2010 and 2027. The cost of gas under these contracts is recoverable under BGE's gas cost adjustment clause discussed inNote 1 of our ~~2008~~2009 Annual Report on Form 10-K.

~~Our other nonregulated businesses have committed to gas purchases, as well as to contribute additional capital for construction programs and joint ventures in which they have an interest.~~

We have also committed to long-term service agreements and other obligations related to our information technology systems.

At ~~September 30, 2009,~~March 31, 2010, the total amount of commitments was ~~$5,371.9 million.~~$6.2 billion. These commitments are primarily related to our ~~merchant energy business.~~Generation and NewEnergy businesses.

Long-Term Power Sales Contracts

We enter into long-term power sales contracts in connection with our load-serving activities. We also enter into long-term power sales contracts associated with certain of our power plants. Our load-serving power sales contracts extend for terms through 2019 and provide for the sale of energy to electricity distribution utilities and certain retail customers. Our power sales contracts associated with power plants we own extend for terms into ~~2017~~2016 and provide for the sale of all or a portion of the actual output of certain of our power plants. Substantially all long-term contracts were executed at pricing that approximated market rates, including profit margin, at the time of execution.

Contingencies

Litigation

In the normal course of business, we are involved in various legal proceedings. We discuss the significant matters below.

Merger with MidAmerican

Beginning September 18, 2008, seven shareholders of Constellation Energy filed lawsuits in the Circuit Court for Baltimore City, Maryland challenging the then-pending merger with MidAmerican. Four similar suits were filed by other shareholders of Constellation Energy in the United States District Court for the District of Maryland.

The lawsuits claim that the merger consideration was inadequate and did not maximize value for shareholders, that the sales process leading up to the merger was ~~unreasonably short and procedurally~~ flawed, and that unreasonable deal protection devices were agreed to in order to ward off competing ~~bids and coerce shareholders into accepting the merger.~~bids. The federal lawsuits also assert that the conversion of the Preferred Stock issued to MidAmerican into debt is not permitted under Maryland law. The lawsuits seek declaratory judgments establishing the unenforceability of the merger based on the alleged breaches of duty, injunctive relief to enjoin the merger, rescission of the merger or rescissory damages, the imposition of a constructive trust in favor of shareholders of any benefits received by the individual members of the

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~~Board of Directors of Constellation Energy, and reasonable costs and expenses, including attorney's fees.~~

The termination of the MidAmerican merger renders moot the claims attempting to enjoin the merger with MidAmerican. One of the federal merger cases was voluntarily dismissed on December 31, ~~2008. The~~2008, and the other federal merger cases ~~filed in the United States District Court for the District of Maryland~~ were dismissed as moot on May 27, 2009. Plaintiffs' counsel in six of the seven state merger cases have ~~indicated that in light of the termination of the MidAmerican merger they will be filing~~filed dismissals without prejudice toof their MidAmerican merger claims. ~~In addition, on October 27, 2009 certain counsel in~~On April 16, 2010, the ~~state~~seventh merger ~~cases jointly moved for approval~~case was dismissed without prejudice by the Court, thereby concluding these cases.

Table of a settlement regarding claims for attorneys' fees, which is pending and subject to court approval. We believe there are meritorious defenses to any claims or requests for relief that might possibly remain regarding this matter. However, we are unable at this time to determine the ultimate outcome of these lawsuits or their possible effect on our financial results.Contents

Securities Class Action

Three federal securities class action lawsuits have been filed in the United States District Courts for the Southern District of New York and the District of Maryland between September 2008 and November 2008. The cases were filed on behalf of a proposed class of persons who acquired publicly traded securities, including the Series A Junior Subordinated Debentures (Debentures), of Constellation Energy between January 30, 2008 and September 16, 2008, and who acquired Debentures in an offering completed in June 2008. The securities class actions generally allege that Constellation Energy, a number of its present or former officers or directors, and the underwriters violated the securities laws by issuing a false and misleading registration statement and prospectus in connection with Constellation Energy's June 27, 2008 offering of Debentures. The securities class actions also allege that Constellation Energy issued false or misleading statements or was aware of material undisclosed information which contradicted public statements including in connection with its announcements of financial results for 2007, the fourth quarter of 2007, the first quarter of 2008 and the second quarter of 2008 and the filing of its first quarter 2008 Form 10-Q. The securities class actions seek, among other things, certification of the cases as class actions, compensatory damages, reasonable costs and expenses, including counsel fees, and rescission damages.

The Southern District of New York granted the defendants' motion to transfer the two securities class actions filed there to the District of Maryland, and the actions have since been transferred for coordination with the securities class action filed there. On June 18, 2009, the court appointed a lead plaintiff, who filed a consolidated amended complaint on September 17, 2009. On November 17, 2009, the defendants moved to dismiss the consolidated amended complaint in its entirety. We are unable at this time to determine the ultimate outcome of the securities class actions or their possible effect on our, or BGE's financial results.

ERISA Actions

In the fall of 2008, multiple class action lawsuits were filed in the United States District Courts for the District of Maryland and the Southern District of New York against Constellation Energy; Mayo A. Shattuck III, Constellation Energy's Chairman of the Board, President and Chief Executive Officer; and others in their roles as fiduciaries of the Constellation Energy Employee Savings Plan. The actions, which have been consolidated into one action in Maryland (the Consolidated Action), allege that the defendants, in violation of various sections of ERISA, breached their fiduciary duties to prudently and loyally manage Constellation Energy Savings Plan's assets by designating Constellation Energy common stock as an investment, by failing to properly provide accurate information about the investment, by failing to avoid conflicts of interest, by failing to properly monitor the investment and by failing to properly monitor other fiduciaries. The plaintiffs seek to compel the defendants to reimburse the plaintiffs and the Constellation Energy Savings Plan for all losses resulting from the defendants' breaches of fiduciary duty, to impose a constructive trust on any unjust enrichment, to award actual damages with pre- and post-judgment interest, to award appropriate equitable relief including injunction and restitution and to award costs and expenses, including attorneys' fees. On October 2, 2009, the defendants moved to dismiss the consolidated complaint in its entirety. We are unable at this time to determine the ultimate outcome of the Consolidated Action or its possible effects on our, or BGE's, financial results.

Mercury

Since September 2002, BGE, Constellation Energy, and several other defendants have been involved in numerous actions filed in the Circuit Court for Baltimore City, Maryland alleging mercury poisoning from several sources, including coal plants formerly owned by BGE. The plants are now owned by a subsidiary of Constellation Energy. In addition to BGE and Constellation Energy, approximately 11 other defendants, consisting of pharmaceutical companies, manufacturers of vaccines, and manufacturers of Thimerosal have been sued. Approximately 70 cases, involving claims related to approximately 132 children, have been filed to date, with each claimant seeking $20 million in compensatory damages, plus punitive damages, from us.

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The claims against BGE and Constellation Energy have been dismissed in all of the cases either with prejudice based on rulings by the Court or without prejudice based on voluntary dismissals by the plaintiffs' counsel. Plaintiffs may attempt to pursue appeals of the rulings in favor of BGE and Constellation Energy once the cases are finally concluded as to all defendants. We believe that we have meritorious defenses and intend to defend the actions vigorously. However, we cannot predict the timing, or outcome, of these cases, or their possible effect on our, or BGE's, financial results.

Asbestos

Since 1993, BGE and certain Constellation Energy subsidiaries have been involved in several actions concerning asbestos. The actions are based upon the theory of "premises liability," alleging that BGE and Constellation Energy knew of and exposed individuals to an asbestos

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hazard. In addition to BGE and Constellation Energy, numerous other parties are defendants in these cases.

Approximately ~~499~~482 individuals who were never employees of BGE or Constellation Energy have pending claims each seeking several million dollars in compensatory and punitive damages. Cross-claims and ~~third-party~~third party claims brought by other defendants may also be filed against BGE and Constellation Energy in these actions. To date, most asbestos claims which have been resolved have been dismissed or resolved without any payment and a small minority have been resolved for amounts that were not material to our financial results.

BGE and Constellation Energy do not know the specific facts necessary to estimate their potential liability for these claims. The specific facts we do not know include:

•: the identity of the facilities at which the plaintiffs allegedly worked as contractors,
•: the names of the plaintiffs' employers,
•: the dates on which and the places where the exposure allegedly occurred, and
•: the facts and circumstances relating to the alleged exposure.

Until the relevant facts are determined, we are unable to estimate what our, or BGE's, liability might be. Although insurance and hold harmless agreements from contractors who employed the plaintiffs may cover a portion of any awards in the actions, the potential effect on our, or BGE's, financial results could be material.

Environmental Matters

Solid and Hazardous Waste

In 1999, the EPA proposed to add the 68th Street Dump in Baltimore, Maryland to the Superfund National Priorities List, which is its list of sites targeted for clean-up and enforcement, and sent a general notice letter to BGE and 19 other parties identifying them as potentially liable parties at the site. In March 2004, we and other potentially responsible parties formed the 68th Street Coalition and entered into consent order negotiations with the EPA to investigate clean-up options for the site under the Superfund Alternative Sites Program. In May 2006, a settlement among the EPA and 19 of the potentially responsible parties, including BGE, with respect to investigation of the site became effective. The settlement requires the potentially responsible parties, over the course of several years, to identify contamination at the site and recommend clean-up options. BGE is ~~fully~~ indemnified by a wholly owned subsidiary of Constellation Energy for most of the costs related to this settlement ~~as well as any~~and clean-up ~~costs.~~of the site. The clean-up costs will not be known until the investigation is closer to completion, which is expected by mid-2010. The completed investigation will provide a range of remediation alternatives to the EPA, and the EPA is expected to select one of the alternatives by the end of the first quarter of 2011. The clean-up costs we incur could have a material effect on our financial results.

Air Quality

In May 2007, a subsidiary of Constellation Energy entered into a consent decree with the Maryland Department of the Environment to resolve alleged violations of air quality opacity standards at three fossil fuel plants in Maryland. The consent decree requires the subsidiary to pay a $100,000 penalty, provide $100,000 to a supplemental environmental project, and install technology to control emissions from those plants.

In January 2009, the EPA issued a notice of violation (NOV) to a subsidiary of Constellation Energy, as well as the other owners and the operator of the Keystone coal-fired power plant in Shelocta, Pennsylvania. We hold an approximately 21% interest in the Keystone plant. The NOV alleges that the plant performed various capital projects beginning in 1984 without complying with the new source review permitting requirements of the Clean Air Act. The EPA also contends that the alleged failure to comply with those requirements are continuing violations under the plant's air permits. The EPA could seek civil penalties under the Clean Air Act for the alleged violations.

The owners and operator of the Keystone plant are investigating the allegations and have entered into discussions with the EPA. We believe there are meritorious defenses to the allegations contained in the NOV. However, we cannot predict the outcome of this proceeding and it is not possible to determine our actual liability, if any, at this time.

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Water Quality

In October 2007, a subsidiary of Constellation Energy entered into a consent decree with the Maryland Department of the Environment relating to groundwater contamination at a third party facility that was licensed to accept fly ash, a byproduct generated by our coal-fired plants. The consent decree requires the payment of a $1.0 million penalty, remediation of groundwater contamination resulting from the ash placement operations at the site, replacement of drinking water supplies in the vicinity of the site, and monitoring of groundwater conditions. We recorded a liability in our Consolidated Balance Sheets of approximately ~~$7.9~~$10.6 million, which includes the $1 million penalty and our estimate of probable costs to remediate contamination, replace drinking water supplies, monitor groundwater conditions, and otherwise comply with the consent decree. We have paid approximately ~~$4.4~~$5.1 million of these costs as of ~~September 30, 2009,~~March 31,

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2010, resulting in a remaining liability at ~~September 30, 2009~~March 31, 2010 of ~~$3.5~~$5.5 million. We estimate that it is reasonably possible that we could incur additional costs of up to approximately $10 million more than the liability that we accrued.

Insurance

We discuss our ~~nuclear and~~ non-nuclear insurance programs inNote 12 of our ~~2008~~2009 Annual Report on Form 10-K.

Derivative Instruments

Nature of Our Business and Associated Risks

Our business activities primarily include our ~~merchant energy business and our~~Generation, NewEnergy, regulated electric and gas ~~business.~~businesses. Our ~~merchant energy business includes:~~Generation and NewEnergy businesses include:

•: the generation of electricity from our owned and contractually-controlled physical assets,
•: the sale of power, gas, and other energy commodities to wholesale and retail customers, and
•: risk management services and energy trading activities.

Our regulated electric and gas businesses engage in electricity and gas transmission and distribution activities in Central Maryland at prices set by the Maryland PSC that are generally designed to recover our costs, including purchased fuel and energy. Substantially all of our risk management activities involving derivatives occur outside our regulated businesses.

In carrying out our ~~merchant energy~~ business activities, we purchase and sell power, fuel, and other energy-related commodities in competitive markets. These activities expose us to significant risks, including market risk from price volatility for energy commodities and the credit risks of counterparties with which we enter into contracts. The sources of these risks include, but are not limited to, the following:

•: the risks of unfavorable changes in power prices in the wholesale forward and spot markets in which we sell a portion of the power from our power generation facilities and purchase power to meet our load-serving requirements,
•: the risk of unfavorable fuel price changes for the purchase of a portion of the fuel for our generation facilities under short-term contracts or on the spot ~~market (Fuel~~market. Fuel prices can be volatile, and the price that can be obtained for power produced from such fuel may not change at the same rate ~~or direction~~ as fuel ~~costs),~~costs.
•: the risk that one or more counterparties may fail to perform under their obligations to make payments or deliver fuel or power,
•: interest rate risk associated with variable-rate debt and the fair value of fixed-rate debt used to finance our ~~operations,~~operations; and
•: foreign currency exchange rate risk associated with international investments and purchases of equipment and commodities in currencies other than U.S. dollars.

Objectives and Strategies for Using Derivatives

Risk Management Activities

To lower our exposure to the risk of unfavorable fluctuations in commodity prices, interest rates, and foreign currency rates, we routinely enter into derivative contracts, such as fixed-price forward physical purchase and sales contracts, futures, financial swaps, and option contracts traded in the over-the-counter markets or on exchanges, for hedging purposes. The objectives for entering into such hedging transactions primarily include:

•: fixing the price for a portion of anticipated future electricity sales from our generation operations,
•: fixing the price of a portion of anticipated fuel purchases for the operation of our power plants,
•: fixing the price for a portion of anticipated energy purchases to supply our load-serving customers, and
•: managing our exposure to interest rate risk and foreign currency exchange risks.

Non-Risk Management Activities

In addition to the use of derivatives for risk management purposes, we also enter into derivative contracts for trading purposes primarily ~~to achieve the following objectives:~~for:

•: optimizing the margin on surplus electricity generation and load positions and surplus fuel supply and demand positions,
•: ~~obtaining knowledge of prices~~price discovery and ~~developing expertise in less-liquid markets,~~verification, and

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•: deploying limited risk capital in an effort to generate returns.

Accounting for Derivative Instruments

The accounting requirements for derivatives ~~provide for~~require recognition of all qualifying derivative instruments on the balance sheet at fair value as either assets or liabilities.

Accounting Designation

We must evaluate new and existing transactions and agreements to determine whether they are derivatives, for which there are several possible accounting treatments. Mark-to-market is required as the default accounting treatment for all derivatives unless they qualify, and we specifically designate them, for one of the other accounting treatments. Derivatives designated for any of the elective accounting treatments must meet specific, restrictive criteria,

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both at the time of designation and on an ongoing basis. The permissible accounting treatments include:

•: normal purchase normal sale (NPNS),
•: cash flow hedge,
•: fair value hedge, and
•: mark-to-market.

We discuss our accounting policies for derivatives and hedging activities and their impacts on our financial statements inNote 1 toof our ~~2008~~2009 Annual Report on Form 10-K.

NPNS

We elect NPNS accounting for derivative contracts that provide for the purchase or sale of a physical commodity that will be delivered in quantities expected to be used or sold over a reasonable period in the normal course of business. Once we elect NPNS classification for a given contract, we cannot subsequently change the election and treat the contract as a derivative using mark-to-market or hedge accounting.

Cash Flow Hedging

We generally elect cash flow hedge accounting for most of the derivatives that we use to hedge market price risk for our physical energy delivery activities because hedge accounting more closely aligns the timing of earnings recognition and cash flows for the underlying business activities. Management monitors the potential impacts of commodity price changes and, where appropriate, may enter into or close out (via offsetting transactions) derivative transactions designated as cash flow hedges.

Commodity Cash Flow Hedges

~~Our merchant energy business has~~We have designated fixed-price forward contracts as cash-flow hedges of forecasted sales of energy and forecasted purchases of fuel and energy for the years ~~2009~~2010 through 2016. ~~Our merchant energy business~~We had net unrealized pre-tax losses on these cash-flow hedges recorded in "Accumulated other comprehensive loss" of ~~$1,323.1~~$1,146.4 million at ~~September 30, 2009~~March 31, 2010 and ~~$2,614.9~~$951.3 million at December 31, ~~2008.~~2009.

We expect to reclassify ~~$941.8~~$951.2 million of net pre-tax losses on cash-flow hedges from "Accumulated other comprehensive loss" into earnings during the next twelve months based on market prices at ~~September 30, 2009.~~March 31, 2010. However, the actual amount reclassified into earnings could vary from the amounts recorded at ~~September 30, 2009,~~March 31, 2010, due to future changes in market prices.

When we determine that a forecasted transaction originally hedged has become probable of not occurring, we reclassify net unrealized gains or losses associated with those hedges from "Accumulated other comprehensive loss" to earnings. We recognized in earnings the following pre-tax amounts on such contracts:

Quarter Ended
September 30,
Nine Months
Ended
September 30,

2009
2008
2009
2008

(In millions)

Pre-tax (losses) gains
$ — $ 17.0 $ (241.0 ) $ 17.7

Quarter ended March 31,	2010			2009


	(In millions)
Pre-tax losses	$	(1.4	)	$	(166.4	)

The pre-tax loss reclassified in 2009 resulted from the sale of a majority of our international commodities operation and our termination of certain contracts as part of our efforts to improve liquidity and reduce risk. The forecasted transactions associated with previously designated cash-flow hedge contracts were deemed probable of not occurring.

Interest Rate Swaps Designated as Cash Flow Hedges

We use interest rate swaps designated as cash flow hedges to manage our interest rate exposures associated with new debt issuances and to manage our exposure to fluctuations in interest rates on variable rate debt. The effective portion of gains and losses on these interest rate cash flow hedges, net of associated deferred income tax effects, is recorded in "Accumulated other comprehensive loss" in our Consolidated Statements of Comprehensive Income (Loss). We reclassify gains and losses on the hedges from "Accumulated other comprehensive loss" into "Interest expense" in our Consolidated Statements of Income (Loss) during the periods in which the interest payments being hedged occur.

Accumulated other comprehensive loss includes net unrealized pre-tax gains on interest rate cash-flow hedges of prior debt issuances totaling ~~$11.9~~$7.4 million at ~~September 30, 2009~~March 31, 2010 and ~~$12.0~~$11.3 million at December 31, ~~2008.~~2009. We expect to reclassify ~~$2.3~~$0.6 million of pre-tax net gains on these cash-flow hedges from "Accumulated other comprehensive loss" into "Interest expense" during the next twelve months. We had no hedge ineffectiveness on these swaps.

~~Table of Contents~~

Fair Value Hedging

We elect fair value hedge accounting for a limited portion of our derivative contracts including certain interest rate ~~swaps and certain forward contracts and price and basis swaps associated with natural gas fuel in storage.~~swaps. The objectives for electing fair value hedging in these situations are to manage our exposure and to optimize the mix of our fixed and floating-rate ~~debt, and to hedge the value of our natural gas in storage. We did not have any fair value hedges related to the value of our natural gas in storage during the second and third quarters of 2009.~~debt.

Interest Rate Swaps Designated as Fair Value Hedges

We use interest rate swaps designated as fair value hedges to optimize the mix of fixed and floating-rate debt. We record any gains or losses on swaps that qualify for fair value hedge accounting treatment, as well as changes in the fair value of the debt being hedged, in "Interest expense." We record changes in fair value of the swaps in "Derivative assets and liabilities" and changes in the fair value of the debt in "Long-term debt" in our Consolidated Balance Sheets. In addition, we record the difference between interest on hedged fixed-rate debt and floating-rate swaps in "Interest expense" in the periods that the swaps settle.

~~During 2004, we entered into~~We have interest rate swaps qualifying as fair value hedges relating to ~~$450~~$400 million of our fixed-rate debt

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maturing in 2012 and 2015, and converted this notional amount of debt to floating-rate. The fair value of these hedges was an unrealized gain of ~~$46.8~~$44.4 million at ~~September 30, 2009~~March 31, 2010 and ~~$55.9~~$35.8 million at December 31, ~~2008~~2009 and was recorded as an increase in our "Derivative assets" and an increase in our "Long-term debt." We had no hedge ineffectiveness on these interest rate swaps. On July 15, 2009, we terminated an interest rate swap relating to $50 million of the $450 million of our fixed-rate debt and received approximately $4.5 million in cash. This transaction was recorded in the third quarter of 2009.

Hedge Ineffectiveness

For all categories of derivative instruments designated in hedging relationships, we recorded in earnings the following pre-tax gains (losses) related to hedge ineffectiveness:



	Quarter Ended September 30,						Nine Months Ended September 30,
	2009			2008			2009		2008
Quarter ended March 31,												2010		2009
	(In millions)											(In millions)
Cash-flow hedges	$	(13.2	)	$	(13.2	)	$	39.4	$	(103.0	)	$	13.3	$	29.1
Fair value hedges		—			(6.2	)		23.9		6.7			—		23.9

Total	$	(13.2	)	$	(19.4	)	$	63.3	$	(96.3	)	$	13.3	$	53.0

~~In addition, we~~We did not recognize any gain or loss during ~~the quarter or nine months ended September 30,~~2010 and 2009 ~~and 2008~~ relating to changes in value for the portion of our fair value hedges excluded from our hedge effectiveness assessment.

Mark-to-Market

We generally apply mark-to-market accounting for risk management and trading activities for which changes in fair value more closely reflect the economic performance of the underlying business activity. However, we also use mark-to-market accounting for derivatives related to the following physical energy delivery activities:

•: our nonregulated retail gas customer supply activities, which are managed using economic hedges that we have not designated as cash-flow hedges in order to match the timing of recognition of the earnings impacts of those activities to the greatest extent permissible, and
•: economic hedges of activities that require accrual accounting for which the related hedge requires mark-to-market accounting.

Quantitative Information About Derivatives and Hedging Activities

~~Background~~

Effective January 1, 2009, we adopted an accounting standard related to disclosures about derivative instruments and hedging activities. This standard does not change the accounting for derivatives; rather, it requires expanded disclosure about derivative instruments and hedging activities regarding:

•: ~~the ways in which an entity uses derivatives,~~
•: ~~the accounting for derivatives and hedging activities, and~~
•: ~~the impact that derivatives have (or could have) on an entity's financial position, financial performance, and cash flows.~~

Balance Sheet Tables

We present our derivative assets and liabilities in our Consolidated Balance Sheets on a net basis, including cash collateral, whenever we have a legally enforceable master netting agreement with a counterparty to a derivative contract. We use master netting agreements whenever possible to manage and substantially reduce our potential counterparty credit risk. The net presentation in our Consolidated Balance Sheets reflects our actual credit exposure after giving effect to the beneficial effects of these agreements and cash collateral, and our credit risk is reduced further by other forms of collateral.

The following ~~table provides~~tables provide information about the types of market risks we manage using derivatives. ~~This table~~These tables only ~~includes~~include derivatives and ~~does~~do not reflect the price risks we are hedging that arise from physical assets or nonderivative accrual contracts within our ~~generating plants, customer supply,~~Generation and ~~global commodities activities.~~

~~Table of Contents~~NewEnergy businesses.

As discussed more fully following the ~~table,~~tables, we present this information by disaggregating our net derivative assets and liabilities into gross components on a contract-by-contract basis before giving effect to the risk-reducing benefits of master netting arrangements and collateral. As a result, we must present each individual contract as an "asset value" if it is in the money or a "liability value" if it is out of the money, regardless of whether the individual contracts offset market or credit risks of other contracts in full or in part. Therefore, the gross amounts in ~~this table~~these tables do not reflect our actual economic or credit risk associated with derivatives. This gross presentation is intended only to show separately the various derivative contract types we use, such as commodities, interest rate, and foreign exchange.

In order to identify how our derivatives impact our financial position, at the bottom of the ~~table~~tables we provide a reconciliation of the gross fair value components to the net fair value amounts as presented in theFair Value Measurements note and our Consolidated Balance Sheets.

The gross asset and liability values in the ~~table~~tables below are segregated between those derivatives designated in qualifying hedge accounting relationships and those not designated in hedge accounting relationships. Derivatives not designated in hedging relationships include our NewEnergy retail gas ~~customer supply operation,~~operations, economic hedges of accrual activities, the total return swaps entered into to effect the sale of the international commodities and Houston-based gas trading operations, ~~that we have divested,~~ and risk management and trading activities which we have substantially curtailed as part of our effort to reduce risk in our business. We use the end of period accounting designation to determine the classification for each derivative position.

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As of September 30, 2009		Derivatives Designated as Hedging Instruments for Accounting Purposes					Derivatives Not Designated As Hedging Instruments for Accounting Purposes					All Derivatives Combined
As of March 31, 2010																		As of March 31, 2010	Derivatives Designated as Hedging Instruments for Accounting Purposes					Derivatives Not Designated As Hedging Instruments for Accounting Purposes					All Derivatives Combined
Contract type	Contract type	Asset Values³		Liability Values⁴			Asset Values³		Liability Values⁴			Asset Values³			Liability Values⁴			Contract type	Asset Values³		Liability Values⁴			Asset Values³		Liability Values⁴			Asset Values³			Liability Values⁴

		(In millions)																	(In millions)
	Power contracts	$	2,127.9	$	(2,943.8	)	$	16,422.9	$	(17,345.4	)	$	18,550.8		$	(20,289.2	)	Power contracts	$	2,889.0	$	(3,530.5	)	$	16,954.3	$	(17,645.2	)	$	19,843.3		$	(21,175.7	)
	Gas contracts		1,868.8		(1,305.4	)		5,412.9		(5,088.8	)		7,281.7			(6,394.2	)	Gas contracts		2,615.6		(2,342.5	)		5,945.3		(5,647.3	)		8,560.9			(7,989.8	)
	Coal contracts		33.7		(71.6	)		1,070.9		(1,090.6	)		1,104.6			(1,162.2	)	Coal contracts		19.9		(55.0	)		475.0		(486.3	)		494.9			(541.3	)
	Other commodity contracts¹		10.6		(18.3	)		200.1		(172.3	)		210.7			(190.6	)	Other commodity contracts¹		—		—			73.5		(34.4	)		73.5			(34.4	)
	Interest rate contracts		46.8		—			35.5		(52.8	)		82.3			(52.8	)	Interest rate contracts		44.4		—			30.4		(39.1	)		74.8			(39.1	)
	Foreign exchange contracts		—		—			26.9		(21.9	)		26.9			(21.9	)	Foreign exchange contracts		—		—			12.2		(9.8	)		12.2			(9.8	)

Total gross fair values	Total gross fair values	$	4,087.8	$	(4,339.1	)	$	23,169.2	$	(23,771.8	)	$	27,257.0		$	(28,110.9	)	Total gross fair values	$	5,568.9	$	(5,928.0	)	$	23,490.7	$	(23,862.1	)	$	29,059.6		$	(29,790.1	)

	Netting arrangements⁵												(26,223.6	)		26,223.6		Netting arrangements⁵												(27,878.0	)		27,878.0
	Cash collateral												(274.1	)		99.4		Cash collateral												(105.6	)		192.5

Net fair values	Net fair values											$	759.3		$	(1,787.9	)	Net fair values											$	1,076.0		$	(1,719.6	)

Net fair value by balance sheet line item:	Net fair value by balance sheet line item:																	Net fair value by balance sheet line item:
Accounts receivable²	Accounts receivable²											$	(741.2	)				Accounts receivable²											$	(341.4	)
Derivative assets—current	Derivative assets—current												582.8					Derivative assets—current												686.0
Derivative assets—noncurrent	Derivative assets—noncurrent												917.7					Derivative assets—noncurrent												731.4
Derivative liabilities—current	Derivative liabilities—current															(823.1	)	Derivative liabilities—current															(906.7	)
Derivative liabilities—noncurrent	Derivative liabilities—noncurrent															(964.8	)	Derivative liabilities—noncurrent															(812.9	)

Total Derivatives	Total Derivatives											$	759.3		$	(1,787.9	)	Total Derivatives											$	1,076.0		$	(1,719.6	)

1 Other commodity contracts include oil, freight, emission allowances, and weather contracts.

2 Represents the unrealized fair value of exchange traded derivatives, exclusive of cash margin posted.

3 Represents in-the-money contracts without regard to potentially offsetting out-of-the-money contracts under master netting agreements.

4 Represents out-of-the-money contracts without regard to potentially offsetting in-the-money contracts under master netting agreements.

5 Represents the effect of legally enforceable master netting agreements.

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As of December 31, 2009		Derivatives Designated as Hedging Instruments for Accounting Purposes					Derivatives Not Designated As Hedging Instruments for Accounting Purposes					All Derivatives Combined


Contract type		Asset Values³		Liability Values⁴			Asset Values³		Liability Values⁴			Asset Values³			Liability Values⁴

		(In millions)
	Power contracts	$	1,737.3	$	(2,292.1	)	$	11,729.3	$	(12,414.3	)	$	13,466.6		$	(14,706.4	)
	Gas contracts		1,860.6		(1,380.0	)		4,159.1		(3,857.1	)		6,019.7			(5,237.1	)
	Coal contracts		20.1		(40.8	)		609.5		(627.2	)		629.6			(668.0	)
	Other commodity contracts¹		1.4		(0.8	)		83.1		(32.1	)		84.5			(32.9	)
	Interest rate contracts		35.8		—			28.5		(39.9	)		64.3			(39.9	)
	Foreign exchange contracts		—		—			13.2		(9.0	)		13.2			(9.0	)

Total gross fair values		$	3,655.2	$	(3,713.7	)	$	16,622.7	$	(16,979.6	)	$	20,277.9		$	(20,693.3	)

	Netting arrangements⁵												(19,261.0	)		19,261.0
	Cash collateral												(92.6	)		125.6

Net fair values												$	924.3		$	(1,306.7	)

Net fair value by balance sheet line item:
Accounts receivable²												$	(348.7	)
Derivative assets—current													639.1
Derivative assets—noncurrent													633.9
Derivative liabilities—current																(632.6	)
Derivative liabilities—noncurrent																(674.1	)

Total Derivatives												$	924.3		$	(1,306.7	)

1 Other commodity contracts include oil, freight, emission allowances, and weather contracts.

2 Represents the unrealized fair value of exchange traded derivatives, exclusive of cash margin posted.

3 Represents in-the-money contracts without regard to potentially offsetting out-of-the-money contracts under master netting agreements.

4 Represents out-of-the-money contracts without regard to potentially offsetting in-the-money contracts under master netting agreements.

5 Represents the effect of legally enforceable master netting agreements.

The magnitude of and changes in the gross derivatives components in ~~this table~~these tables do not indicate changes in the level of derivative activities, the level of market risk, or the level of credit risk. The primary factors affecting the magnitude of the gross amounts in the ~~table~~tables are changes in commodity prices and the total number of contracts. If commodity prices change, the gross amounts could increase, even if the level of contracts stays the same, because separate presentation is required for contracts that are in the money from those that are out of the money. As a result, the gross amounts of even fully hedged positions could increase if prices change. Additionally, if the number of contracts increases, the gross amounts also could increase. Thus, the execution of new contracts to reduce economic risk could actually increase the gross amounts in the table because of the requirement to present the gross value of each individual contract separately.

~~Table of Contents~~

The primary purpose of ~~this table~~these tables is to disaggregate the risks being managed using ~~derivatives.~~derivatives by contract type and accounting treatment. In order to achieve this objective, we prepare ~~this table~~these tables by separating each individual derivative contract that is in the money from each contract that is out of the money and present such amounts on a gross basis, even for offsetting contracts that have identical quantities for the same commodity, location, and delivery period. We must also present these components excluding the substantive credit-risk reducing effects of master netting agreements and collateral. As a result, the gross "asset" and "liability" amounts for each contract type far exceed our actual economic exposure to commodity price risk and credit risk. Our actual economic exposure consists of the net derivative position combined with our nonderivative accrual contracts, such as those for load-serving, and our physical assets, such as our power plants. Our actual derivative credit risk exposure after master netting agreements and cash collateral is reflected in the net fair value amounts shown at the bottom of the ~~table~~tables above. Our total economic and credit exposures, including derivatives, are managed in a comprehensive risk framework that includes risk measures such as economic value at risk, stress testing, and maximum potential credit exposure.

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Gain and (Loss) Tables

The ~~following~~ tables below summarize the gain and loss impacts of our derivative instruments segregated into the following categories:

•: cash flow hedges,
•: fair value hedges, and
•: mark-to-market derivatives.

The tables only include this information for derivatives and do not reflect the related gains or losses that arise from generation and generation-related assets, nonderivative accrual contracts, or NPNS contracts within our Generation ~~Customer Supply,~~ and ~~Global Commodities activities,~~NewEnergy businesses, other than fair value hedges, for which we separately show the gain or loss on the hedged asset or liability. As a result, for mark-to-market and cash-flow hedge derivatives, these tables only reflect the impact of derivatives themselves and therefore do not necessarily include all of the income statement impacts of the transactions for which derivatives are used to manage risk. For a more complete discussion of how derivatives affect our financial performance, see our accounting policy for Revenues, Fuel and Purchased Energy Expenses, and Derivatives and Hedging Activities inNote 1 toof our ~~2008~~2009 Annual Report on Form 10-K.

The following ~~table presents~~tables present gains and losses on derivatives designated as cash flow hedges. As discussed more fully in our accounting policy, we record the effective portion of unrealized gains and losses on cash flow hedges in Accumulated Other Comprehensive Loss until the hedged forecasted transaction affects earnings. We record the ineffective portion of gains and losses on cash flow hedges in earnings as they occur. When the hedged forecasted transaction settles and is recorded in earnings, we reclassify the related amounts from Accumulated Other Comprehensive Loss into earnings, with the result that the combination of revenue or expense from the forecasted transaction and gain or loss from the hedge are recognized in earnings at a total amount equal to the hedged price. Accordingly, the amount of derivative gains and losses recorded in Accumulated Other Comprehensive Loss and reclassified from Accumulated Other Comprehensive Loss into earnings does not reflect the total economics of the hedged forecasted transactions. The total impact of our forecasted transactions and related hedges is reflected in our Consolidated Statements of Income (Loss).

~~Table of Contents~~

Cash Flow Hedges	Cash Flow Hedges								Quarter Ended September 30, 2009						Nine Months Ended September 30, 2009						Cash Flow Hedges	Quarter Ended March 31,


																						Gain (Loss) Recorded in AOCI							Gain (Loss) Reclassified from AOCI into Earnings						Ineffectiveness Gain (Loss) Recorded in Earnings

		Gain (Loss) Recorded in AOCI																										Statement of Income (Loss) Line Item
Contract type:	Contract type:	Quarter Ended September 30, 2009			Nine Months Ended September 30, 2009			Statement of Income (Loss) Line Item	Gain (Loss) Reclassified from AOCI into Earnings			Ineffectiveness Gain (Loss) Recorded in Earnings			Gain (Loss) Reclassified from AOCI into Earnings			Ineffectiveness Gain (Loss) Recorded in Earnings			Contract type:	2010			2009			Statement of Income (Loss) Line Item	2010			2009			2010			2009

		(In millions)																				(In millions)
Hedges of forecasted sales:	Hedges of forecasted sales:							Nonregulated revenues													Hedges of forecasted sales:							Nonregulated revenues
	Power contracts	$	47.0		$	309.2			$	(44.4	)	$	4.4		$	(174.0	)	$	85.4		Power contracts	$	202.5		$	161.8			$	(59.2	)	$	(92.0	)	$	21.8		$	59.8
	Gas contracts		(1.8	)		(25.7	)			(15.3	)		(1.8	)		(37.3	)		4.7		Gas contracts		(34.9	)		(31.8	)			20.2			(21.4	)		(1.1	)		2.1
	Coal contracts		—			10.0				—			—			(229.9	)		—		Coal contracts		—			10.0				—			(229.9	)		—			—
	Other commodity contracts¹		1.2			7.8				1.3			(1.1	)		(2.3	)		(6.2	)	Other commodity contracts¹		—			13.7				(0.7	)		(2.8	)		—			(3.0	)
Interest rate contracts			—			(0.3	)			(0.4	)		—			(0.6	)		—
Foreign exchange contracts	Foreign exchange contracts		—			0.3				—			—			(0.9	)		—		Foreign exchange contracts		—			0.3				—			(0.9	)		—			—

Total gains (losses)	Total gains (losses)	$	46.4		$	301.3		Total included in nonregulated revenues	$	(58.8	)	$	1.5		$	(445.0	)	$	83.9		Total gains (losses)	$	167.6		$	154.0		Total included in nonregulated revenues	$	(39.7	)	$	(347.0	)	$	20.7		$	58.9

Hedges of forecasted purchases:	Hedges of forecasted purchases:							Fuel and purchased energy expense													Hedges of forecasted purchases:							Fuel and purchased energy expense
	Power contracts	$	(104.6	)	$	(991.4	)		$	(452.5	)	$	(5.8	)	$	(1,490.9	)	$	(35.3	)	Power contracts	$	(455.5	)	$	(774.1	)		$	(203.1	)	$	(426.5	)	$	(9.3	)	$	(29.3	)
	Gas contracts		(30.6	)		123.9				14.5			(5.3	)		107.2			(2.7	)	Gas contracts		(73.6	)		175.2				78.0			25.9			—			0.7
	Coal contracts		43.4			(81.7	)			(69.8	)		(3.6	)		(135.1	)		(6.5	)	Coal contracts		(10.8	)		(84.6	)			(12.5	)		(13.3	)		1.7			(1.2	)
	Other commodity contracts²		(6.9	)		(9.0	)			(7.5	)		—			15.6			—		Other commodity contracts²		(0.2	)		1.8				(0.3	)		25.8			0.2			—
Foreign exchange contracts	Foreign exchange contracts		1.0			1.1				(0.1	)		—			—			—		Foreign exchange contracts		—			0.1				—			0.1			—			—

Total losses	Total losses	$	(97.7	)	$	(957.1	)	Total included in fuel and purchased energy expense	$	(515.4	)	$	(14.7	)	$	(1,503.2	)	$	(44.5	)	Total losses	$	(540.1	)	$	(681.6	)	Total included in fuel and purchased energy expense	$	(137.9	)	$	(388.0	)	$	(7.4	)	$	(29.8	)

Hedges of interest rates:	Hedges of interest rates:							Interest expense													Hedges of interest rates:							Interest expense
	Interest rate contracts		—			—				(0.2	)		—			—			—		Interest rate contracts		—			(0.3	)			3.9			(0.1	)		—			—

Total losses		$	—		$	—		Total included in interest expense	$	(0.2	)	$	—		$	—		$	—
Total gains																					Total gains	$	—		$	(0.3	)	Total included in interest expense	$	3.9		$	(0.1	)	$	—		$	—

Grand total (losses) gains	Grand total (losses) gains	$	(51.3	)	$	(655.8	)		$	(574.0	)	$	(13.2	)	$	(1,948.2	)	$	39.4		Grand total (losses) gains	$	(372.5	)	$	(527.9	)		$	(173.7	)	$	(735.1	)	$	13.3		$	29.1

1 Other commodity sale contracts include oil and freight contracts.

2 Other commodity purchase contracts include freight and emission allowances.

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The following table presents gains and losses on derivatives designated as fair value hedges and, separately, the gains and losses on the hedged item. As discussed earlier, we record the unrealized gains and losses on fair value hedges as well as changes in the fair value of the hedged asset or liability in earnings as they occur. The difference between ~~these amounts represents hedge ineffectiveness. Due to~~ the ~~sale of our Houston-based gas trading operation, we do not have any third quarter activity under~~gains and losses on derivatives designated as fair value hedges ~~related to gas contracts.~~and the gains and losses on the hedged item represents the recognition of locked-in gains on terminated interest rate swaps.

Fair Value Hedges	Fair Value Hedges		Quarter Ended September 30, 2009					Nine Months Ended September 30, 2009					Fair Value Hedges	Quarter Ended March 31,


															Amount of Gain (Loss) Recognized in Income on Derivative				Amount of Gain (Loss) Recognized in Income on Hedged Item
Contract type:	Contract type:	Statement of Income (Loss) Line Item	Gain (Loss) Recognized in Income on Derivative		Gain (Loss) Recognized in Income on Hedged Item			Gain (Loss) Recognized in Income on Derivative		Gain (Loss) Recognized in Income on Hedged Item			Contract type:	Statement of Income (Loss) Line Item	2010		2009		2010			2009

			(In millions)												(In millions)
Commodity contracts:	Commodity contracts:												Commodity contracts:
	Gas contracts	Nonregulated revenues	$	—	$	—		$	40.6	$	(16.7	)	Gas contracts	Nonregulated revenues	$	—	$	40.6	$	—		$	(16.7	)
Interest rate contracts	Interest rate contracts	Interest expense		21.8		(21.5	)		6.3		(6.0	)	Interest rate contracts	Interest expense		13.2		4.9		(11.1	)		(4.9	)

Total gains (losses)	Total gains (losses)		$	21.8	$	(21.5	)	$	46.9	$	(22.7	)	Total gains (losses)		$	13.2	$	45.5	$	(11.1	)	$	(21.6	)

The following table presents gains and losses on mark-to-market ~~derivatives, contracts that have not been designated as hedges for accounting purposes.~~derivatives. As discussed more fully inNote 1 to our ~~2008~~2009 Annual Report on Form 10-K, we record the unrealized gains and losses on mark-to-market derivatives in earnings as they occur. While we use mark-to-market accounting for risk management and trading activities because changes in fair value more closely reflect the economic performance of the activity, we also use mark-to-market accounting for certain derivatives related to

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portions of our physical energy delivery activities. Accordingly, the total amount of gains and losses from mark-to-market derivatives does not necessarily reflect the total economics of related transactions.

Mark-to-Market Derivatives	Mark-to-Market Derivatives		Quarter Ended September 30, 2009			Nine Months Ended September 30, 2009			Mark-to-Market Derivatives	Quarter Ended March 31,


											Amount of Gain (Loss) Recorded in Income

										Statement of Income (Loss) Line Item
Contract type:	Contract type:	Statement of Income (Loss) Line Item	Gain (Loss) Recorded in Income						Contract type:	Statement of Income (Loss) Line Item	2010			2009

			(In millions)								(In millions)
Commodity contracts:	Commodity contracts:								Commodity contracts:
	Power contracts	Nonregulated revenues	$	65.4		$	212.4		Power contracts	Nonregulated revenues	$	(64.9	)	$	88.6
	Gas contracts	Nonregulated revenues		(73.6	)		(353.1	)	Gas contracts	Nonregulated revenues		25.7			(162.6	)
	Coal contracts	Nonregulated revenues		3.1			12.9		Coal contracts	Nonregulated revenues		0.1			(42.3	)
	Other commodity contracts¹	Nonregulated revenues		(4.5	)		(4.1	)	Other commodity contracts¹	Nonregulated revenues		4.9			(3.9	)
	Coal contracts	Fuel and purchased energy expense		(2.1	)		(109.8	)	Coal contracts	Fuel and purchased energy expense		—			(105.5	)
Interest rate contracts	Interest rate contracts	Nonregulated revenues		(6.3	)		(26.9	)	Interest rate contracts	Nonregulated revenues		(1.1	)		(0.5	)
Foreign exchange contracts	Foreign exchange contracts	Nonregulated revenues		1.8			11.5		Foreign exchange contracts	Nonregulated revenues		(0.9	)		7.8

Total gains (losses)	Total gains (losses)		$	(16.2	)	$	(257.1	)	Total gains (losses)		$	(36.2	)	$	(218.4	)

1 Other commodity contracts ~~for the quarter ended September 30, 2009~~ include oil, freight, uranium, weather, and emission allowances. ~~For the nine months ended September 30, 2009, other commodity contracts also include freight and uranium.~~

In computing the amounts of derivative gains and losses in the above tables, we include the changes in fair values of derivative contracts up to the date of maturity or settlement of each contract. This approach facilitates a comparable presentation for both financial and physical derivative contracts. In addition, for cash flow hedges we include the impact of intra-quarter transactions (i.e., those that arise and settle within the same quarter) in both gains and losses recognized in Accumulated Other Comprehensive Loss and amounts reclassified from Accumulated Other Comprehensive Loss into earnings.

Volume of Derivative Activity

The volume of our derivatives activity is directly related to the fundamental nature and scope of our business and the risks we manage. We own or control electric generating facilities, which exposes us to both power and fuel price risk; we serve electric and gas wholesale and retail customers within our ~~customer supply~~ NewEnergy

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business, which exposes us to electricity and natural gas price risk; and we provide risk management services and engage in trading activities, which can expose us to a variety of commodity price risks. We conduct our business activities throughout the United States and internationally. In order to manage the risks associated with these activities, we are required to be an active participant in the energy markets, and we routinely employ derivative instruments to conduct our business.

Derivative instruments provide an efficient and effective way to conduct our business and to manage the associated risks. We manage our generating resources and ~~customer supply activities~~NewEnergy business based upon established policies and limits, and we use derivatives to establish a portion of our hedges and to adjust the level of our hedges from time to time. Additionally, we engage in trading activities which enable us to execute hedging transactions in a cost-effective manner. We manage those activities based upon various risk measures, including position limits, economic value at risk (EVaR) and value at risk (VaR), and we use derivatives to establish and maintain those activities within the prescribed limits. We are also using derivatives to execute, control, and reduce the overall level of our trading positions and risk as well as to manage a portion of our interest rate risk associated with debt and our foreign currency risk from non-dollar denominated transactions. Accordingly, the use of derivative instruments is integral to the conduct of our business, and derivative instruments are an important tool through which we are able to manage and mitigate the risks that are inherent in our activities.

The following ~~table presents~~tables present information designed to provide insight into the overall volume of our derivatives usage. However, the volumes presented in ~~this table~~these tables are subject to a number of limitations and should only be used as an indication of the extent of our derivatives usage and the risks they are intended to manage.

First, the volume information is not a complete representation of our market price risk because it only includes derivative contracts. Accordingly, ~~this table does~~these tables do not present a complete picture of our overall net economic exposure, and should not be interpreted as an indication of open or unhedged commodity positions, because the use of derivatives is only one of the means by which we engage in and manage the risks of our business. For example, ~~the table does~~these tables do not include power or fuel quantities and risks arising from our physical assets, non-derivative contracts, and forecasted transactions that we manage using derivatives; a portion of these volumes reduce those risks. ItThey also ~~does~~do not include volumes of commodities under nonderivative contracts that we use to serve customers or manage our risks. Our actual net economic exposure from our generating facilities and ~~customer supply~~NewEnergy activities is reduced by derivatives, and the exposure from our trading activities is managed and controlled through

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the risk measures discussed above. Therefore, the information in the ~~table~~tables below is only an indication of that portion of our business that we manage through derivatives and serves primarily to identify the extent of our derivatives activities and the types of risks that they are intended to manage.

Additionally, the disclosure of derivative quantities potentially could reveal commercially valuable or otherwise competitively sensitive information that could limit the effectiveness and profitability of our business activities. Therefore, in the ~~table~~tables below, we have computed the derivative volumes for commodities by aggregating the absolute value of net ~~open long (purchase) and short (sell)~~ positions within commodities for each year. This provides an indication of the level of derivatives activity, but it does not indicate either the direction of our position (long or short), or the overall size of our position. We believe this presentation gives an appropriate indication of the level of derivatives activity without unnecessarily revealing the size and direction of our derivatives positions.

Finally, the volume information for commodity derivatives represents "delta equivalent" quantities, not gross notional amounts. We make use of different types of commodity derivative instruments such as forwards, futures, options, and swaps, and we believe that the delta equivalent quantity is the most relevant measure of the volume associated with these commodity derivatives. The delta-equivalent quantity represents a risk-adjusted notional quantity for each contract that takes into account the probability that an option will be exercised. Therefore, the volume information for commodity derivatives represents the delta equivalent quantity of those contracts, computed on the basis described above. For interest rate contracts and foreign currency contracts we have presented the notional amounts of such contracts in the ~~table~~tables below.

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The following ~~table presents~~tables present the volume of our derivative activities as of ~~September 30,~~March 31, 2010 and December 31, 2009 shown by contractual settlement year.

Quantities¹ Under Derivative Contracts									As of September 30, 2009								As of March 31, 2010


Contract Type (Unit)	2009		2010		2011		2012		2013		Thereafter		Total		2010		2011		2012		2013		2014		Thereafter		Total

	(In millions)														(In millions)
Power (MWh)		10.1		28.8		16.0		2.4		1.2		1.2		59.7		26.3		28.7		0.5		2.7		4.2		1.0		63.4
Gas (MMBTU)		20.6		34.7		42.5		8.0		9.9		44.3		160.0		42.2		64.0		25.4		17.0		47.1		18.8		214.5
Coal (Tons)		1.9		4.2		2.6		—		—		—		8.7		4.0		8.0		0.6		—		—		—		12.6
Oil (BBL)		0.1		—		—		—		—		—		0.1		0.3		0.1		0.2		—		—		—		0.6
Emission Allowances (Tons)		10.0		0.2		—		—		—		—		10.2		10.0		—		—		—		—		—		10.0
Interest Rate Contracts	$	795.1	$	944.4	$	45.6	$	629.5	$	93.2	$	425.0	$	2,932.8	$	582.3	$	29.4	$	321.3	$	1.8	$	455.0	$	—	$	1,389.8
Foreign Exchange Rate Contracts	$	4.2	$	51.1	$	58.5	$	16.7	$	16.7	$	32.3	$	179.5	$	13.5	$	84.9	$	7.0	$	16.7	$	16.8	$	15.5	$	154.4

Quantities¹ Under Derivative Contracts			As of December 31, 2009


Contract Type (Unit)	2010		2011		2012		2013		2014		Thereafter		Total

	(In millions)
Power (MWh)		32.7		1.6		3.2		3.2		0.1		0.9		41.7
Gas (MMBTU)		37.3		37.4		22.1		21.0		22.7		21.3		161.8
Coal (Tons)		3.9		3.9		0.2		—		—		—		8.0
Oil (BBL)		0.3		—		—		—		—		—		0.3
Emission Allowances (Tons)		7.2		—		—		—		—		—		7.2
Interest Rate Contracts	$	972.3	$	140.6	$	440.5	$	58.2	$	255.0	$	200.0	$	2,066.6
Foreign Exchange Rate Contracts	$	27.9	$	72.4	$	16.7	$	16.7	$	16.8	$	15.5	$	166.0

1 Amounts in the ~~table~~tables are only intended to provide an indication of the level of derivatives activity and should not be interpreted as a measure of any derivative position or overall economic exposure to market risk. Quantities are expressed as "delta equivalents" on an absolute value basis by contract type by year. Additionally, quantities relate only to derivatives and do not include potentially offsetting quantities associated with physical assets and nonderivative accrual contracts.

In addition to the commodities in the tables above, we also hold derivative instruments related to weather ~~and freight~~ that are insignificant relative to the overall level of our derivative activity.

Credit-Risk Related Contingent Features

Certain of our derivative instruments contain provisions that would require additional collateral upon a credit-related event such as an adequate assurance provision or a credit rating decrease in the senior unsecured debt of Constellation Energy. The amount of collateral we could be required to post would be determined by the fair value of contracts containing such provisions that represent a net liability, after offset for the fair value of any asset contracts with the same counterparty under master netting agreements and any other collateral already posted. This collateral amount is a component of, and is not in addition to, the total collateral we could be required to post for all contracts upon a credit rating decrease.

The following ~~table presents~~tables present information related to these ~~derivatives.~~derivatives at March 31, 2010 and December 31, 2009. Based on contractual provisions, we estimate that if Constellation Energy's senior unsecured debt were downgraded, our total contingent collateral obligation for derivatives in a net liability position was $0.2 billion as of ~~September 30,~~March 31, 2010 and at December 31, 2009, which represents the additional collateral that we could be required to post with counterparties, including both cash collateral and letters of credit, in the event of a credit downgrade to below investment grade. These amounts are associated with net derivative liabilities totaling ~~$1.2~~$1.4 billion at March 31, 2010 and $1.0 billion at December 31, 2009 after reflecting legally binding master netting agreements and collateral already posted.

We present the gross fair value of derivatives in a net liability position that have credit-risk-related contingent features in the first column in the ~~table~~tables below. This gross fair value amount represents only the out-of-the-money contracts containing such features that are not fully collateralized by cash on a stand-alone basis. Thus, this amount does not reflect the offsetting fair value of in-the-money contracts under ~~legally-~~

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~~binding~~legally-binding master netting agreements with the same counterparty, as shown in the second column in the ~~table.~~tables. These in-the-money contracts would offset the amount of any gross liability that could be required to be collateralized, and as a result, the actual potential collateral requirements would be based upon the net fair value of derivatives containing such features, not the gross amount. The amount of any possible

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contingent collateral for such contracts in the event of a downgrade would be further reduced to the extent that we have already posted collateral related to the net liability.

Because the amount of any contingent collateral obligation would be based on the net fair value of all derivative contracts under each master netting agreement, we believe that the "net fair value of derivative contracts containing this feature" as shown in the ~~table~~tables below is the most relevant measure of derivatives in a net liability position with credit-risk-related contingent features. This amount reflects the actual net liability upon which existing collateral postings are computed and upon which any additional contingent collateral obligation would be based.

Credit-Risk Related Contingent Feature							As of March 31, 2010


Gross Fair Value of Derivative Contracts Containing This Feature¹		Offsetting Fair Value of In-the-Money Contracts Under Master Netting Agreements²			Net Fair Value of Derivative Contracts Containing This Feature³		Amount of Posted Collateral⁴		Contingent Collateral Obligation⁵

(In billions)
$	11.7	$	(10.3	)	$	1.4	$	1.1	$	0.2

Credit-Risk Related Contingent Feature	Credit-Risk Related Contingent Feature						As of September 30, 2009				Credit-Risk Related Contingent Feature						As of December 31, 2009


Gross Fair Value of Derivative Contracts Containing This Feature¹	Gross Fair Value of Derivative Contracts Containing This Feature¹	Offsetting Fair Value of In-the-Money Contracts Under Master Netting Agreements²			Net Fair Value of Derivative Contracts Containing This Feature³		Amount of Posted Collateral⁴		Contingent Collateral Obligation⁵		Gross Fair Value of Derivative Contracts Containing This Feature¹	Offsetting Fair Value of In-the-Money Contracts Under Master Netting Agreements²			Net Fair Value of Derivative Contracts Containing This Feature³		Amount of Posted Collateral⁴		Contingent Collateral Obligation⁵

(In billions)	(In billions)										(In billions)
$	12.2	$	(11.0	)	$	1.2	$	0.8	$	0.2	8.6	$	(7.6	)	$	1.0	$	0.7	$	0.2

1 Amount represents the gross fair value of out-of-the-money derivative contracts containing credit-risk-related contingent features that are not fully collateralized by posted cash collateral on an individual, contract-by-contract basis ignoring the effects of master netting agreements.

2 Amount represents the offsetting fair value of in-the-money derivative contracts under legally-enforceable master netting agreements with the same counterparty, which reduces the amount of any liability for which we potentially could be required to post collateral.

3 Amount represents the net fair value of out-of-the-money derivative contracts containing credit-risk related contingent features after considering the mitigating effects of offsetting positions under master netting arrangements and reflects the actual net liability upon which any potential contingent collateral obligations would be based.

4 Amount includes cash collateral posted of ~~$99.4~~$192.5 million and letters of credit of ~~$691.1 million.~~$889.3 million at March 31, 2010 and $125.6 million and letters of credit of $585.2 million at December 31, 2009.

5 Amounts represent the additional collateral that we could be required to post with counterparties, including both cash collateral and letters of credit, in the event of a credit downgrade to below investment grade after giving consideration to offsetting derivative and non-derivative positions under master netting agreements.

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Concentrations of Derivative-Related Credit Risk

Constellation Energy's wholesale and retail credit risk management policies establish the guidelines under which we extend unsecured credit to counterparties and customers. Based on the counterparty analysis and limits established by Constellation Energy, collateral or other security may be required to enter into transactions based on the potential exposure. Under most agreements we have entered into, collateral is in the form of cash or letters of credit. These forms of collateral are held by us and can be drawn upon should a counterparty default on its obligations under its agreement.

As a best practice, we enter into commodity master agreements and cross-commodity netting agreements in order to achieve the benefits of netting in terms of exposure and collateral capital reductions. Where beneficial to the risk profile of the company, we will seek credit protections that include upfront collateral, margining, material adverse change clauses (based on credit ratings downgrades or other financial ratios events), and adequate assurances clauses inWe discuss our ~~master agreements that can be utilized to request security from our counterparties in order to cover our potential risk of loss.~~

~~We consider a significant concentration~~concentrations of credit risk, including derivative-related positions, inNote 1to ~~be any single obligor or counterparty whose concentration exceeds~~our 2009 Annual Report on Form 10-K. As of March 31, 2010, we had two counterparties that exceeded 10% of our total credit ~~exposure. As of September 30,~~exposure, including derivative-related positions. We had an approximate 14% exposure related to the power purchase agreement executed in 2009 ~~no single counterparty concentration comprises more than 10% of the total~~with CENG, and we had an approximate 11% exposure ~~of the portfolio, and no collection of counterparties based in a single country other than the United States comprises more than 10% of the total exposure of the portfolio.~~related to an electric cooperative customer.

Fair Value Measurements

~~Fair value is the price that we would receive to sell an asset or pay to transfer a liability in an orderly transaction between market participants~~Recurring Measurements

Our assets and liabilities measured at ~~the measurement date (exit price).~~

~~The accounting requirements for~~ fair value ~~measurements include~~on a recurring basis consist of the following (BGE's assets and liabilities measured at fair value ~~hierarchy that prioritizes~~on a recurring basis are immaterial):

			As of March 31, 2010

			Assets			Liabilities

			(In millions)
Cash equivalents			$	1,325.8		$	—
Equity securities				40.3			—
Derivative instruments:
	Classified as derivative assets and liabilities:
		Current		686.0			(906.7	)
		Noncurrent		731.4			(812.9	)

		Total classified as derivative assets and liabilities		1,417.4			(1,719.6	)
	Classified as accounts receivable*			(341.4	)		—

	Total derivative instruments			1,076.0			(1,719.6	)

Total recurring fair value measurements			$	2,442.1		$	(1,719.6	)

* Represents the ~~inputs used to measure fair value. The three levels of the fair value hierarchy are as follows:~~

•: ~~Level 1—Unadjusted quoted prices available in active markets at the measurement date for identical assets or liabilities.~~

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•: ~~Level 2—Pricing inputs, other than quoted prices included within Level 1, which are either directly or indirectly observable as of the reporting date.~~
•: ~~Level 3—Significant inputs that are generally not observable from market activity.~~

~~We determine the~~unrealized fair value of ~~our assets~~exchange traded derivatives, exclusive of cash margin posted.

Cash equivalents represent exchange-traded money market funds which are included in "Cash and ~~liabilities using unadjusted quoted prices~~cash equivalents" in ~~active markets (Level 1) or pricing inputs that~~the Consolidated Balance Sheets. Equity securities represent mutual fund investments which are ~~observable (Level 2) whenever that information is available. We use unobservable inputs (Level 3)~~included in "Other assets" in the Consolidated Balance Sheets. Derivative instruments represent unrealized amounts related to ~~estimate fair value only when relevant observable inputs are not available.~~

all derivative positions, including futures, forwards, swaps, and options. We classify ~~assets and liabilities within~~exchange-listed contracts as part of "Accounts Receivable" in our Consolidated Balance Sheets. We classify the ~~fair value hierarchy based on the lowest level~~remainder of ~~input that is significant to the fair value measurement of each individual asset and liability taken~~our derivative contracts as ~~a whole. We determine fair value for assets and liabilities classified as Level 1 by multiplying the market price by the quantity of the asset~~"Derivative assets" or liability. We primarily determine fair value measurements classified as Level 2 or Level 3 using the income valuation approach, which involves discounting estimated cash flows using assumptions that market participants would use"Derivative liabilities" in ~~pricing the asset or liability.~~our Consolidated Balance Sheets.

We present all derivatives recorded at fair value net with the associated fair value cash collateral. This presentation of the net position reflects our credit exposure for our on-balance sheet positions but excludes the impact of any off-balance sheet positions and collateral. Examples of off-balance sheet positions and collateral include in-the-money accrual contracts for which the right of offset exists in the event of default and letters of credit. We discuss our letters of credit in more detail in theFinancing Activities section.

~~Recurring Measurements~~Table of Contents

~~BGE's~~ The table below sets forth by level within the fair value hierarchy the gross components of the Company's assets and liabilities that were measured at fair value on a recurring basis ~~are immaterial.~~as of March 31, 2010. Our ~~merchant energy business segment's assets and liabilities measured at fair value on a recurring basis consist of the following:~~

As of
September 30, 2009

Assets
Liabilities

(In millions)

Cash equivalents
$ 596.8 $ —
Debt and equity securities
1,228.3 —
Derivative instruments:

Classified as derivative assets and liabilities:

Current
582.8 (823.1 )

Noncurrent
917.7 (964.8 )

Total classified as derivative assets and liabilities
1,500.5 (1,787.9 )

Classified as accounts receivable*
(741.2 ) —

Total derivative instruments
759.3 (1,787.9 )

Total recurring fair value measurements
$ 2,584.4 $ (1,787.9 )

* Represents the unrealized fair value of exchange traded derivatives, exclusive of cash margin posted.

Cash equivalents represent money market mutual funds which are included in "Cash and cash equivalents" and "Nuclear decommissioning trust funds" in the Consolidated Balance Sheets. Debt and equity securities primarily represent available-for-sale investments which are included in "Nuclear decommissioning trust funds" and "Other assets" in the Consolidated Balance Sheets. Derivative instruments represent unrealized amounts related to all derivative positions, including futures, forwards, swaps, and options. We classify exchange-listed contracts as part of "Accounts Receivable" in our Consolidated Balance Sheets. We classify the remainder of our derivative contracts as "Derivative assets" or "Derivative liabilities" in our Consolidated Balance Sheets.

~~The table below disaggregates our~~ net derivative assets and liabilities are disaggregated on a gross contract-by-contract basis. ~~Each individual asset or liability that is remeasured at~~These gross balances are intended solely to provide information on sources of inputs to fair value ~~on a recurring basis is required to be presented in this table~~ and ~~classified, in its entirety, within the appropriate level in the~~proportions of fair value ~~hierarchy.~~involving objective versus subjective valuations and do not represent either our actual credit exposure or net economic exposure. Therefore, the objective of this table is to provide information about how each individual derivative contract is valued within the fair value hierarchy, regardless of whether a particular contract is eligible for netting against other contracts or whether it has been collateralized.

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The table below sets forth by level within the fair value hierarchy the gross components of the Company's assets and liabilities that were measured at fair value on a recurring basis as of September 30, 2009. These gross balances are intended solely to provide information on sources of inputs to fair value and proportions of fair value involving objective versus subjective valuations and do not represent either our actual credit exposure or net economic exposure.

At September 30, 2009
Level 1
Level 2
Level 3
Netting and
Cash Collateral*
Total Net
Fair Value

(In millions)

Cash equivalents
$ 576.6 $ 20.2 $ — $ — $ 596.8
Debt and equity securities:

Marketable equity securities
324.6 — — — 324.6

Mutual funds / common collective trusts
53.2 564.7 — — 617.9

Corporate debt securities
— 169.2 — — 169.2

U.S. Government agencies
— 45.0 — — 45.0

U.S. Treasuries
20.0 — — — 20.0

State municipal bonds
— 51.6 — — 51.6

Debt and equity securities
397.8 830.5 — — 1,228.3
Derivative assets
325.1 24,133.4 2,798.5 (26,497.7 ) 759.3
Derivative liabilities
(391.7 ) (24,680.1 ) (3,039.1 ) 26,323.0 (1,787.9 )

Net derivative position
(66.6 ) (546.7 ) (240.6 ) (174.7 ) (1,028.6 )

Total
$ 907.8 $ 304.0 $ (240.6 ) $ (174.7 ) $ 796.5

At March 31, 2010		Level 1			Level 2			Level 3			Netting and Cash Collateral*			Total Net Fair Value


		(In millions)
Cash equivalents		$	1,325.8		$	—		$	—		$	—		$	1,325.8
Equity securities			40.3			—			—			—			40.3
Derivative assets:
	Power contracts		—			18,913.5			929.8
	Gas contracts		138.2			8,254.6			168.1
	Coal contracts		—			487.2			7.7
	Other commodity contracts		2.0			69.0			2.5
	Interest rate contracts		—			74.8			—
	Foreign exchange contracts		—			—			12.2

	Total derivative assets		140.2			27,799.1			1,120.3			(27,983.6	)		1,076.0

Derivative liabilities:
	Power contracts		—			(19,758.9	)		(1,416.8	)
	Gas contracts		(135.9	)		(7,849.6	)		(4.3	)
	Coal contracts		—			(539.2	)		(2.1	)
	Other commodity contracts		(2.3	)		(29.6	)		(2.5	)
	Interest rate contracts		—			(39.1	)		—
	Foreign exchange contracts		—			—			(9.8	)

Total derivative liabilities			(138.2	)		(28,216.4	)		(1,435.5	)		28,070.5			(1,719.6	)

	Net derivative position		2.0			(417.3	)		(315.2	)		86.9			(643.6	)

Total		$	1,368.1		$	(417.3	)	$	(315.2	)	$	86.9		$	722.5

* We present our derivative assets and liabilities in our Consolidated Balance Sheets on a net basis. We net derivative assets and liabilities, including cash collateral, when a legally enforceable master netting agreement exists between us and the counterparty to a derivative contract. At ~~September 30, 2009,~~March 31, 2010, we included ~~$274.1~~$105.6 million of cash collateral held and ~~$99.4~~$192.5 million of cash collateral posted (excluding margin posted on exchange traded derivatives) in netting amounts in the above table.

The factors that cause changes in the gross components of the ~~derivatives~~derivative amounts in the ~~table~~tables above are unrelated to the existence or level of actual market or credit risk from our operations. The gross components of the derivatives amounts in this table decreased from the corresponding amounts as of December 31, 2008, due to changes in commodity prices and the number of derivative contracts outstanding. We describe the primary factors that change the gross components below.

We prepared this table by separating each individual derivative contract that is in the money from each contract that is out of the ~~money ignoring~~money. We also did not reflect master netting agreements and ~~collateral.~~collateral for our derivatives. As a result, the gross "asset" and "liability" amounts ~~under~~in each of the three fair value levels far exceed our actual economic exposure to commodity price risk and credit risk. Our actual economic exposure consists of the net derivative position combined with our nonderivative accrual contracts, such as those for load-serving, and our physical assets, such as our power plants. Our ~~actual~~ credit risk exposure related to our derivative positions is reflected in the net derivative asset and derivative liability amounts shown in the Total Net Fair Value column.

Increases and decreases in the gross components presented in each of the levels in this table ~~also~~ do not indicate changes in the level of derivative activities. Rather, the primary factors affecting the gross amounts are commodity prices and the total number of contracts. If commodity prices change, the gross amounts could increase, even if the level of contracts stays the same, because separate presentation is required for contracts that are in the money from those that are out of the money. As a result, even

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fully hedged positions could exhibit increases in the gross amounts if prices change. Additionally, if the number of contracts increases, the gross amounts also could increase. Thus, the execution of new contracts to reduce economic risk could actually increase the gross amounts in the table because of the required separation of contracts discussed above.

Cash equivalents ~~are primarily comprised~~consist of ~~exchange traded~~exchange-traded money market funds, ~~and money market mutual funds. These instruments~~which are valued ~~based upon~~by multiplying unadjusted quoted prices in active markets by the quantity of the asset and are classified within Level 1. ~~Cash equivalents classified in Level 2 are held within our nuclear decommissioning trust funds and are valued based on fund share price, which is observable on a less frequent basis.~~

~~Debt and equity~~Equity securities ~~include trust assets securing certain executive benefits, other marketable securities, and our nuclear decommissioning trust funds. Trust assets securing certain executive benefits~~ consist of mutual funds, which are valued ~~based upon~~by multiplying unadjusted quoted prices in active markets by the quantity of the asset and are classified within Level 1. ~~Our other marketable securities consist of marketable equity securities, which are valued based on unadjusted quoted prices in~~

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~~active markets and are classified within Level 1. Nuclear decommissioning trust funds consist of a number of different types of securities, including the following:~~

•: ~~marketable equity securities, mutual funds, and United States Treasury securities are classified within Level 1 because they are valued based on unadjusted quoted prices in active markets,~~
•: fixed income securities other than United States Treasury securities are classified within Level 2 because these instruments are traded in markets that are less active than the markets for equity securities and United States Treasury securities, and
•: ~~common collective trusts are classified within Level 2 because they are valued based on the fund share price, which is observable on a less frequent basis.~~

Derivative instruments include exchange-traded and bilateral contracts. Exchange-traded derivative contracts include futures and ~~certain~~ options. Bilateral derivative contracts include swaps, forwards, ~~certain~~ options and ~~complex~~ structured transactions. We utilize models to measure the fair value of bilateral derivative contracts. Generally, we use similar models to value similar instruments. Valuation models utilize various inputs, which include quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in markets that are not active, other observable inputs for the asset or liability, and market-corroborated inputs, which are inputs derived principally from or corroborated by observable market data by correlation or other means. However, the primary input to our valuation models is the forward commodity price. We have classified derivative contracts within the fair value hierarchy as follows:

•: Exchange-traded derivative contracts valued ~~based on~~by multiplying unadjusted quoted prices in active markets by the quantity of the asset or liability are classified within Level 1.
•: Exchange-traded derivative contracts valued using pricing inputs based upon market quotes or market transactions are classified within Level 2. These contracts generally trade in less active markets ~~due to the length of the contracts~~ (i.e., for certain contracts the exchange sets the closing price, which may not be reflective of an actual trade).
•: Bilateral derivative contracts where observable inputs are available for substantially the full term and value of the asset or liability are classified within Level 2.
•: Bilateral derivative contracts with a lower availability of pricing information are classified in Level 3. In addition, ~~complex or~~ structured transactions, such as certain options, may require us to use internally-developed model inputs, which might not be observable in or corroborated by the market, to determine fair value. When such unobservable inputs have more than an insignificant impact on the measurement of fair value, we ~~also~~ classify the instrument within Level 3.

During the quarter ended March 31, 2010, there were no significant transfers of derivatives between Level 1 and Level 2 of the fair value hierarchy.

We utilize models based upon the income approach to measure the fair value of derivative contracts classified as Level 2 or Level 3. Generally, we use similar models to value similar instruments. In order to determine ~~the~~ fair value, ~~of derivatives,~~ we utilize various inputs and factors including market data and assumptions that market participants would use in pricing assets or liabilities as well as assumptions about the risks inherent in the inputs to the valuation technique. The inputs and factors include:

•: forward commodity prices,
•: price volatility,
•: volumes,
•: location,
•: interest rates,
•: credit quality of counterparties and Constellation Energy, and
•: credit enhancements.

The primary input to our valuation models is the forward commodity curve for the respective instrument. Forward commodity curves are derived from published exchange transaction prices, executed bilateral transactions, broker quotes, and other observable or public data sources. The relevant forward commodity curve used to value each of our derivatives will depend on a number of factors including commodity type, location, and expected delivery period. Price volatility would vary by commodity and location. When appropriate, we discount future cash flows using risk free interest rates with adjustments to reflect the credit quality of each counterparty for assets and our own credit quality for liabilities.

We also record valuation adjustments to reflect uncertainty associated with certain estimates inherent in the determination of the fair value of derivative assets and liabilities. The effect of these uncertainties is not incorporated in market price information of other market-based estimates used to determine fair value of our mark-to-market energy contracts.

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The following table sets forth a reconciliation of changes in Level 3 fair value ~~measurements:~~measurements, which predominantly relate to power contracts:

		Quarter Ended September 30,						Nine Months Ended September 30,							Quarter Ended March 31,

		2009			2008			2009			2008				2010			2009

		(In millions)													(In millions)
Balance at beginning of period	Balance at beginning of period	$	(176.5	)	$	211.4		$	37.0		$	(147.1	)	Balance at beginning of period	$	(291.5	)	$	37.0
Realized and unrealized (losses) gains:	Realized and unrealized (losses) gains:													Realized and unrealized (losses) gains:
	Recorded in income		(121.0	)		37.4			(368.3	)		203.3		Recorded in income		(136.8	)		(147.5	)
	Recorded in other comprehensive income		122.6			(24.3	)		146.6			226.2		Recorded in other comprehensive income		76.4			(90.7	)
Purchases, sales, issuances, and settlements	Purchases, sales, issuances, and settlements		(5.5	)		(39.5	)		31.0			(3.2	)	Purchases, sales, issuances, and settlements		9.3			1.9
Transfers into and out of Level 3			(60.2	)		529.6			(86.9	)		435.4
Transfers into Level 3¹														Transfers into Level 3¹		115.1
Transfers out of Level 3¹														Transfers out of Level 3¹		(87.7	)

Balance at end of period		$	(240.6	)	$	714.6		$	(240.6	)	$	714.6
Net transfers into and out of Level 3														Net transfers into and out of Level 3		27.4			(75.8	)

Balance at end of year														Balance at end of year	$	(315.2	)	$	(275.1	)

Change in unrealized gains recorded in income relating to derivatives still held at end of period	Change in unrealized gains recorded in income relating to derivatives still held at end of period	$	43.8		$	338.8		$	(0.7	)	$	478.5		Change in unrealized gains recorded in income relating to derivatives still held at end of period	$	(108.8	)	$	164.7

1 Effective January 1, 2010, we are required to present separately the amounts transferred into Level 3 from the amounts transferred out of Level 3. For purposes of this reconciliation, we assumed transfers into and out of Level 3 occurred on the last day of the quarter.

Realized and unrealized gains (losses) are included primarily in "Nonregulated revenues" for our derivative contracts that are marked-to-market in our Consolidated Statements of Income (Loss) and are included in "Accumulated other comprehensive loss" for our derivative contracts designated as cash-flow hedges in our Consolidated Balance Sheets.

We discuss the income statement classification for realized gains and losses related to cash-flow hedges for our various hedging relationships in~~Table of Contents~~Note 1 to our 2009 Annual Report on Form 10-K.

Fair Value of Financial Instruments

We show the carrying amounts and fair values of financial instruments included in our Consolidated Balance Sheets in the following table:



At September 30, 2009		Carrying Amount		Fair Value
At March 31, 2010						At March 31, 2010	Carrying Amount		Fair Value
		(In millions)					(In millions)
Investments and other assets—Constellation Energy	Investments and other assets—Constellation Energy	$	1,393.5	$	1,392.1	Investments and other assets—Constellation Energy	$	220.0	$	219.8
Fixed-rate long-term debt:	Fixed-rate long-term debt:					Fixed-rate long-term debt:
	Constellation Energy (including BGE)		5,481.4		5,678.1	Constellation Energy (including BGE)		3,736.2		3,984.2
	BGE		2,238.5		2,320.7	BGE		2,200.1		2,312.8
Variable-rate long-term debt:	Variable-rate long-term debt:					Variable-rate long-term debt:
	Constellation Energy (including BGE)		695.9		695.9	Constellation Energy (including BGE)		544.5		544.5
	BGE		—		—	BGE		—		—

We use the following methods and assumptions for estimating the fair value ~~disclosures for~~of financial instruments:

•: cash and cash equivalents, net accounts receivable, other current assets, certain current liabilities, short-term borrowings, current portion of long-term debt, and certain deferred credits and other liabilities: because of their short-term nature, the amounts reported in our Consolidated Balance Sheets approximate fair value,
•: investments and other assets: the fair value is based on quoted market prices where available, and
•: long-term debt: the fair value is based on quoted market prices where available or by discounting remaining cash flows at current market rates.

Accounting Standards ~~Issued~~
Adopted

Accounting for Variable Interest Entities

In June 2009, the ~~FASB~~Financial Accounting Standards Board amended the accounting, ~~for~~presentation, and disclosure guidance related to variable interest ~~entities, effective for interim~~entities. We adopted this guidance on January 1, 2010 and ~~annual reporting periods~~discuss our adoption in more detail beginning ~~after November 15, 2009. The standard includes the following significant provisions:~~

•: ~~requires an entity to qualitatively assess if it is the primary beneficiary of a VIE based~~ on whether the entity (1) has the power to direct matters that most significantly impact the activities of the VIE, and (2) has the obligation to absorb losses or the right to receive benefits of the VIE that could potentially be significant to the VIE,
•: ~~requires ongoing reconsideration of the primary beneficiary instead of only upon certain triggering events,~~
•: ~~amends the events that trigger a reassessment of whether an entity is a VIE, and~~
•: requires the primary beneficiary of a VIE to disclose separately (1) the assets of the consolidated VIE, if they can be used to only settle specific obligations of the consolidated VIE, and (2) the liabilities of a consolidated VIE for which creditors do not have recourse to the general credit of the primary beneficiary.

page 11.

~~We are currently evaluating the impacts of this standard on our, and BGE's, financial results, which could be material.~~Related Party Transactions

~~Accounting Standards Adopted~~Constellation Energy

~~Noncontrolling Interests in Consolidated Financial Statements~~CENG

~~In December 2007,~~On November 6, 2009, upon the ~~FASB issued amended guidance related to the accounting and reporting~~sale of ~~noncontrolling interests in consolidated financial statements. A noncontrolling~~a membership interest in ~~a subsidiary is an ownership~~CENG, our nuclear generation and operation business, to EDF, we deconsolidated CENG and began accounting for our 50.01% membership interest in ~~the consolidated entity that should be reported~~CENG as an equity in the consolidated financial statements. This presentation is based upon the view of the consolidated business as a single economic entity and considers minority ownership interests in consolidated subsidiaries as equity in the consolidated entity.

~~Under the amended guidance, companies are required to:~~

•: ~~present noncontrolling interests (formerly described as "minority interests") in the consolidated balance sheet as a separate line item within equity,~~
•: ~~separately present on the face of the income statement the amount of consolidated net income attributable to the parent and to the noncontrolling interest,~~
•: ~~account for changes in ownership interests that do not result in a change in control as equity transactions, and~~
•: ~~upon deconsolidation of a subsidiary due to a change in control, measure any retained interest at fair value and record a gain or loss for both the portion sold and the portion retained.~~

~~Effective January 1, 2009, we presented and disclosed noncontrolling interests in our Consolidated Financial Statements in accordance with the amended guidance.~~

The total increase in Constellation Energy's noncontrolling interest amount of $52.4 million from December 31, 2008 to September 30, 2009 is primarily due to income earned at one entity in which there is a noncontrolling interest.

~~The total increase in BGE's noncontrolling interest amount of $8.4 million from December 31, 2008 to September 30, 2009 is primarily due to a contribution by its noncontrolling interest owner.~~

~~Disclosures about Derivative Instruments and Hedging Activities~~

~~In March 2008, the FASB issued amended guidance requiring expanded disclosure about derivative instruments~~method investment.

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~~and hedging activities, but did not change~~ In connection with the ~~accounting for derivatives. We adopted the new disclosure requirements on January 1, 2009 and provide these additional disclosures beginning on page 31.~~

~~Subsequent Events~~

In May 2009, the FASB issued a new accounting standard addressing the accounting for and disclosure of events that occur subsequent to the balance sheet date but before financial statements are issued or are available to be issued. Because this standard does not change the fundamental requirements for accounting for subsequent events, it does not have a significant impact on our, or BGE's financial results. However, this standard does require the disclosureclosing of the date through which subsequent events have been evaluated as well as whether that date is the date the financial statements were issued. We adopted this standard as of June 30, 2009 and have provided the additional required disclosures on page 11.

~~Accounting Standards Codification and Hierarchy of Generally Accepted Accounting Principles~~

In June 2009, the FASB issued the Accounting Standards Codification (Codification), which became effective for financial statements issued for interim and annual periods ending after September 15, 2009. The Codification became the sole source of authoritative generally accepted accounting principles in the United States of America (GAAP) and superseded all existing non-SEC accounting and reporting standards. All of the Codification content carries the same level of authority, and any accounting guidance not contained within the Codification is considered non-authoritative. Because the Codification was not intended to change GAAP, the adoption of this standard did not have an impact on our, or BGE's, financial results. However, our disclosures and references to accounting standards have changed to reflect the new Codification structure beginningtransaction with ~~this Form 10-Q for the quarter ended September 30, 2009.~~

~~Recognition and Presentation of Other-Than-Temporary Impairments~~

In April 2009, the FASB issued accounting guidance for the recognition and presentation of other-than-temporary impairments. This guidance amended the other-than-temporary guidance for debt securities and expanded the disclosure requirements for debt and equity securities. The available-for-sale investments in our nuclear decommissioning trust funds are managed by third parties who have independent discretion over the purchases and sales of securities. As such, the amended guidance for other-than-temporary impairments does not affect our policy of recognizing impairments for any of these investments for which fair value declines below its book value. This guidance also requires disclosures regarding available-for-sale securities in interim financial statements as well as in annual financial statements. We adopted this guidance as of April 1, 2009 and provide the additional disclosures regarding available for sale securities beginning on page 18.

~~Interim Disclosures about Fair Value of Financial Instruments~~

~~In April 2009, the FASB issued accounting guidance for interim disclosures about~~EDF, we entered into a power purchase agreement (PPA) with CENG with a fair value of financial instruments. This guidance requires disclosures about fair value of financial instruments in interim financial statements as well as in annual financial statements. We adopted this guidance as of April 1, 2009 with no effect on our, or BGE's financial results. We provide the disclosures regarding fair value of financial instruments on page 41.

~~Delay of Effective Date for Certain Fair Value Measurements~~

In February 2008, the FASB issued accounting guidance that delayed the effective date of adopting the accounting standard for fair value measurements for many nonfinancial assets and liabilities, including asset retirement obligations, long-lived assets, and goodwill, to fiscal years beginning after November 15, 2008. Prospectively,$0.8 billion under which we will ~~disclose subsequent measurements~~purchase between 85-90% of ~~nonfinancial assets~~the output of CENG's nuclear plants that is not sold to third parties under pre-existing PPAs over the five year term of the PPA.

In addition to the PPA, we entered into a power services agency agreement (PSA) and ~~liabilities at fair value as part~~an administrative service agreement (ASA). The PSA is a five-year agreement under which we will provide scheduling, asset management and billing services to CENG and recognize average annual revenue of ~~our~~~~Fair Value Measurements~~ ~~footnote. We adopted this guidance~~approximately $16 million. The ASA is a one year agreement that is renewable annually under which we will provide administrative support services to CENG for a fee of approximately $66 million for 2010. The fees for administrative support services will be subject to change in future years based on ~~January 1, 2009 with no effect on our, or BGE's, financial results. See page 37 for our disclosures about fair value measurements.~~

~~Determining Fair Value When~~ the ~~Volume and Level of Activity for the Asset or Liability have Significantly Decreased and Identifying Transactions That Are Not Orderly~~

~~In April 2009, the FASB issued accounting guidance for determining fair value when the volume and~~ level of ~~activity for~~services provided. The charges under this agreement are intended to represent the ~~asset or liability have significantly decreased and for identifying~~actual cost of the services provided to CENG from us.

The impact of transactions that are not orderly. The guidance provides for estimating fair value when the volume and level of activity for the asset or liability have decreased and assists in identifying circumstances that indicate a transactionunder these agreements is not orderly. Finally, the guidance expands the disclosure requirements for fair value measurements to include further disaggregation in the tabular disclosures. We adopted this guidance as of April 1, 2009 with no effect on our, or BGE's, financial results. See page 37 for our disclosures about fair value measurements.

~~Third Party Credit Enhancements~~

~~In September 2008, the FASB issued guidance on third party credit enhancements and clarified that an entity shall~~summarized below:

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not include the effects of a third party credit enhancement in the fair value measurement of a liability. We adopted this guidance on January 1, 2009 and recorded a reduction in our derivative liability of approximately $4 million.

Agreement	Amount Recognized in Earnings for the Quarter Ended March 31, 2010			Income Statement Classification	Accounts Receivable/ (Accounts Payable) at March 31, 2010


	(In millions)
PPA	$	198.5		Fuel and purchased energy expenses	$	(27.8	)
PSA		(4.0	)	Nonregulated revenues		—
ASA		(16.5	)	Operating expenses		5.5

~~Related Party Transactions~~

BGE—Income Statement

BGE is obligated to provide market-based standard offer service to all of its electric customers for varying periods. Bidding to supply BGE's market-based standard offer service to electric customers will occur from time to time through a competitive bidding process approved by the Maryland PSC.

�� Our ~~merchant energy~~NewEnergy business will supply a portion of BGE's market-based standard offer service obligation to electric customers through ~~May 31,~~September 30, 2012.

The cost of BGE's purchased energy from nonregulated subsidiaries of Constellation Energy to meet its standard offer service obligation was ~~as follows:~~$124.0 million for the quarter ended March 31, 2010 compared to $204.3 million for the same period in 2009.

Quarter Ended
September 30,
Nine Months
Ended
September 30,

2009
2008
2009
2008

(In millions)

Purchased energy
$ 155.9 $ 175.6 $ 502.7 $ 632.9

In addition, Constellation Energy charges BGE for the costs of certain corporate functions. Certain costs are directly assigned to BGE. We allocate other corporate function costs based on a total percentage of expected use by BGE. We believe this method of allocation is reasonable and approximates the cost BGE would have incurred as an unaffiliated entity. Under the Maryland PSC's October 30, 2009 order approving the transaction with EDF, we are limited to allocating no more than 31% of these costs to BGE. These costs were approximately $36.2 million for the quarter ended March 31, 2010 compared to $29.6 million for the quarter ended March 31, 2009. Other nonregulated affiliates of BGE also charge BGE for the costs of certain services provided.

~~The following table presents the costs Constellation Energy charged to BGE in each period.~~

Quarter Ended
September 30,
Nine Months
Ended
September 30,

2009
2008
2009
2008

(In millions)

Charges to BGE
$ 38.9 $ 44.5 $ 104.0 $ 114.6

BGE—Balance Sheet

Throughout 2009, BGE ~~participates~~participated in a cash pool under a Master Demand Note agreement with Constellation Energy. Under this arrangement, participating subsidiaries may invest in or borrow from the pool at market interest rates. Constellation Energy administers the pool and invests excess cash in short-term investments or issues commercial paper to manage consolidated cash requirements. Under this arrangement, BGE had invested ~~$77.3 million at September 30, 2009 and $148.8~~$314.7 million at December 31, ~~2008.~~2009.

As part of the ring-fencing measures required by the Maryland PSC in its order approving the transaction with EDF, BGE ceased participation in the cash pool on January 7, 2010.

BGE's Consolidated Balance Sheets include intercompany amounts related to BGE's purchases to meet its standard offer service obligation, ~~BGE's gas purchases,~~ BGE's charges to Constellation Energy and its nonregulated affiliates for certain services it provides them, Constellation Energy and its nonregulated affiliates' charges to BGE, ~~for certain services provided to BGE,~~ and the participation of BGE's employees in the Constellation Energy defined benefit plans.

~~BGE will cease participation in the cash pool in accordance with the Maryland PSC's order approving our transaction with EDF.~~

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Item 2. Management's Discussion

Management's Discussion and Analysis of Financial Condition and Results of Operations

Introduction and Overview

Constellation Energy Group, Inc. (Constellation Energy) is an energy company that conducts its business through various subsidiaries including ~~a merchant energy business~~nonregulated businesses and Baltimore Gas and Electric Company (BGE). We describe our operating segments in theNotes to Consolidated Financial Statements ~~beginning~~ on page ~~19.~~14.

This Quarterly Report on Form 10-Q is a combined report of Constellation Energy and BGE. References in this report to "we" and "our" are to Constellation Energy and its subsidiaries, collectively. References in this report to the "regulated business(es)" are to BGE. We discuss our business and strategy in more detail inItem 1—Business section of our ~~2008~~2009 Annual Report on Form 10-K and we discuss the risks affecting our business inItem 1A. Risk Factors section of our ~~2008~~2009 Annual Report on Form 10-K.

Our ~~2008~~2009 Annual Report on Form 10-K includes a detailed discussion of various items impacting our business, our results of operations, and our financial condition. These include:

•: Introduction and Overview section which provides a description of our business, ~~segments,~~
•: Strategy section,
•: Business Environment section, including how recent events, regulation, weather, and other factors affect our business, and
•: Critical Accounting Policies section.

Critical accounting policies are the accounting policies that are most important to the portrayal of our financial condition and results of operations and that require management's most difficult, subjective, or complex judgment. Our critical accounting policies include derivative accounting and the evaluation of assets for impairment and other than temporary decline in ~~value, and asset retirement obligations.~~value.

In this discussion and analysis, we explain the general financial condition and the results of operations for Constellation Energy and BGE including:

•: factors which affect our businesses,
•: our earnings and costs in the periods presented,
•: changes in earnings and costs between periods,
•: sources of earnings,
•: impact of these factors on our overall financial condition,
•: expected future expenditures for capital projects,
•: expected sources of cash for future capital expenditures, and
•: our net available liquidity and collateral requirements.

As you read this discussion and analysis, refer to our Consolidated Statements of Income (Loss) on page 3, which present the results of our operations for the quarters ended March 31, 2010 and ~~nine months ended September 30, 2009 and 2008.~~2009. We analyze and explain the differences between periods in the specific line items of the Consolidated Statements of Income (Loss).

We have organized our discussion and analysis as follows:

•: We describe changes to our business environment during the year.
•: We highlight significant events that occurred in ~~2009~~2010 that are important to understanding our results of operations and financial condition.
•: We then review our results of operations beginning with an overview of our total company results, followed by a more detailed review of those results by operating segment. As of January 1, 2010, we changed our reportable segments and have recast prior period information to conform with the current presentation.
•: We review our financial condition, addressing our sources and uses of cash, capital resources, commitments, and liquidity.
•: We conclude with a discussion of our exposure to various market risks.

Business Environment

Various factors affect our financial results. We discuss these various factors in theForward Looking Statements section on page 7863 and inItem 1A. Risk Factors section of our ~~2008~~2009 Annual Report on Form 10-K. We discuss our market risks in theRisk Management section beginning on page ~~72.~~57.

The volatility of the financial, credit and global energy markets impacts our liquidity and collateral requirements as well as our credit risk. We discuss our liquidity and collateral requirements in theFinancial Condition section and our customer (counterparty) credit and other risks in more detail in theRisk Management section.

In this section, we discuss in more detail events which have impacted our business during ~~2009.~~2010.

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~~Federal Regulation~~

The United States Congress and the Commodity Futures Trading Commission are evaluating additional regulations for the derivatives markets, including position limits and eliminating hedge regulatory exemptions. We are unable to determine the final form any regulations may take, but such regulations could have a material effect on our business.

~~Maryland PSC Review of EDF Transaction~~

In June 2009, during Phase I of the EDF proceeding, the Maryland Public Service Commission (Maryland PSC) determined that EDF Group and related entities (EDF) would obtain the power to exercise substantial influence over the policies and actions of BGE under Constellation Energy's proposed transaction with EDF, and, therefore, that the Maryland PSC must review the transaction to determine that it is in the public interest with benefits and no harm to consumers.

Constellation Energy, BGE and EDF filed suit in the Baltimore City Circuit Court appealing the Maryland PSC's Phase I ruling that the Maryland PSC's review and approval was required for the EDF transaction. The Circuit Court dismissed the suit as premature, and Constellation Energy and BGE appealed the court's dismissal of the Phase I challenge to the Maryland Court of Special Appeals.

In Phase II of the EDF proceeding, EDF filed an application with the Maryland PSC in June 2009 and the Maryland PSC issued an order in Phase II on October 30, 2009. We discuss this Maryland PSC order and the EDF transaction in more detail in the~~Notes to Consolidated Financial Statements~~ ~~beginning on page 11.~~

Environmental Matters

Air Quality

~~Capital Expenditures~~National Ambient Air Quality Standards (NAAQS)

As discussed in our 2008 Annual Report on Form 10-K, we expect to incur additional environmental capital expenditures to comply with air quality laws and regulations. Based on updated information from vendors, we expect our estimated environmental capital requirements for these air quality projects to be approximately $345 million in 2009, $10 million in 2010, $20 million in 2011 and $30 million from 2012-2013.

Our estimates may change further as we implement our compliance plan. As discussed in our 2008 Annual Report on Form 10-K, our estimates of capital expenditures continue to be subject to significant uncertainties.

~~Global Climate Change~~

In ~~September 2009,~~January 2010, the U.S. Environmental Protection Agency (EPA) proposed ~~regulations~~rules to ~~address greenhouse gas emissions under~~adopt NAAQs for ozone that are stricter than the ~~Clean Air Act. The proposed regulations would require large facilities that emit at least 25,000 tons~~NAAQs adopted in March 2008, based on the EPA's reevaluation of ~~greenhouse gases a year to obtain construction~~scientific evidence about ozone and ~~operating permits covering these emissions. The proposed regulations would apply to many of our fossil fuel generating facilities.~~ozone's effects on humans and the environment. We are ~~evaluating~~unable to determine the ~~potential~~ impact ~~of these regulations on our business should they be adopted. We could incur compliance costs~~ that complying with the stricter NAAQS for ozone will have ~~a material impact~~ on our financial ~~results.~~results until the states in which our generating facilities are located adopt plans to meet the new standards. However, costs associated with compliance with these plans could be material.

Water Quality

Water Intake Regulations

In March 2010, the New York Department of Environmental Conservation issued a draft policy designating closed-cycle cooling as the best technology available for cooling water intake structures for minimizing adverse environmental impacts. At this time we cannot predict whether this policy will be adopted. However, if the policy is adopted and CENG is required to retrofit its two nuclear generating facilities in New York to implement this technology, our share of the compliance costs could be material.

Hazardous and Solid Waste

In May 2010, the EPA proposed rules to regulate coal combustion by-products, such as fly ash, either as a special hazardous waste or as a nonhazardous waste. Depending on the scope of any final rules that are adopted, additional federal regulation has the potential to result in additional compliance requirements and costs that could be material.

Accounting Standards ~~Issued and~~ Adopted

We discuss recently ~~issued and~~ adopted accounting standards in theAccounting Standards ~~Issued~~ ~~and~~~~Accounting Standards~~ Adopted ~~sections~~section of ~~the~~~~Notes to Consolidated Financial Statements~~ ~~beginning on page 41.~~

~~Events of 2009~~

~~Acquisition~~

~~In July 2009, we acquired CLT Efficient Technologies Group (CLT), an energy services company. We discuss this acquisition in more detail in~~ theNotes to Consolidated Financial Statements on page ~~16.~~36.

~~Divestitures~~Events of 2010

Acquisitions

Criterion Wind Project

In ~~January 2009, we entered into a definitive agreement to sell a majority of our international commodities operation. We completed this transaction in March 2009.~~

~~In February 2009, we entered into a definitive agreement to sell our gas trading operation. We transferred control of this operation in~~ April 2009. Simultaneously, we entered into an agreement with the buyer of our Houston-based gas trading operation under which that company will provide us with the gas supply needed to support our retail gas customer supply business.

~~In June 2009,~~2010, we completed the ~~sale~~acquisition of ~~a uranium market participant that provides marketing services~~the Criterion wind project in Garrett County, Maryland.

Texas Combined Cycle Generation Facilities

In April 2010, we signed an agreement to ~~uranium producers, utilities~~purchase the 550 MW Colorado Bend Energy Center and ~~an investment fund~~the 550 MW Quail Run Energy Center natural gas combined cycle generation facilities in ~~the North American and European markets.~~

~~In August 2009, we completed the sale of our equity investment in our shipping joint venture.~~Texas for $365 million, subject to closing adjustments.

We discuss these ~~divestitures and the gas supply agreement~~transactions in more detail on page 13 in ~~the~~Notes to Consolidated Financial ~~Statements~~Statements. ~~beginning on page 16.~~

~~Merger Termination and Strategic Alternatives Costs~~
Divestiture

~~During~~In January 2010, BGE completed the ~~quarter and nine months ended September 30, 2009, we incurred merger termination and strategic alternatives costs related~~sale of its interest in a nonregulated subsidiary that owns a district chilled water facility to ~~the terminated merger with MidAmerican Energy Holdings Company (MidAmerican), the conversion of our Series A Preferred Stock, the transactions related to EDF, and other strategic alternatives costs.~~a third party. We discuss ~~costs related to the mergers and strategic~~

~~Table of Contents~~

~~alternatives~~this transaction in more detail on page 1213 inNotes to Consolidated Financial Statements.

Redemption of Notes

In February 2010, we retired certain of our 7.00% Notes due April 1, 2012 as part of a cash tender offer launched in January 2010 and in March 2010 we repurchased certain tax exempt notes. We discuss these transactions in more detail on page 17 inNotes to Consolidated Financial Statements.

~~Impairment Losses and Other Costs~~
Healthcare Reform Legislation

~~During~~In March 2010, the Patient Protection and Affordable Care Act and the Healthcare and Education Reconciliation Act of 2010 (Reconciliation Act) were signed into law. We discuss the impact of these new laws on our earnings for the quarter ~~and nine months~~ ended ~~September 30, 2009, we recorded impairment losses and other costs on certain of our equity method investments, investments in equity securities and other assets. We discuss these charges~~March 31, 2010 in more detail on page 16 in ~~the~~Notes to Consolidated Financial Statements ~~beginning on page 14.~~

~~Workforce Reduction Costs~~

During the nine months ended September 30, 2009, we incurred workforce reduction costs primarily related to the divestiture of a majority of our international commodities operation as well as some smaller restructurings elsewhere in our organization. We recognized an $11.6 million pre-tax charge in 2009 related to the elimination of approximately 180 positions. We expect all of these restructurings will be completed within 12 months from the program's initiation. We discuss our workforce reduction costs in more detail in the~~Notes to Consolidated Financial Statements~~ ~~beginning on page 15.~~.

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Results of Operations for the Quarter ~~and Nine Months~~ Ended ~~September 30, 2009~~March 31, 2010 Compared with the Same ~~Periods~~Period of ~~2008~~2009

In this section, we discuss our earnings and the factors affecting them. We begin with a general overview, then separately discuss earnings for our operating segments. Significant changes in other (expense) income, ~~and expense,~~ fixed charges, and income taxes are discussed, as necessary, in the aggregate for all segments in theConsolidated Nonoperating Income and Expenses section on page ~~63.~~51.

Overview

Results

		Quarter Ended September 30,						Nine Months Ended September 30,						Quarter Ended March 31,

		2009			2008			2009			2008			2010			2009

		(In millions, after-tax)												(In millions, after-tax)
Merchant energy		$	142.1		$	(246.0	)	$	(39.7	)	$	106.7
Generation														$	27.1		$	41.5
NewEnergy															104.1			(246.3	)
Regulated electric	Regulated electric		42.3			34.3			109.8			(31.2	)		27.2			45.4
Regulated gas	Regulated gas		(10.5	)		(11.5	)		22.9			26.4			37.2			39.6
Other nonregulated	Other nonregulated		(6.5	)		1.1			(17.0	)		0.4			(4.3	)		0.1

Net Income (Loss)	Net Income (Loss)	$	167.4		$	(222.1	)	$	76.0		$	102.3		$	191.3		$	(119.7	)

Net Income (Loss) attributable to common stock	Net Income (Loss) attributable to common stock	$	137.6		$	(225.7	)	$	22.2		$	91.5		$	191.5		$	(123.5	)

Change from prior year	Change from prior year	$	363.3					$	(69.3	)				$	315.0

Other Items Included in Operations (after-tax)¹:
	International commodities operation and gas trading operation²	$	(62.9	)	$	—		$	(370.9	)	$	—
	Impairment losses and other costs		(9.0	)		(298.8	)		(85.4	)		(298.8	)
	Impairment of nuclear decommissioning trust assets		(19.7	)		(15.3	)		(49.5	)		(21.5	)
	Merger termination and strategic alternatives costs		(4.9	)		(37.3	)		(51.2	)		(37.3	)
	Accrual of Maryland settlement credit		—			—			—			(125.3	)
	BGE effective tax rate impact of Maryland settlement agreement		—			2.0			—			10.7
	Emission allowance write-down, net		—			(22.8	)		—			(36.2	)
	Non-qualifying hedges		—			12.0			—			(57.3	)
	Workforce reduction costs		(1.6	)		(1.6	)		(7.0	)		(1.6	)
	Credit facility amendment fees		(8.2	)		—			(17.1	)		—

Total Other Items		$	(106.3	)	$	(361.8	)	$	(581.1	)	$	(567.3	)

Change from prior year		$	255.5					$	(13.8	)

~~1 Amounts~~Our total net income attributable to common stock for the quarter ended ~~September 30,~~March 31, 2010 was favorable compared to the net loss attributable to common stock for the same period of 2009 ~~include income tax adjustments relating~~by $315.0 million, or $1.57 per share, primarily due to ~~activity during~~ the ~~quarters~~following:

2010 vs. 2009

(in millions,
after-tax)

Generation gross margin
$ (132 )
NewEnergy gross margin
117
Generation operating expenses, primarily performance-based labor and benefit costs due to the deconsolidation of CENG
100
Gain on NewEnergy international coal contract assignment
38
NewEnergy hedge ineffectiveness
(6 )
Regulated businesses
(18 )
Total change inOther Items included in Operations per table below
175
All other changes
41

Total Change
$ 315

Other Items Included in Operations (after-tax):

Quarter Ended
March 31,

2010
2009

(In millions,
after-tax)

Deferred income tax expense relating to federal subsidies for providing post-employment prescription drug benefits
$ (8.8 ) $ —

Loss on early retirement of 2012 Notes
(30.9 ) —

Amortization of basis difference in CENG
(25.7 ) —

Impact of power purchase agreement with CENG¹
(25.7 ) —

International commodities operation and gas trading operation²
— (184.2 )

Impairment losses and other costs
— (11.1 )

Merger termination and strategic alternatives costs
— (42.3 )

Impairment of nuclear decommissioning trust assets
— (23.8 )

Workforce reduction costs
— (4.2 )

Credit facility amendment fees
(2.9 ) (3.7 )

Total Other Items
$ (94.0 ) $ (269.3 )

Change from prior year
$ 175.3

1 The net impact to the Company of the power purchase agreement with CENG was $42.1 million pre-tax for the quarter ended March 31, ~~2009 and June 30, 2009 based on updated estimates~~2010. This amount represents the amortization of our ~~2009 annual effective tax rate.~~$0.8 billion "Unamortized energy contract asset" less our 50.01% equity in CENG's amortization of its $0.8 billion "Unamortized energy contract liability."

2 These amounts include the ~~losses~~loss on ~~the sales~~sale of the international commodities ~~and gas trading operations,~~operation, the reclassification of losses on previously designated cash-flow hedges from Accumulated Other Comprehensive Loss because the forecasted transactions are probable of not occurring, and earnings that are no longer part of our core business. The impairment losses and other costs and workforce reduction costs line items also include amounts related to the operations we divested. ~~Third quarter of 2009 activity is primarily due to the income tax adjustments referenced above.~~

~~Quarter and Nine Months Ended September 30, 2009~~

Our total net income attributable to common stock for the quarter ended September 30, 2009 exceeded the net loss attributable to common stock for the quarter ended September 30, 2008 and the net income attributable to common stock for the nine months ended September 30, 2009 decreased from the net income attributable to common stock for the nine months ended September 30, 2008 primarily due to the following:

Quarter Ended
September 30,
Nine Months
Ended
September 30,

2009 vs. 2008

(In millions, after-tax)

Generation gross margin
$ (11 ) $ 62
Customer supply gross margin
(8 ) 4
Global Commodities gross margin
169 (232 )
Hedge ineffectiveness
4 100
Absence of sale of upstream gas assets
— (55 )
Absence of credit loss—coal supplier bankruptcy
— 33
Merchant interest expense
(24 ) (77 )
Regulated businesses, primarily related to absence of Maryland settlement agreement credit
9 137
Other nonregulated businesses
(8 ) (17 )
Total change in Other Items included in operations perOverview—Results table
256 (14 )
All other changes
(24 ) (10 )

Total Change
$ 363 $ (69 )

In the following sections, we discuss our net ~~income~~loss by business segment in greater detail.

~~Merchant Energy Business~~

~~Background~~

~~Our merchant energy business is a competitive provider of energy solutions for various customers. We discuss the impact of deregulation on our merchant energy business in~~~~Item 1. Business—Competition~~ ~~section of our 2008 Annual Report on Form 10-K.~~

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Generation Business
Background
We define our Generation business in theNotes to Consolidated Financial Statements on page 14.
        We present the results of this business based on the assumption that we have hedged 100% of generation output and fuel for generation. The assumption is based on executing hedges at prevailing market prices with the NewEnergy business. Taking into account previously executed hedges at the end of each fiscal year, we ensure that the Generation business is fully hedged by the NewEnergy business for the next year. Therefore, all commodity price risk is managed by and presented in the results of our NewEnergy business as discussed below. Generally, changes in the results of our Generation business during the period are due to changes in the level of output from the generating assets.
Results

Quarter Ended
March 31,

2010
2009

(In millions)

Revenues
$ 579.9 $ 785.5
Fuel and purchased energy expenses
(326.6 ) (221.9 )

Gross margin
253.3 563.6
Operating expenses
(94.6 ) (281.6 )
Merger termination and strategic alternatives costs
— (26.4 )
Depreciation, depletion, and amortization
(28.1 ) (45.1 )
Accretion of asset retirement obligations
(0.4 ) (17.9 )
Taxes other than income taxes
(5.4 ) (18.2 )
Gain on divestitures
2.9 —
Equity investment earnings:

CENG
(19.2 ) —

UNE
(6.1 ) —

Other
4.6 —

Income from Operations
$ 107.0 $ 174.4

Net Income
$ 27.1 $ 41.5

Net Income attributable to common stock
$ 27.1 $ 41.5

Other Items Included in Operations (after-tax):

Deferred income tax expense relating to federal subsidies for providing post-employment prescription drug benefits
$ (0.8 ) $ —

Loss on early retirement of 2012 Notes
(30.9 ) —

Amortization of basis difference in CENG
(25.7 ) —

Impact of power purchase agreement with CENG¹
(25.7 ) —

Credit facility amendment fees
(1.9 ) (2.2 )

Merger termination and strategic alternatives costs
— (26.4 )

Impairment of nuclear decommissioning trust assets
— (23.8 )

Total Other Items
$ (85.0 ) $ (52.4 )

Above amounts include intercompany transactions eliminated in our Consolidated Financial Statements. The Information by Operating Segment section within the Notes to Consolidated Financial Statements on page 15 provides a reconciliation of operating results by segment to our Consolidated Financial Statements.
1 The net impact to the Company of the power purchase agreement with CENG was $42.1 million pre-tax for the quarter ended March 31, 2010. This amount represents the amortization of our $0.8 billion "Unamortized energy contract asset" less our 50.01% equity in CENG's amortization of its $0.8 billion "Unamortized energy contract liability."

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Effects of Transaction with EDF on Consolidated Statement of Income (Loss)
Prior to November 6, 2009, Constellation Energy Nuclear Group, LLC (CENG), our nuclear generation and operation business, was a 100% owned consolidated subsidiary. On November 6, 2009, we completed the sale of a 49.99% membership interest in CENG to EDF Group and affiliates (EDF), and we deconsolidated CENG. Specifically, we removed the assets and liabilities of CENG and recorded an investment in CENG at fair value on our Consolidated Balance Sheets, and recorded the proceeds received on our Consolidated Statements of Cash Flows. After November 6, 2009, we record equity investment earnings from CENG on our Consolidated Statements of Income (Loss). We discuss our transaction with EDF in more detail inNote 2 to our 2009 Annual Report on Form 10-K.
Revenues
Our ~~merchant~~Generation revenues decreased $205.6 million in the first quarter of 2010 compared to 2009, primarily due to the following:

2010 vs.
2009

(In millions)

Decrease in volume of output from nuclear generating assets due to the deconsolidation of CENG
$ (159 )
Decrease due to higher planned outages at our fossil plants
(61 )
All other
14

Total decrease in Generation revenues
$ (206 )

Fuel and Purchased Energy Expenses
Our Generation fuel and purchased energy expenses increased $104.7 million in the first quarter of 2010 compared to 2009, primarily due to the following:

2010 vs.
2009

(In millions)

Increase in purchased energy costs due to power purchase agreement with CENG compared with nuclear fuel costs in 2009
$ 160
Decrease due to higher planned outages at our fossil plants
(40 )
All other
(15 )

Total increase in Generation fuel and purchased energy expenses
$ 105

Operating Expenses
Our Generation business operating expenses decreased $187.0 million for the quarter ended March 31, 2010 as compared to the same period for 2009 due to lower labor and benefit costs of $146.4 million and lower non-labor operating expenses of $40.6 million, the majority of which results from the absence of costs in 2010 due to the deconsolidation of CENG in 2009.
Merger Termination and Strategic Alternatives Costs
We discuss costs related to the terminated merger with MidAmerican Energy Holdings Company, the conversion of our Series A Preferred Stock, our transaction with EDF and our pursuit of other strategic alternatives inNote 2 of our 2009 Annual Report on Form 10-K.
Depreciation, Depletion and Amortization Expense
Our Generation business incurred lower depreciation, depletion and amortization expenses of $17.0 million during the quarter ended March 31, 2010 compared to the same period of 2009 primarily due to a decrease of $26.9 million in depreciation on the nuclear generating facilities resulting from the deconsolidation of CENG in 2009, partially offset by an increase of $9.9 million in depreciation on our other generating facilities primarily related to environmental additions at our Brandon Shores coal-fired generating plant that went into service in the fourth quarter of 2009.
Accretion of Asset Retirement Obligations
Our Generation business incurred lower accretion of asset retirement obligations of $17.5 million during the quarter ended March 31, 2010 compared to the same period of 2009 primarily as a result of the deconsolidation of CENG. The majority of our asset retirement obligations in 2009 related to the nuclear generating facilities owned by CENG.
Taxes Other Than Income Taxes
Taxes other than income taxes decreased $12.8 million during the quarter ended March 31, 2010 compared to the same period of 2009 primarily due to a reduction in property taxes as a result of the deconsolidation of CENG, which included the removal of five nuclear generating facilities from our total assets.
Equity Investment Losses
During the quarter ended March 31, 2010 our equity investment losses increased $20.7 million compared to the same period of 2009 primarily due to $19.2 million in losses on our investment in CENG, which included amortization of our basis difference in CENG of $42.6 million, and $6.1 million in losses on our investment

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in UNE, partially offset by $4.6 million in earnings on investments in power projects.
NewEnergy Business
Background
We define our NewEnergy business in theNotes to Consolidated Financial Statements on page 14.
        Our NewEnergy business focuses on delivery of physical, customer-oriented energy products and services to energy producers and consumers, manages the risk and optimizes the value of our owned generation assets and ~~customer supply~~NewEnergy activities, and uses our portfolio management and trading capabilities both to manage risk and to deploy risk capital.
        ~~Earlier this year, we outlined various strategic initiatives for~~ Our NewEnergy business actively transacts in energy and energy-related commodities in order to manage our ~~Global Commodities operation. We discuss our strategy in more detail in the~~~~Strategy~~ ~~section~~portfolio of ~~our 2008 Annual Report on Form 10-K. As of the end of the third quarter of 2009, these initiatives are substantially complete.~~
        ~~While we have completed the sale of a majority of our international commodities operation, our gas trading operation, certain other trading operations,~~energy purchases and a uranium market participant, the execution of our strategy in the future will be affected by continued uncertainty in global financial, credit, and commodities markets. Execution of our goals could have a substantial effect on the nature and mix of our business activities. In particular, the EDF transaction results in the deconsolidation of our subsidiary that owns our nuclear generation assets. In turn, this could affect our financial position, results of operations, and cash flows in material amounts, and these amounts could vary substantially from historical results. We discuss our asset and operation divestitures in more detail in the~~Notes~~sales to ~~Consolidated Financial Statements~~ ~~beginning on page 16.~~customers through structured transactions.
        We record ~~merchant energy~~NewEnergy revenues and expenses in our financial results in different periods depending upon which portion of our business they affect and based on the associated accounting policies. We discuss our revenue recognition policies in theCritical Accounting Policies section and inNote 1 of our ~~2008~~2009 Annual Report on Form 10-K.
        As part of managing our total portfolio risk, we use economic value at risk. We view economic value at risk as the most comprehensive measure of our exposure to changing commodity prices. This metric measures the risk in our total portfolio, encompassing all aspects of our ~~merchant energy~~NewEnergy business. We also use daily value at risk and stop loss limits and liquidity guidelines to restrict the level of risk in our portfolio.
        Our Global Commodities operation actively transacts in energy and energy-related commodities in order to manage our portfolio of energy purchases and sales to customers through structured transactions. As part of these activities, we trade energy and energy-related commodities and deploy risk capital in the management of our portfolio in order to earn returns.
We discuss the impact of our economic value at risk and value at risk in more detail in theMark-to-Market andRisk Management sections.
Results

Quarter Ended
September 30,
Nine Months
Ended
September 30,

Quarter Ended
March 31,

2009
2008
2009
2008

2010
2009

(In millions)

(In millions)

Revenues
Revenues
$ 3,258.0 $ 4,492.6 $ 9,738.5 $ 12,719.7
Revenues
$ 2,350.9 $ 3,014.8
Fuel and purchased energy expenses
Fuel and purchased energy expenses
(2,268.7 ) (3,843.0 ) (7,285.3 ) (10,371.1 )
Fuel and purchased energy expenses
(1,979.4 ) (2,960.8 )

Gross margin
Gross margin
371.5 54.0
Operating expenses
Operating expenses
(396.8 ) (322.0 ) (1,214.0 ) (1,298.0 )
Operating expenses
(168.5 ) (188.6 )
Merger termination and strategic alternatives costs
(4.9 ) (27.2 ) (51.2 ) (27.2 )
Merger and strategic alternatives costs
Merger and strategic alternatives costs
— (15.9 )
Impairment losses and other costs
Impairment losses and other costs
(7.5 ) (477.1 ) (96.6 ) (477.1 )
Impairment losses and other costs
— (28.6 )
Workforce reduction costs
Workforce reduction costs
(0.4 ) (2.2 ) (11.6 ) (2.2 )
Workforce reduction costs
— (10.8 )
Depreciation, depletion, and amortization
Depreciation, depletion, and amortization
(69.7 ) (68.6 ) (198.3 ) (207.8 )
Depreciation, depletion, and amortization
(21.7 ) (20.2 )
Accretion of asset retirement obligations
Accretion of asset retirement obligations
(18.5 ) (17.2 ) (54.6 ) (50.8 )
Accretion of asset retirement obligations
(0.1 ) —
Taxes other than income taxes
Taxes other than income taxes
(29.2 ) (35.8 ) (85.3 ) (94.0 )
Taxes other than income taxes
(12.9 ) (11.2 )
Net (loss) gain on divestitures
(0.3 ) — (464.4 ) 91.5
Gain (loss) on divestitures
Gain (loss) on divestitures
2.0 (334.5 )

Income (Loss) from Operations
Income (Loss) from Operations
$ 462.0 $ (300.5 ) $ 277.2 $ 283.0
Income (Loss) from Operations
$ 170.3 $ (555.8 )

Net Income (Loss)
Net Income (Loss)
$ 142.1 $ (246.0 ) $ (39.7 ) $ 106.7
Net Income (Loss)
$ 104.1 $ (246.3 )

Net Income (Loss) attributable to common stock
Net Income (Loss) attributable to common stock
$ 116.0 $ (246.0 ) $ (83.1 ) $ 105.9
Net Income (Loss) attributable to common stock
$ 107.6 $ (246.8 )

Other Items Included in Operations (after-tax)¹:

International commodities operation and gas trading operation²
$ (62.9 ) $ — $ (370.9 ) $ —

Impairment losses and other costs
(8.2 ) (298.8 ) (81.5 ) (298.8 )
Other Items Included in Operations (after-tax):
Other Items Included in Operations (after-tax):

Impairment of nuclear decommissioning trust assets
(19.7 ) (15.3 ) (49.5 ) (21.5 )
Deferred income tax expense relating to federal subsidies for providing post-employment prescription drug benefits
$ (0.1 ) $ —

Merger termination and strategic alternatives costs
(4.9 ) (25.8 ) (51.2 ) (25.8 )
International commodities operation and gas trading operation¹
— (184.2 )

Emission allowance write-down, net
— (22.8 ) — (36.2 )
Impairment losses and other costs
— (11.1 )

Non-qualifying hedges
— 12.0 — (57.3 )
Merger termination and strategic alternatives costs
— (15.9 )

Workforce reduction costs
(1.6 ) (1.6 ) (7.0 ) (1.6 )
Workforce reduction costs
— (4.2 )

Credit facility amendment fees
(8.2 ) — (17.1 ) —
Credit facility amendment fees
(1.0 ) (1.5 )

Total Other Items
Total Other Items
$ (105.5 ) $ (352.3 ) $ (577.2 ) $ (441.2 )
Total Other Items
$ (1.1 ) $ (216.9 )

Above amounts include intercompany transactions eliminated in our Consolidated Financial Statements. The Information by Operating Segment section within the Notes to Consolidated Financial Statements on page 2015 provides a reconciliation of operating results by segment to our Consolidated Financial Statements.

1 Amounts for the quarter ended September 30, 2009 include income tax adjustments relating to activity during the quarters ended March 31, 2009 and June 30, 2009 based on updated estimates of our 2009 annual effective tax rate.

2 These amounts include the ~~losses~~loss on ~~the sales~~sale of the international commodities ~~and gas trading operations,~~operation, the reclassification of losses on previously designated cash-flow hedges from Accumulated Other Comprehensive Loss because the forecasted transactions are probable of not occurring, and earnings that are no longer part of our core business. The impairment losses and other costs and workforce reduction costs line items also include amounts related to the operations we ~~divested. Third quarter of 2009 activity is primarily due to the income tax adjustments referenced above.~~are divesting.

~~Revenues and Fuel and Purchased Energy Expenses~~

Our merchant energy business manages the revenues we realize from the sale of energy and energy-related products to our customers and our costs of procuring fuel and energy. The difference between revenues and fuel and

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purchased energy expenses, including all direct expenses, represents the gross margin of our merchant energy business, and this measure is a useful tool for assessing the profitability of our merchant energy business. Accordingly, we believe it is appropriate to discuss the operating results of our merchant energy business by analyzing the changes in gross margin between periods. In managing our portfolio, we may terminate, restructure, or acquire contracts primarily to reduce risk and/or improve our liquidity. Such transactions are within the normal course of managing our portfolio and may materially impact the timing of our recognition of revenues, fuel and purchased energy expenses, and cash flows.
        ~~We discuss our merchant energy revenues, fuel and purchased energy expenses, and gross margin below.~~
Revenues
Our ~~merchant energy~~NewEnergy revenues decreased ~~$1,234.6~~$663.9 million ~~and $2,981.2 million during~~in the first quarter ~~and nine months ended September 30, 2009, respectively,~~of 2010 compared to ~~the same periods in 2008~~2009, primarily due to the following:

Quarter Ended
September 30,
Nine Months
Ended
September 30,

2009 vs. 2008

(In millions)

Increase (decrease) in Global Commodities mark-to-market revenues due to changes in power and gas prices
$ 205 $ (235 )
Decrease in volume of business primarily related to our international coal and freight operation, which we have divested
(143 ) (652 )
Increase in contract prices and volume related to our domestic coal operation
67 240
Realization of lower prices and volume of business at our gas trading operation, which we have divested, and absence of revenue due to the sales of certain of our upstream gas properties in 2008
(5 ) (218 )
Realization of lower volumes on wholesale and retail load at our Customer Supply operation, partially offset by higher contract prices
(1,334 ) (2,097 )
All other
(25 ) (19 )

Total decrease in merchant revenues
$ (1,235 ) $ (2,981 )

2010 vs. 2009

(In millions)

Realization of lower volumes on wholesale load
$ (503 )
Decrease in volume and contract prices related to our domestic coal operation
(115 )
Realization of lower volumes primarily due to the absence of revenues at our gas trading operation, which we divested in 2009
(73 )
Change in wholesale mark-to-market revenues due to more favorable changes in power and gas prices
33
All other
(6 )

Total decrease in NewEnergy revenues
$ (664 )

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Fuel and Purchased Energy Expenses
Our ~~merchant energy~~NewEnergy fuel and purchased energy expenses decreased ~~$1,574.3~~$981.4 million ~~and $3,085.8 million during~~in the first quarter ~~and nine months ended September 30, 2009, respectively,~~of 2010 compared to ~~the same periods in 2008~~2009, primarily due to the following:

Quarter Ended
September 30,
Nine Months
Ended
September 30,

2009 vs. 2008

(In millions)

Increase in Global Commodities mark-to-market expenses related to the absence of international coal purchase contracts due to divestiture of operations and changes in prices
$ 225 $ 333
Decrease in volume of business primarily related to our international coal and freight operation, which we have divested
(123 ) (562 )
Increase in contract prices and volume related to our domestic coal operation
87 207
Realization of lower volumes at our gas trading operations, which we have divested
(54 ) (197 )
Realization of lower contract prices and volumes on wholesale and retail power purchases at our Customer Supply operation
(1,696 ) (2,890 )
All other
(13 ) 23

Total decrease in merchant energy fuel and purchased energy expenses
$ (1,574 ) $ (3,086 )

~~Gross Margin~~
~~We analyze our merchant energy gross margin in the following categories:~~
•
Generation—our operation that owns, operates, and maintains fossil, nuclear, and renewable generating facilities and holds interests in qualifying facilities, and power projects in the United States and Canada. We present the gross margin results of this operation based on a 100% hedged assumption for the portfolio, related to both output from the facilities and the fuel used to generate electricity. The assumption is based on executing hedges at current market prices with the Global Commodities operation at the end of each fiscal year in order to ensure that the Generation operation is fully hedged. Therefore, all commodity price risk is managed by and presented in the results of our Global Commodities operation as discussed below. Changes in gross margin of our Generation operation during the period are due to changes in the level of output from the generating assets, and changes in gross margin between years are a result of changes in prices and expected output.
•
Customer Supply—our load-serving operation that provides energy products and services to wholesale and retail electric and natural gas customers, including distribution utilities, cooperatives, aggregators, and commercial, industrial and governmental customers. We present the gross margin results of this operation based on the gross margin value of new customer supply arrangements at the time of execution assuming an estimated level of customer usage and the impact of any changes in the underlying usage of the customers based on actual energy deliveries. Changes in estimated customer usage result from attrition (customers changing suppliers) or variable load risk (changes in actual usage when compared to expected usage). All commodity price risk is presented in and managed by our Global Commodities operation as discussed below.
•
Global Commodities—our marketing, risk management, and trading operation that manages contractually owned physical assets, including generation facilities, natural gas properties, provides risk management services, and trades energy and energy-related commodities. This operation provides the wholesale risk management function for our Generation and Customer Supply operations, as well as our structured products and energy investments portfolios, and includes our merchant energy business' actual hedged positions with third parties. Therefore, changes in gross margin for this operation result mostly from changes in commodity prices and positions across the various commodities and regions in which we transact.

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        ~~We provide a summary of our gross margin for these three components of our merchant energy business as follows:~~

Quarter Ended
September 30,
Nine Months Ended
September 30,

2009
2008
2009
2008

(Dollar amounts in millions)

% of
Total

% of
Total

% of
Total

% of
Total

Gross Margin:

Generation
$ 648 66 % $ 626 96 % $ 1,666 68 % $ 1,499 64 %

Customer Supply
140 14 142 22 565 23 537 23

Global Commodities
201 20 (119 ) (18 ) 222 9 312 13

Total
$ 989 100 % $ 649 100 % $ 2,453 100 % $ 2,348 100 %

~~Generation~~
The $22 million increase in Generation gross margin during the quarter ended September 30, 2009 compared to the same period of 2008 is primarily due to an increase of $29 million due to the timing and duration of planned and unplanned outages at our nuclear and fossil generating assets, partially offset by a $7 million decrease from lower energy prices on hedged gross margin with Global Commodities for the output of our generating assets in the PJM and New York regions based on prices established at the end of 2008 (see Global Commodities discussion below for impact of prices during 2009).
        ~~The $167 million increase in generation gross margin during the nine months ended September 30, 2009 compared to the same period of 2008 is primarily due to the following:~~
•
~~$109 million due to the timing and duration of planned and unplanned outages at our nuclear and fossil generating plants, and~~
•
$84 million increase from higher energy prices on hedged gross margin with Global Commodities for the output of our generating assets in the PJM and New York regions based on prices established at the end of 2008 (see Global Commodities discussion below for impact of prices during 2009).
        ~~These increases were partially offset by $26 million of lower gross margin primarily related to our investments in power projects.~~
~~Customer Supply~~
The $2 million decrease in Customer Supply gross margin during the quarter ended September 30, 2009 compared to the same period of 2008 is primarily due to $71 million of lower gross margin as a result of lower customer retention and unfavorable variable load risk associated with wholesale and retail power primarily due to variances from normal weather and lower demand during the quarter ended September 30, 2009.
        ~~This decrease was partially offset by the following:~~
•
~~$45 million of higher gross margin related to the consolidation of a retail power supply variable interest entity (VIE) for which we became the primary beneficiary in December 2008, and~~
•
~~$14 million of higher mark-to-market results primarily in our retail gas operation. We discuss these results in more detail in the~~~~Mark-to-Market~~ ~~section beginning on page 53, and~~
•
$10 million related to higher realization of contracts executed in prior periods and higher margins on new business originated and realized during the quarter primarily in our wholesale and retail power supply operations, partially offset by lower volumes.
        ~~The $28 million increase in customer supply gross margin during the nine months ended September 30, 2009 compared to the same period of 2008 is primarily due to:~~
•
~~$88 million of higher gross margin mostly related to the consolidation of a retail power supply VIE for which we became the primary beneficiary in December 2008, and~~
•
$10 million related to higher realization of contracts executed in prior periods and higher margins on new business originated and realized during the nine months ended September 30, 2009 primarily in our wholesale and retail power supply operations, partially offset by lower volumes.
        ~~These increases were partially offset by the following:~~
•
$62 million of lower gross margin as a result of lower customer retention and unfavorable variable load risk associated with wholesale and retail power primarily due to variances from normal weather and lower demand, and

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•
~~$8 million of lower mark-to-market results primarily in our retail gas operation. We discuss these results in more detail in the Mark-to-Market section beginning on page 53.~~
        ~~During the quarter and nine months ended September 30, 2009, the higher margin related to the consolidated retail power supply VIE is fully attributable to noncontrolling interests.~~
~~Global Commodities~~
~~We present Global Commodities results in the following categories:~~
•
Portfolio Management and Trading—our centralized risk management service related to energy price risk associated with our generation fleet, wholesale and retail customer supply business, and our structured products portfolio.
•
Structured Products—customized risk management products in the power, gas, coal and freight markets (e.g., generation tolls, gas transport and storage, and global coal logistics). As of September 30, 2009, we have reduced our participation in the coal, freight and gas trading markets through the execution of our strategic initiatives.
•
Energy Investments—investments in energy assets that primarily include natural gas properties and a joint interest in an entity that owns dry bulk cargo vessels. As of September 30, 2009, we sold our investment in an entity that owns the dry bulk cargo vessels. We discuss this investment in more detail on page 14 of the~~Notes to Consolidated Financial Statements~~.
        ~~Our portfolio de-risking and liquidity improving activities had a substantial impact on the comparability of results for the quarter and nine months ended September 30, 2009 as discussed below.~~
        The $320 million increase in gross margin from our Global Commodities activities during the quarter ended September 30, 2009 compared to the same period of 2008 is primarily due to $457 million of higher gross margin related to our portfolio management and trading operation. These changes are discussed further in the table below.
        ~~This increase was partially offset by the following:~~
•
$74 million of lower gross margin from our energy investment operation primarily related to lower new business and backlog realized within the quarter including the absence of a $29 million gain on sale of a dry bulk vessel in the third quarter of 2008, and
•
$63 million of lower gross margin in our structured products portfolio primarily as a result of fewer terminations of in-the-money energy purchase and sales contracts during the quarter ended September 30, 2009.
        ~~The $90 million decrease in gross margin from our Global Commodities operation for the nine months ended September 30, 2009 compared to the same period in 2008 is primarily due to:~~
•
~~$143 million of lower gross margin from our energy investments operation primarily related to lower new business and backlog realized within the nine months ended September 30, 2009.~~
•
$108 million of lower gross margin in our structured products portfolio primarily as a result of fewer terminations of in-the-money energy purchase and sales contracts during the nine months ended September 30, 2009 for a cash payment.
        ~~These decreases were partially offset by an increase of $161 million in our portfolio management and trading operation. These changes are discussed further in the table below.~~
        ~~Our portfolio management and trading operation gross margin increased $457 million and $161 million during the quarter and nine months ended September 30, 2009,~~

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~~respectively, compared to the same periods in 2008 primarily due to the following:~~

Quarter Ended
September 30,
Nine Months
Ended
September 30,

2009 vs. 2008

(In millions)

Increase in portfolio management of positions arising from hedges of accrual positions with Generation and Customer Supply activities due to the favorable impact of changes in prices of power, natural gas, and coal
$ 327 $ 484
Increase in gains recognized on hedges due to ineffectiveness and certain cash-flow hedges that no longer qualified for hedge accounting
6 160
Increase primarily due to write-downs of our emission allowance inventory recorded in 2008 that did not recur in the same periods of 2009
56 63
Increase (decrease) in earnings related to our portfolio of contracts subject to mark-to-market accounting. We discuss these results in more detail in theMark-to-Market section below.
19 (543 )
Decrease due to loss reclassified from accumulated other comprehensive loss to earnings in connection with the closing of the sale of our international commodities operation as a result of hedged transactions that were probable of not occurring by the end of the specified contract period.
— (166 )
Increase due to the absence of our international coal and freight operations, which were divested in March 2009, and assignment of certain contracts in the third quarter of 2009
49 108
Increase due to the absence of a loss as a result of the bankruptcy of one of our domestic coal suppliers. During the first quarter of 2008, as a result of a default by the supplier, we terminated our derivative contracts with the supplier, reclassified the related asset to accounts receivable and fully reserved the amount.
— 55

Total increase in portfolio management and trading gross margin
$ 457 $ 161

2010 vs. 2009

(In millions)

Realization of lower volumes on wholesale power purchases
$ (538 )
Decrease due to the absence of costs at our international coal and freight operation, which we divested in 2009
(129 )
Decrease in volume and contract prices related to our domestic coal operation
(116 )
Decrease in wholesale mark-to-market expenses due to the absence of losses on international coal purchase contracts, which we divested in 2009
(106 )
Realization of lower volumes primarily due to the absence of costs at our gas trading operations, which we divested in 2009
(74 )
All other
(18 )

Total decrease in NewEnergy fuel and purchased energy expenses
$ (981 )

Mark-to-Market
Mark-to-market results include net gains and losses from origination, risk management and trading activities for which we use the mark-to-market method of accounting. We discuss these activities and the mark-to-market method of accounting in more detail in theCritical Accounting Policies section of our ~~2008~~2009 Annual Report on Form 10-K.
        The nature of our operations and the use of mark-to-market accounting for certain activities create fluctuations in mark-to-market earnings. We cannot predict these fluctuations, but the impact on our earnings could be material. We discuss our market risk in more detail in theRisk Management section beginning on page ~~72.~~57. The primary factors that cause fluctuations in our mark-to-market results are:
•
changes in the level and volatility of forward commodity prices and interest rates,
•
counterparty creditworthiness,
•
the number and size of our open derivative positions, and
•
the number, size, and profitability of new transactions, including termination or restructuring of existing contracts.
        ~~As discussed earlier,~~During 2009, we ~~are continuing to assess the ongoing capital requirements of the merchant energy business and are continuing to implement various alternative strategies. Additionally, we have~~ focused our activities on reducing capital requirements, reducing long-term economic risk, and reducing ~~short-term~~short- and interim-term liquidity requirements. These actions may impact the future results of the ~~merchant energy~~NewEnergy business, particularly the size of and potential for changes in fair value of activities subject to mark-to-market accounting.
        The primary components of mark-to-market results are origination gains and gains and losses from risk management and trading activities.
        Origination gains arise primarily from contracts that our ~~Global Commodities operation~~NewEnergy business structures to meet the risk management needs of our customers or relate to our trading activities. Transactions that result in origination gains may be unique and provide the potential for individually significant revenues and gains from a single transaction. We did not record any origination gains during the quarters ended March 31, 2010 and 2009.
        Risk management and trading—mark-to-market represents both realized and unrealized gains and losses from changes in the value of our portfolio, including the effects of changes in valuation adjustments. In addition to our fundamental risk management and trading activities, we also use non-trading derivative contracts subject to mark-to-market accounting to manage our exposure to changes in market prices, while in general the underlying physical transactions related to these activities are accounted for on an accrual basis.

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~~for on an accrual basis.~~        We discuss the changes in mark-to-market results below. We show the relationship between our mark-to-market results and the change in our net mark-to-market energy asset later in this section.
        Mark-to-market results were as follows:

Quarter Ended
September 30,
Nine Months
Ended
September 30,

Quarter Ended
March 31,

2009
2008
2009
2008

2010
2009

(In millions)

(In millions)

Unrealized mark-to-market results
Unrealized mark-to-market results

Unrealized mark-to-market results

Origination gains
$ — $ 5.3 $ — $ 73.8
Origination gains
$ — $ —

Risk management and trading—mark-to-market

Risk management and trading—mark-to-market

Unrealized changes in fair value
(36.2 ) (194.5 )

Unrealized changes in fair value
(16.2 ) (54.4 ) (233.2 ) 243.1
Changes in valuation techniques
— —

Changes in valuation techniques
— — — —
Reclassification of settled contracts to realized
(190.1 ) (316.7 )

Reclassification of settled contracts to realized
(124.7 ) 288.1 (282.6 ) 141.2

Total risk management and trading—mark-to-market
(226.3 ) (511.2 )

Total risk management and trading—mark-to-market
(140.9 ) 233.7 (515.8 ) 384.3

Total unrealized mark-to-market*
Total unrealized mark-to-market*
(140.9 ) 239.0 (515.8 ) 458.1
Total unrealized mark-to-market*
(226.3 ) (511.2 )
Realized mark-to-market
Realized mark-to-market
124.7 (288.1 ) 282.6 (141.2 )
Realized mark-to-market
190.1 316.7

Total mark-to-market results**
Total mark-to-market results**
$ (16.2 ) $ (49.1 ) $ (233.2 ) $ 316.9
Total mark-to-market results**
$ (36.2 ) $ (194.5 )

* Total unrealized mark-to-market is the sum of origination gains and total risk management and trading—mark-to-market.
** Includes gains (losses) on hedge ineffectiveness for fair value hedges recorded in gross margin.
        Total mark-to-market results increased ~~$32.9~~$158.3 million during the quarter ended ~~September 30, 2009~~March 31, 2010 compared to the same period of ~~2008. This change was primarily~~2009 due to ~~a decrease~~unrealized changes in ~~unrealized risk management and trading losses of $38.2 million, partially offset by a decrease in origination gains of $5.3 million. We discuss origination gains below.~~
        ~~The increase in risk management and trading results of $38.2 million is~~fair value primarily due to:
•
$~~147~~172 million of higher results on open positions primarily due to the absence of losses in our power and transmission risk management activities ~~primarily~~ in the PJM, Northeast, and New York regions as a result of ~~our de-risking and liquidity improving activities and~~ a more favorable price environment ~~in the third quarter of 2009,~~and our activities to reduce risk and improve liquidity, and
•
$657 million of higher results in our ~~international~~domestic coal ~~and freight operation primarily~~portfolio due to the absence of losses asthat resulted from a ~~result of its divestiture in March 2009,~~
•
~~$36 million of higher results on open positions primarily related to a more favorable price environment in our domestic coal portfolio, and~~
•
~~$22 million of lower losses in our retail gas portfolio primarily due to a more~~less favorable price environment in the ~~third~~first quarter of 2009.
        These increases were partially offset by the following:
•
$~~193~~16 million of lower results indue to the absence of our ~~wholesale natural gas risk management~~international coal and ~~trading operation primarily~~freight operations as a result of its divestiture in ~~the beginning of April~~March 2009, and
•
$~~39 million of lower results related to our emissions trading activities primarily as a result of a less favorable price environment.~~
        Total mark-to-market results decreased $550.1 million during the nine months ended September 30, 2009 compared to the same period of 2008. The period-to-period variance in unrealized changes in fair value was primarily due to increased unrealized risk management and trading losses of $476.3 million and the decrease in origination gains of $73.8 million. We discuss origination gains below.
        ~~The decrease in risk management and trading results of $476.3 million is primarily due to:~~
•
$206 million of lower results on open positions in our power and transmission risk management activities primarily in the PJM, Northeast, and New York regions due to our de-risking and liquidity improving activities and a less favorable price environment and strong results in the second quarter of 2008 that did not recur in the same period of 2009,
•
~~$162~~5 million of lower gains ~~on open positions primarily related~~due to ~~less favorable prices in our domestic coal portfolio,~~
•
~~$71 million~~the absence of ~~lower gains in~~ our wholesale natural gas risk management and trading operation primarily as a result of the divestiture of our natural gas trading operation in ~~the beginning of~~ April ~~2009, and~~
•
~~$37 million of lower results related to our emissions trading activities primarily as a result of a less favorable price environment.~~2009.
        We did not record any origination gains during the nine months ended September 30, 2009. During the nine months ended September 30, 2008, our Global Commodities operation amended certain nonderivative contracts to mitigate counterparty performance risk under the existing contracts. As a result of these amendments, the revised contracts became derivatives subject to mark-to-market accounting. The change in accounting for these contracts from nonderivative to derivative resulted in substantially all of the origination gains for 2008 presented in the table above.

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Derivative Assets and Liabilities
Derivative assets and liabilities, excluding $341.4 million of exchange-traded derivatives classified as accounts receivable, consisted of the following:

September 30,
2009
December 31,
2008
March 31,
2010
December 31,
2009

(In millions)
(In millions)

Current Assets
$ 582.8 $ 1,465.0 $ 686.0 $ 639.1
Noncurrent Assets
917.7 851.8 731.4 633.9

Total Assets
1,500.5 2,316.8 1,417.4 1,273.0

Current Liabilities
823.1 1,241.8 906.7 632.6
Noncurrent Liabilities
964.8 1,115.0 812.9 674.1

Total Liabilities
1,787.9 2,356.8 1,719.6 1,306.7

Net Derivative Position
$ (287.4 ) $ (40.0 ) $ (302.2 ) $ (33.7 )

Composition of net derivative position:

Hedges
$ (851.3 ) $ (1,837.6 ) $ (993.9 ) $ (591.0 )
Mark-to-market
738.6 1,485.9 604.8 524.3
Net cash collateral included in derivative balances
(174.7 ) 311.7 86.9 33.0

Net Derivative Position
$ (287.4 ) $ (40.0 ) $ (302.2 ) $ (33.7 )

Derivative balances above include noncurrent assets related to our Generation business of $44.4 million and $35.8 million for the periods ended March 31, 2010 and December 31, 2009, respectively. Derivative balances related to our Generation business consist of interest rate contracts accounted for as fair value hedges. We discuss our derivative assets and liabilities in further detail in the Notes to Consolidated Financial Statements.
        As discussed in theCritical Accounting Policies section of our ~~2008~~2009 Annual Report on Form 10-K, our "Derivative assets and liabilities" include contracts accounted for as hedges and those accounted for on a mark-to-market basis. These amounts are presented in our Consolidated Balance Sheets after the impact of legally binding master netting agreements. Due to the impacts of commodity prices, the number of open positions, master netting arrangements, and offsetting risk positions on the presentation of our derivative assets and liabilities in our Consolidated Balance Sheets, we believe an evaluation of the net position is the most relevant measure, and is discussed in more detail below.
        The ~~decrease~~increase in our net derivative liability subject to hedge accounting since December 31, ~~2008~~2009 of ~~$986.3~~$402.9 million was due primarily to ~~$1,338 million of realization of out-of-the-money cash-flow hedges, partially offset by $352~~$516 million of increases on our out-of-the-money cash-flow hedge positions primarily related to decreases in power and natural gas ~~and coal~~ prices during the ~~nine months ended September 30, 2009.~~first quarter of 2010, partially offset

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by $113 million of realization of out-of-the-money cash-flow hedges of wholesale and retail load obligations.
        The following are the primary sources of the change in ~~the~~our net ~~mark-to-market~~ derivative asset subject to mark-to-market accounting during the quarter ~~and nine months~~ ended ~~September 30, 2009:~~March 31, 2010:

Quarter Ended
September 30, 2009
Nine Months Ended
September 30, 2009

(in millions)

(In millions)

Fair value beginning of period
Fair value beginning of period
$ 801.2 $ 1,485.9
Fair value beginning of period
$ 524.3
Changes in fair value recorded in earnings
Changes in fair value recorded in earnings

Changes in fair value recorded in earnings

Origination gains
$ — $ —
Origination gains
$ —

Unrealized changes in fair value
(16.2 ) (233.2 )
Unrealized changes in fair value
(36.2 )

Changes in valuation techniques
— —
Changes in valuation techniques
—

Reclassification of settled contracts to realized
(124.7 ) (282.6 )
Reclassification of settled contracts to realized
(190.1 )

Total changes in fair value
Total changes in fair value
(140.9 ) (515.8 )
Total changes in fair value
(226.3 )
Changes in value of exchange-listed futures and options
Changes in value of exchange-listed futures and options
27.8 355.9
Changes in value of exchange-listed futures and options
172.1
Net change in premiums on options
Net change in premiums on options
32.0 41.0
Net change in premiums on options
103.0
Contracts acquired
Contracts acquired
— (35.8 )
Contracts acquired
—
Dedesignated contracts and other changes in fair value
Dedesignated contracts and other changes in fair value
18.5 (592.6 )
Dedesignated contracts and other changes in fair value
31.7

Fair value at end of period
Fair value at end of period
$ 738.6 $ 738.6
Fair value at end of period
$ 604.8

        Changes in our net derivative asset that affected earnings were as follows:
•
Origination gains represent the initial unrealized fair value at the time these contracts are executed to the extent permitted by applicable accounting rules.
•
Unrealized changes in fair value represent unrealized changes in commodity prices, the volatility of options on commodities, the time value of options, and other valuation adjustments.
•
Changes in valuation techniques represent improvements in estimation techniques, including modeling and other statistical enhancements used

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to value our portfolio to more accurately reflect the economic value of our contracts.
•
Reclassification of settled contracts to realized represents the portion of previously unrealized amounts settled during the period and recorded as realized revenues.
        The net derivative asset also changed due to the following items recorded in accounts other than in our Consolidated Statements of Income (Loss):
•
Changes in value of exchange-listed futures and options are adjustments to remove unrealized revenue from exchange-traded contracts that are included in risk management revenues. The fair value of these contracts is recorded in "Accounts receivable" rather than "Derivative assets" in our Consolidated Balance Sheets because these amounts are settled through our margin account with a third-party broker.
•
Net changes in premiums on options reflects the accounting for premiums on options purchased as an increase in the net derivative asset and premiums on options sold as a decrease in the net derivative asset.
•
Contracts acquired represents the initial fair value of acquired derivative contracts recorded in "Derivative assets and liabilities" in our Consolidated Balance Sheets. Substantially all of this activity for the nine months ended September 30, 2009 related to the divestiture of our international commodities operation, Houston-based gas trading operation, and certain other trading operations in order to transfer risk and reward to the buyers. We discuss these divestitures in more detail beginning on page 16 of the~~Notes to Consolidated Financial Statements~~.
•
Dedesignated contracts and other changes in fair value represent transfers of derivative contracts from cash flow hedges to mark-to-market treatment ~~transfers of derivative contracts from mark-to-market treatment to cash flow hedges,~~ and those derivative contracts that did not meet the qualifications of cash flow hedge accounting. In the quarter and nine months ended September 30, 2009, substantially all of the activity related to dedesignations in connection with the strategic objective of restructuring and reducing the risk of our portfolio.
        The settlement terms of the portion of our net derivative asset subject to mark-to-market accounting and sources of fair value based on the fair value hierarchy are as follows as of ~~September 30, 2009:~~March 31, 2010:

Settlement Term
Settlement Term

2009
2010
2011
2012
2013
2014
Thereafter
Fair Value
2010
2011
2012
2013
2014
2015
Thereafter
Fair Value

(In millions)
(In millions)

Level 1
$ (43.8 ) $ — $ — $ — $ — $ — $ — $ (43.8 ) $ 4.6 $ — $ — $ — $ — $ — $ — $ 4.6
Level 2
209.4 78.5 332.8 143.7 (26.7 ) (3.4 ) 0.2 734.5 291.5 490.6 154.3 (3.2 ) 4.8 7.2 1.3 946.5
Level 3
115.6 285.7 (170.5 ) (200.5 ) (5.2 ) 12.7 10.1 47.9 80.4 (213.7 ) (215.5 ) (18.7 ) 10.7 9.7 0.8 (346.3 )

Total net derivative asset subject to mark-to-market accounting
$ 281.2 $ 364.2 $ 162.3 $ (56.8 ) $ (31.9 ) $ 9.3 $ 10.3 $ 738.6
Total net derivative asset (liability) subject to mark-to-market accounting
$ 376.5 $ 276.9 $ (61.2 ) $ (21.9 ) $ 15.5 $ 16.9 $ 2.1 $ 604.8

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        Management uses its best estimates to determine the fair value of commodity and derivative contracts it holds and sells. These estimates consider various factors including closing exchange and over-the-counter price quotations, time value, volatility factors, and credit exposure. Additionally, because the depth and liquidity of the power markets varies substantially between regions and time periods, the prices used to determine fair value could be affected significantly by the volume of transactions executed. Future market prices and actual quantities will vary from those used in recording mark-to-market energy assets and liabilities, and it is possible that such variations could be material.
        We manage our mark-to-market risk on a portfolio basis based upon the delivery period of our contracts and the individual components of the risks within each contract. Accordingly, we manage the energy purchase and sale obligations under our contracts in separate components based upon the commodity (e.g., electricity or gas), the product (e.g., electricity for delivery during peak or off-peak hours), the delivery location (e.g., by region), the risk profile (e.g., forward or option), and the delivery period (e.g., by month and year).
        The electricity, fuel, and other energy contracts we hold have varying terms to maturity, ranging from contracts for delivery the next hour to contracts with terms of ten years or more. Because an active, liquid electricity futures market comparable to that for other commodities has not developed, many contracts are direct contracts between market participants and are not exchange-traded or financially settling contracts that can be readily offset in their entirety through an exchange or other market

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mechanism. Consequently, we and other market participants generally realize the value of these contracts as cash flows become due or payable under the terms of the contracts rather than through selling or liquidating the contracts themselves.
        In order to realize the entire value of a long-term contract in a single transaction, we would need to sell or assign the entire contract. If we were to sell or assign any of our long-term contracts in their entirety, we may not realize the entire value reflected in the preceding table. However, based upon the nature of ~~the global commodities operation,~~our operations, we expect to realize the value of these contracts, as well as any contracts we may enter into in the future to manage our risk, over time as the contracts and related hedges settle in accordance with their terms. Generally, we do not expect to realize the value of these contracts and related hedges by selling or assigning the contracts themselves in total.
Operating Expenses
Our ~~merchant energy~~NewEnergy business operating expenses ~~increased $74.8~~decreased $20.1 million ~~for~~during the quarter ended ~~September 30, 2009~~March 31, 2010 as compared to the same period of ~~2008~~2009 primarily due to ~~higher performance-based~~lower labor and benefit costs of ~~$53.7 million and higher non-labor operating expenses of $21.1 million.~~
        Our merchant energy business operating expenses decreased $84.0 million for the nine months ended September 30, 2009 as compared to the same period of 2008 primarily due to lower performance-based labor and benefit costs of $69.5$17.9 million and lower non-labor operating expenses of ~~$14.5~~$2.2 million.
Merger Termination and Strategic Alternatives Costs
We discuss costs related to the ~~mergers~~terminated merger with MidAmerican, the conversion of our Series A Preferred Stock, our transaction with EDF and our pursuit of other strategic alternatives in ~~more detail on page 12 in~~~~Notes~~Note 2 to Consolidated Financial Statements.
~~Impairment losses and Other Costs~~
~~Our impairment losses and other costs are discussed in more detail beginning on page 14 in~~~~Notes to Consolidated Financial Statements~~.
~~Workforce Reduction Costs~~
~~Our merchant energy business recognized expenses associated with our workforce reduction efforts as discussed in more detail on page 15 in~~~~Notes to Consolidated Financial Statements~~.
~~Amortization of Credit Facility Amendment Fees~~
Our merchant energy business incurred costs related to the amortization of credit facility amendment fees in connection with the EDF transaction. These costs are classified as interest expense in our Consolidated Statements of Income (Loss).
Depreciation, Depletion and Amortization Expense
Our ~~merchant energy~~NewEnergy business incurred ~~lower~~higher depreciation, depletion and amortization expenses of ~~$9.5~~$1.5 million during the ~~nine months~~quarter ended ~~September 30, 2009~~March 31, 2010 compared to the same period of ~~2008~~2009 primarily due to ~~the absence of~~an increase in depletion expenses ~~of $27.1 million as a result of divestitures made in 2008 in~~related to our upstream gas ~~operations, partially offset by an increase~~operations.
Taxes Other Than Income Taxes
Taxes other than income taxes increased $1.7 million during the quarter ended March 31, 2010 compared to the same period of ~~$17.6~~2009 primarily due to $1.3 million of higher production taxes related to our upstream gas producing properties and $0.4 million of higher gross receipts, value-added and other taxes.
Gain (Loss) on Divestitures
During the quarter ended March 31, 2010, we sold a portfolio of contracts in ~~depreciation~~our retail gas division and recognized a $2.0 million gain.
        During the quarter ended March 31, 2009, we sold a majority of our international commodities operation, and we recognized a net loss of $334.5 million. We discuss this divestiture in more detail inNote 2 of our 2009 Annual Report on ~~our generating facilities.~~Form 10-K.

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Regulated Electric Business
Our regulated electric business is discussed in detail inItem 1. Business—Electric Business section of our ~~2008~~2009 Annual Report on Form 10-K.
Results

Quarter Ended
September 30,
Nine Months Ended
September 30,
Quarter Ended
March 31,

2009
2008
2009
2008
2010
2009

(In millions)
(In millions)

Revenues
$ 788.3 $ 822.4 $ 2,250.8 $ 1,980.5 $ 751.3 $ 806.8
Electricity purchased for resale expenses
(508.2 ) (556.6 ) (1,435.9 ) (1,416.2 ) (473.6 ) (525.2 )
Operations and maintenance expenses
(102.6 ) (99.0 ) (297.6 ) (291.9 ) (113.8 ) (91.1 )
Merger termination and strategic alternatives costs
— (7.9 ) — (7.9 )
Depreciation and amortization
(51.1 ) (39.4 ) (161.6 ) (138.0 ) (56.4 ) (55.5 )
Taxes other than income taxes
(36.5 ) (36.3 ) (109.8 ) (104.1 ) (37.2 ) (37.3 )

Income from Operations
$ 89.9 $ 83.2 $ 245.9 $ 22.4 $ 70.3 $ 97.7

Net Income (Loss)
$ 42.3 $ 34.3 $ 109.8 $ (31.2 )
Net Income
$ 27.2 $ 45.4

Net Income (Loss) attributable to common stock
$ 39.8 $ 31.7 $ 102.2 $ (38.8 )
Net income attributable to common stock
$ 24.6 $ 42.9

Other Items Included in Operations (after-tax):

Accrual of Maryland settlement credit
$ — $ — $ — $ (125.3 )
Effective tax rate impact of Maryland settlement agreement
— 3.4 — 8.4
Merger termination and strategic alternatives costs*
— (7.5 ) — (7.5 )
Deferred income tax expense relating to federal subsidies for providing post-employment prescription drug benefits
$ (3.1 ) $ —

Total Other Items
$ — $ (4.1 ) $ — $ (124.4 )

Above amounts include intercompany transactions eliminated in our Consolidated Financial Statements. The Information by Operating Segment section within the Notes to Consolidated Financial Statements on page 2015 provides a reconciliation of operating results by segment to our Consolidated Financial Statements.
* Recovery of these costs will not be sought in rates.
        Net income attributable to common stock from the regulated electric business ~~increased $8.1~~decreased $18.3 million ~~for~~during the quarter ended ~~September 30, 2009~~March 31, 2010 compared to the same period ~~of 2008,~~in 2009, primarily due to ~~an increase~~a decrease in revenues less electricity purchased for resale expenses of ~~$9.0~~$2.3 million after-tax, ~~and the absence in 2009 of merger termination and strategic alternatives costs of $7.5 million after-tax, partially offset by increased depreciation and amortization of $7.4 million after-tax.~~
        Net income attributable to common stock from the regulated electric business for the nine months ended September 30, 2009 exceeded the net loss attributable to common stock from the regulated electric business for the nine months ended September 30, 2008 by $141.0 million, mostly due to increased revenues less electricity purchased for resale expenses of $151.9 million after-tax, which was due to the absence in 2009 of the impact of the accrual of the Maryland settlement credit of $125.3 million after-tax in 2008, and the absence in 2009 of merger termination and strategic alternatives costs of $7.5 million after-tax. These increases were partially offset by increased depreciation and amortization of $14.3 million after-tax and increased operations and maintenance expenses of ~~$3.4~~$13.3 million ~~after-tax.~~after-tax, and the additional deferred income tax expense of $3.1 million relating to federal subsidies for providing post-employment prescription drug benefits as a result of new legislation in March 2010.
Electric Revenues
The changes in electric revenues ~~in 2009~~during the quarter ended March 31, 2010 compared to ~~2008~~the same period of 2009 were caused by:

Quarter Ended
September 30,
2009 vs. 2008
Nine Months Ended
September 30,
2009 vs. 2008
Quarter Ended
March 31,
2010 vs. 2009

(In millions)
(In millions)

Distribution volumes
$ (8.8 ) $ (8.1 ) $ (1.1 )
Nuclear decommissioning charges
5.1 14.2
Smart energy savers program^SM surcharges
10.2 21.3
Maryland settlement credit
0.6 188.8
Revenue decoupling
5.6 16.0
Smart Energy Savers Program^SM surcharges
(1.3 )
Standard offer service
(46.6 ) 22.7 (52.4 )
Rate stabilization recovery
(2.8 ) (0.5 ) (1.2 )
Financing credits
1.3 2.4
Senate Bill 1 credits
(0.2 ) 7.2

Total change in electric revenues from electric system sales
(35.6 ) 264.0 (56.0 )
Other
1.5 6.3 0.5

Total change in electric revenues
$ (34.1 ) $ 270.3 $ (55.5 )

Distribution Volumes
Distribution volumes are the amount of electricity that BGE delivers to customers in its service territory.

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        The percentage changes in our electric distribution volumes, by type of customer, ~~in 2009 compared to 2008 were:~~

Quarter Ended
September 30,
2009 vs. 2008
Nine Months Ended
September 30,
2009 vs. 2008

Residential
(0.5 )% (2.2 )%
Commercial
(3.0 ) 0.9
Industrial
(13.3 ) (9.8 )
        ~~During~~during the quarter ended ~~September 30, 2009~~March 31, 2010 compared to the same period of 2009 were:

Quarter Ended
March 31,
2009 vs. 2008
Residential
0.6 %
Commercial
0.9
Industrial
(1.7 )
        During the quarter ended March 31, 2010, we distributed less electricity to ~~commercial customers due to decreased usage per customer and milder weather, partially offset by an increased number of customers. We distributed less electricity to~~ industrial ~~customers primarily due to decreased usage per customer.~~
        ~~During the nine months ended September 30, 2009 compared to the same period of 2008, we distributed less electricity to residential~~ customers mostly due to decreased usage per ~~customer, partially offset by colder weather and an increased number of customers. We distributed less electricity to industrial customers primarily due to decreased usage per~~ customer.
~~Nuclear Decommissioning Charges~~
Effective January 1, 2009, BGE and Calvert Cliffs Nuclear Power Plant Inc. (Calvert Cliffs) mutually agreed to terminate the decommissioning funds collection agent agreement, which was effective from July 1, 2000 to December 31, 2008. As a result, BGE ceased transferring funds to provide for the decommissioning of Calvert Cliffs Unit 1 and Unit 2. Calvert Cliffs retains the obligation to provide adequate assurances of funding pursuant to Nuclear Regulatory Commission requirements. Under the 2008 Maryland settlement agreement, BGE will continue to provide certain credits to residential customers and assess certain charges to all customers relating to decommissioning.
Smart Energy Savers Program^SM Surcharges
Beginning in 2009, the Maryland PSC approved customer surcharges through which BGE recovers costs associated with certain programs designed to help BGE manage peak demand and encourage customer energy conservation.
~~Maryland Settlement Credit~~
In 2008, BGE entered into a settlement agreement with the State of Maryland and other parties, which provided residential electric customers a credit totaling $170 per customer. The total settlement of $188.2 million was accrued in the second quarter of 2008 and $188.8 million was credited to customers in the third quarter of 2008.
~~Revenue Decoupling~~
The Maryland PSC has allowed us to record a monthly adjustment to our electric distribution revenues from residential and small commercial customers since 2008 and for the majority of our large commercial and industrial customers since February 2009 to eliminate the effect of abnormal weather and usage patterns per customer on our electric distribution volumes, thereby recovering a specified dollar amount of distribution revenues per customer, by customer class, regardless of changes in consumption levels. This means BGE recognizes revenues at Maryland PSC-approved levels per customer, regardless of what actual distribution volumes were for a billing period. Therefore, while these revenues are affected by customer growth, they will not be affected by actual weather or usage conditions. We then bill or credit impacted customers in subsequent months for the difference between approved revenue levels under revenue decoupling and actual customer billings.
Standard Offer Service
BGE provides standard offer service for customers that do not select an alternative supplier. We discuss the provisions of Maryland's Senate Bill 1 related to residential electric rates in ~~the~~Item 7. Management's Discussion and Analysis—Business Environment—Regulation—Maryland—Senate Bills 1

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and 400 section of our ~~2008~~2009 Annual Report on Form 10-K.
        Standard offer service revenues decreased during the quarter ended ~~September 30, 2009~~March 31, 2010 compared to the same period of ~~2008,~~2009 mostly due to ~~lower standard offer service volumes.~~
        ~~Standard offer service revenues increased during the nine months ended September 30, 2009 compared to the same period of 2008, mostly due to an increase~~a decrease in the standard offer service rates ~~partially offset by~~and lower standard offer service volumes.
Rate Stabilization Recovery
In late June 2007, BGE began recovering amounts deferred during the first rate deferral period that ended on May 31, 2007. The recovery of the first rate stabilization plan will occur over approximately ten years. In April 2008, BGE began recovering amounts deferred during the second rate deferral period that ended on December 31, 2007. The recovery of the second rate deferral ~~will occur~~occurred over a 21-month period that began April 1, 2008 and ~~ends~~ended on December 31, 2009.
~~Financing Credits~~
Concurrent with the recovery of the deferred amounts related to the first rate deferral period, we are providing credits to residential customers to compensate them primarily for income tax benefits associated with the financing of the deferred amounts with rate stabilization bonds.

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~~Senate Bill 1 Credits~~
As a result of Senate Bill 1, beginning January 1, 2007, we were required to provide to residential electric customers a credit equal to the amount collected from all BGE electric customers for the decommissioning of Calvert Cliffs and to suspend collection of the residential return component of the administrative charge collected through residential standard offer service rates through May 31, 2007. Under an order issued by the Maryland PSC in May 2007, as of June 1, 2007, we were required to reinstate collection of the residential return component of the administration charge in rates and to provide all residential electric customers a credit for the residential return component of the administrative charge. Under the 2008 Maryland settlement agreement, BGE was allowed to resume collection of the residential return portion of the administrative charge from June 1, 2008 through May 31, 2010 without having to rebate it to residential customers.
        The increase in revenues during the nine months ended September 30, 2009 compared to the same period of 2008 is primarily due to the absence of the credit for the residential return component of the administrative charge which was suspended under the Maryland settlement agreement.
Electricity Purchased for Resale Expenses
Electricity purchased for resale expenses include the cost of electricity purchased for resale to our standard offer service customers. These costs do not include the cost of electricity purchased by delivery service only customers. The following table summarizes our regulated electricity purchased for resale expenses:

Quarter Ended
September 30,
Nine Months Ended
September 30,
Quarter Ended
March 31,

2009
2008
2009
2008
2010
2009

(In millions)
(In millions)

Actual costs
$ 489.9 $ 537.7 $ 1,391.3 $ 1,372.0 $ 458.1 $ 509.4
Recovery under rate stabilization plans
18.3 18.9 44.6 44.2
Recovery under rate stabilization plan
15.5 15.8

Electricity purchased for resale expenses
$ 508.2 $ 556.6 $ 1,435.9 $ 1,416.2 $ 473.6 $ 525.2

Actual Costs
BGE's actual costs for electricity purchased for resale decreased ~~$47.8~~$51.3 million during the quarter ended ~~September 30, 2009~~March 31, 2010 compared to the same period of ~~2008,~~2009 primarily due to lower ~~volumes.~~
        ~~BGE's actual costs for electricity purchased for resale increased $19.3 million during the nine months ended September 30, 2009 compared to the same period of 2008, primarily due to higher~~ contract prices to purchase electricity for our customers ~~partially offset by~~and lower volumes.
Recovery ~~Under~~under Rate Stabilization Plan
In late June 2007, we began recovering previously deferred amounts from customers. ~~During~~We recovered $15.5 million during the quarter ~~and nine months~~ ended ~~September 30, 2009, $17.2 million and $41.5 million, respectively, of the amount recovered secures~~March 31, 2010 in deferred electricity purchased for resale expenses. These collections secure the payment of principal and interest and other ongoing costs associated with rate stabilization bonds issued by a subsidiary of BGE in June 2007.
Electric Operations and Maintenance Expenses
Regulated electric operations and maintenance expenses increased ~~$5.7~~$22.7 million in the ~~nine months~~quarter ended ~~September 30, 2009~~March 31, 2010 compared to the same period ~~of 2008,~~in 2009 primarily due to ~~increased uncollectible accounts receivable expense of $13.6 million, partially offset by the absence of $8.1~~$17.3 million in incremental distribution service restoration expenses associated with ~~2008 storms.~~
        ~~We discuss the Allowance for Uncollectible Accounts Receivable in more detail on page 63.~~
~~Electric Depreciation~~2010 storms and ~~Amortization~~
Regulated electric depreciation and amortization expense increased $11.7 million during the quarter ended September 30, 2009, compared to the same period in 2008, primarily due to $17.2 million in increased amortization expense associated with the Smart Energy Savers Program^SM and additional property placed in service in 2009, partially offset by $5.7 million in lower depreciation expense as a result of revised depreciation rates which were implemented on June 1, 2008 for regulatory and financial reporting purposes as part of the Maryland settlement agreement.
        Regulated electric depreciation and amortization expense increased $23.6 million during the nine months ended September 30, 2009, compared to the same period in 2008, primarily due to $29.1 million in increased amortization expense associated with the Smart Energy Savers Program^SM and increased depreciation primarily due to additional property placed in service in 2009, partially offset by $17.1 million in lower depreciation expense as a result of revised depreciation rates which were implemented on June 1, 2008 for regulatory and financial reporting purposes as part of the Maryland settlement agreement.
        ~~The Maryland settlement agreement is discussed in more detail in~~~~Note 2 to Consolidated Financial Statements~~ ~~of our 2008 Annual Report on Form 10-K.~~
~~Taxes Other Than Income Taxes~~
~~Taxes other than income taxes increased $5.7 million during the nine months ended September 30, 2009, respectively, compared to the same period in 2008, primarily due to the absence of~~ the impact of ~~the Maryland settlement agreement~~inflation on ~~franchise taxes.~~

~~Table~~other costs of ~~Contents~~$2.9 million.
Regulated Gas Business
Our regulated gas business is discussed in detail inItem 1. Business—Gas Business section of our ~~2008~~2009 Annual Report on Form 10-K.
Results

Quarter Ended
September 30,
Nine Months Ended
September 30,

2009
2008
2009
2008

(In millions)

Revenues
$ 78.2 $ 155.5 $ 576.8 $ 740.0
Gas purchased for resale expenses
(31.2 ) (107.5 ) (340.9 ) (505.2 )
Operations and maintenance expenses
(40.0 ) (40.5 ) (120.9 ) (118.0 )
Merger termination and strategic alternatives costs
— (3.2 ) — (3.2 )
Depreciation and amortization
(10.6 ) (10.1 ) (32.7 ) (33.2 )
Taxes other than income taxes
(7.6 ) (7.8 ) (26.5 ) (26.6 )

(Loss) Income from operations
$ (11.2 ) $ (13.6 ) $ 55.8 $ 53.8

Net (Loss) Income
$ (10.5 ) $ (11.5 ) $ 22.9 $ 26.4

Net (Loss) Income attributable to common stock
$ (11.3 ) $ (12.2 ) $ 20.6 $ 24.1

Other Items Included in Operations (after-tax):

Effective tax rate impact of Maryland settlement agreement
$ — $ (1.4 ) $ — $ 2.3
Merger termination and strategic alternatives costs*
— (3.1 ) — (3.1 )

Total Other Items
$ — $ (4.5 ) $ — $ (0.8 )

Quarter Ended
March 31,

2010
2009

(In millions)

Revenues
$ 318.0 $ 386.9
Gas purchased for resale expenses
(194.5 ) (258.1 )
Operations and maintenance expenses
(35.2 ) (35.9 )
Depreciation and amortization
(11.3 ) (11.4 )
Taxes other than income taxes
(10.4 ) (10.4 )

Income from operations
$ 66.6 $ 71.1

Net Income
$ 37.2 $ 39.6

Net Income attributable to common stock
$ 36.5 $ 38.8

Above amounts include intercompany transactions eliminated in our Consolidated Financial Statements. The Information by Operating Segment section within the Notes to Consolidated Financial Statements on page 2015 provides a reconciliation of operating results by segment to our Consolidated Financial ~~Statements~~
* Recovery of these costs will not be sought in rates.Statements.

        ~~Net income attributable to common stock from the regulated gas business decreased $3.5 million during the nine months ended September 30, 2009, compared to the same period~~Table of ~~2008, primarily due to the absence in 2009 of the impact of reduced earnings in 2008 from the Maryland settlement agreement on our effective tax rate of $2.3 million.~~Contents
Gas Revenues
The changes in gas revenues ~~in 2009~~during the quarter ended March 31, 2010 compared to ~~2008~~the same period of 2009 were caused by:

Quarter Ended
September 30,
2009 vs. 2008
Nine Months Ended
September 30,
2009 vs. 2008
Quarter Ended
March 31,
2010 vs. 2009

(In millions)
(In millions)

Distribution volumes
$ (0.5 ) $ 5.0 $ (2.7 )
Conservation surcharge
0.1 0.7 (0.5 )
Gas revenue decoupling
(0.1 ) (5.2 ) 2.7
Gas cost adjustments
(26.5 ) (58.4 ) (73.9 )

Total change in gas revenues from gas system sales
(27.0 ) (57.9 ) (74.4 )
Off-system sales
(49.9 ) (103.7 ) 4.2
Other
(0.4 ) (1.6 ) 1.3

Total change in gas revenues
$ (77.3 ) $ (163.2 ) $ (68.9 )

Distribution Volumes
The percentage changes in our distribution volumes, by type of customer, ~~in 2009~~during the quarter ended March 31, 2010 compared to ~~2008~~the same period of 2009 were:

Quarter Ended
September 30,
2009 vs. 2008
Nine Months Ended
September 30,
2009 vs. 2008

Residential
(1.4 )% 5.9 %
Commercial
(14.5 ) (7.5 )
Industrial
0.8 4.9

Quarter Ended
March 31,
2010 vs. 2009
Residential
(1.5 )%
Commercial
(10.3 )
Industrial
17.9
        During the quarter ended ~~September 30, 2009 compared to the same period in 2008,~~March 31, 2010, we distributed less gas to residential customers compared to the same period of 2009 mostly due to ~~decreased~~milder weather, partially offset by increased usage per customer ~~partially offset by~~and an increased number of customers. We distributed less gas to commercial customers ~~compared to the same period of 2008,~~mostly due to decreased usage per customer and milder weather, partially offset by an increased number of customers.
        During the nine months ended September 30, 2009 compared to the same period in 2008, we distributed more gas to residential customers due to colder weather and an increased number of customers, partially offset by decreased usage per customer. We distributed less gas to commercial customers due to decreased usage per customer, partially offset by an increased number of customers and colder weather. We distributed more gas to industrial customers mostly due to increased usage per ~~customer, partially offset by a decreased number of customers.~~customer.
Conservation Surcharge
Beginning February 2009, the Maryland PSC approved a customer surcharge through which BGE recovers costs associated with certain programs designed to help BGE encourage customer conservation.

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Gas Revenue Decoupling
The Maryland PSC allows us to record a monthly adjustment to our gas distribution revenues to eliminate the effect of abnormal weather and usage patterns per customer on our gas distribution volumes, thereby recovering a specified dollar amount of distribution revenues per customer, by customer class, regardless of changes in consumption levels. This means BGE recognizes revenues at Maryland PSC-approved levels per customer, regardless of what actual distribution volumes were for a billing period. Therefore, while these revenues are affected by customer growth, they will not be affected by actual weather or usage conditions. We then bill or credit impacted customers in subsequent months for the difference between approved revenue levels under revenue decoupling and actual customer billings.
Gas Cost Adjustments
We charge our gas customers for the natural gas they purchase from us using gas cost adjustment clauses set by the Maryland PSC as described inNote 1 of our ~~2008~~2009 Annual Report on Form 10-K. However, under the market-based rates mechanism approved by the Maryland PSC, our actual cost of gas is compared to a market index (a measure of the market price of gas in a given period). The difference between our actual cost and the market index is shared equally between shareholders and customers.
        Customers who do not purchase gas from BGE are not subject to the gas cost adjustment clauses because we are not selling gas to them. However, these customers are charged base rates to recover the costs BGE incurs to deliver their gas through our distribution system, and the rates charged are included in the gas distribution volume revenues.
        Gas cost adjustment revenues decreased ~~$26.5 million and $58.4~~$73.9 million during the quarter ~~and nine months~~ ended ~~September 30, 2009, respectively,~~March 31, 2010 compared to the same period of ~~2008,~~2009 because we sold less gas at lower ~~prices.~~rates.
Off-System ~~Gas~~ Sales
Off-system ~~gas~~ sales are low-margin direct sales of gas to wholesale suppliers of natural gas. Off-system gas sales, which occur after we have satisfied our customers' demand, are not subject to gas cost adjustments. The Maryland PSC approved an arrangement for part of the margin from off-system sales to benefit customers (through reduced costs) and the remainder to be retained by BGE (which benefits shareholders). Changes in off-system sales do not significantly impact earnings.
        Revenues from off-system gas sales ~~decreased~~increased $4.2 million during the quarter ~~and nine months~~ ended ~~September 30, 2009~~March 31, 2010 compared to the same period of ~~2008 because we sold less gas at~~2009 primarily due to higher prices, partially offset by lower ~~prices.~~volumes.
Gas Purchased For Resale Expenses
Gas purchased for resale expenses include the cost of gas purchased for resale to our customers and for off-system

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sales. These costs do not include the cost of gas purchased by delivery service only customers.
        Gas costs decreased ~~$76.3 million and $164.3~~$63.6 million during the quarter ~~and nine months~~ ended ~~September 30, 2009~~March 31, 2010 compared to the same period of ~~2008~~2009 because we purchased less gas at lower prices.
Other Nonregulated Businesses
Results

Quarter Ended
September 30,
Nine Months Ended
September 30,

2009
2008
2009
2008

(In millions)

Revenues
$ 60.2 $ 50.2 $ 169.1 $ 175.5
Operating expense
(47.6 ) (29.4 ) (131.2 ) (128.4 )
Impairment losses and other costs
— — (6.7 ) —
Merger termination and strategic alternatives costs
— (0.9 ) — (0.9 )
Depreciation and amortization
(17.9 ) (16.2 ) (54.2 ) (45.5 )
Taxes other than income taxes
(1.1 ) (1.2 ) (3.1 ) (2.3 )

(Loss) Income from Operations
$ (6.4 ) $ 2.5 $ (26.1 ) $ (1.6 )

Net (Loss) Income
$ (6.5 ) $ 1.1 $ (17.0 ) $ 0.4

Net (Loss) Income attributable to common stock
$ (6.9 ) $ 0.8 $ (17.5 ) $ 0.3

Other Items Included in Operations (after-tax):

Impairment losses and other costs
$ (0.8 ) $ — $ (3.9 ) $ —
Merger termination and strategic alternatives costs
— (0.9 ) — (0.9 )

Total Other Items
$ (0.8 ) $ (0.9 ) $ (3.9 ) $ (0.9 )

Quarter Ended
March 31,

2010
2009

(In millions)

Revenues
$ — $ 2.5
Operating expenses
15.7 15.2
Depreciation and amortization
(13.9 ) (16.4 )
Taxes other than income taxes
(0.9 ) (0.8 )

Income from Operations
$ 0.9 $ 0.5

Net (Loss) Income
$ (4.3 ) $ 0.1

Net (Loss) Income attributable to common stock
$ (4.3 ) $ 0.1

Other Items Included in Operations (after-tax):

Deferred income tax expense relating to federal subsidies for providing post-employment prescription drug benefits
$ (4.8 ) $ —

Above amounts include intercompany transactions eliminated in our Consolidated Financial Statements. The Information by Operating Segment section within the Notes to Consolidated Financial Statements on page 2015 provides a reconciliation of operating results by segment to our Consolidated Financial Statements.
        Net loss attributable to common stock for the quarter ended March 31, 2010 exceeded net income attributable to common stock ~~during~~for the ~~quarter and nine months ended September 30,~~same period in 2009 by ~~$7.7~~$4.4 million ~~and $17.8 million, respectively, compared to the same periods of 2008~~ primarily due to ~~increased losses from UniStar Nuclear Energy, LLC and other nonregulated operations of $4.4~~$4.8 million ~~and $11.1 million, respectively, increased impairment losses and other costs due to a~~

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~~write-off of an uncollectible advance to an affiliate of $0.8 million and $3.9 million after-tax, respectively, and depreciation and amortization~~in deferred income tax expense recorded as a result of ~~increased property additions during 2008.~~healthcare reform legislation enacted in March 2010 that eliminated the tax exempt status of prescription drug subsidies received by companies under Medicare Part D.
Consolidated Nonoperating Income and Expenses
Other (Expense) Income ~~(Expense)~~
InOther expenses decreased $34.0 million during the quarter ended ~~September 30, 2009, we had other income of $38.7 million and, in the quarter ended September 30, 2008, we had other expenses of $15.8 million. The $54.5 million increase in 2009~~March 31, 2010 compared to ~~2008 is~~the same period of 2009 mostly due to ~~a decrease~~the absence in 2010 of other-than-temporary impairment charges related to ~~our~~ nuclear decommissioning trust fund assets of ~~$30.3 million.~~$60.5 million recorded in 2009.
        ~~Other income decreased $18.9~~Fixed Charges
Fixed charges increased $12.4 million during the ~~nine months~~quarter ended ~~September 30, 2009~~March 31, 2010 compared to the same period of ~~2008 mostly~~2009 due to a lower ~~average cash balance offset by an increase in other-than-temporary impairment charges related to our nuclear decommissioning trust fund assets of $19.5 million.~~
~~Fixed Charges~~
~~Our fixed charges increased during the quarter~~capitalized interest and ~~nine months ended September 30, 2009 compared to the same periods of 2008 mostly due to~~allowance for borrowed funds used for construction and a higher level of interest ~~expense associated with new debt issuances, primarily the Series A and Series B Preferred Stock issuances in 2008, and higher amortization of debt issuance and credit facility costs.~~
        Fixed charges at BGE increased during the nine months ended September 30, 2009 compared to the same period of 2008 mostly due to a higher level of interest expense associated with new debt issuances in 2008 and higher amortization of debt issuance and credit facility costs.expense.
Income Taxes
~~Income~~In the first quarter of 2010, we had income tax expense ~~exceeded~~of $95.6 million and, in the first quarter of 2009, we had income tax ~~benefit by $410.0~~benefits of $242.2 million. The $337.8 million ~~during the quarter ended September 30, 2009 compared~~change is primarily due to ~~the same period of 2008 because we reported~~higher income before income taxes in ~~2009 as~~2010 compared to a loss before income taxes in 2008. The income before income taxes for the quarter required us to change our estimated annual effective tax rate at September 30, 2009, requiring us to reduce the income tax benefit recognized in connection with losses and impairment charges recorded in the first half of 2009.
        Income tax expense increased $87.6 million during the nine months ended September 30, 2009 compared to the same period of 2008 mostly due to higher income before income taxes in 2009 compared to 2008. Additionally, a higher effective tax rate in 2009 ~~increased~~decreased income tax expense because it produced a higher income tax ~~expense~~benefit when applied to the ~~income~~loss before income taxes.
        BGE's income tax expense ~~increased $82.8~~decreased $9.6 million during the ~~nine months~~quarter ended ~~September 30, 2009~~March 31, 2010 compared to the same period of ~~2008,~~2009 mostly due to higher pre-tax income. In addition, for the nine months ended September 30, 2008, BGE had a lower effective tax rate. BGE projected a reduction in its 2008 taxable income as a result of the impact of certain provisions of the 2008 Maryland settlement agreement, which increased the relative impact of the favorable permanent tax adjustments on its effective tax rate.
~~Allowance for Uncollectible Accounts Receivable~~
~~Our allowance for uncollectible accounts receivable decreased $59.7 million from $240.6 million at December 31, 2008 to $180.9 million at September 30, 2009, primarily related to~~ a decrease ~~of $80.3 million~~ in ~~our merchant energy business, partially offset by an increase of $18.7 million at our regulated electric and gas businesses.~~
        The decrease in allowance for uncollectible accounts receivable from our merchant energy business is primarily driven by the write-off of accounts receivable balances of certain customers and the reversal of the related allowance for uncollectible accounts receivable that were established primarily during 2008 for certain counterparties that encountered financial difficulties. There was no earnings impact associated with these write-offs.
        The increase in allowance for uncollectible accounts receivable from our regulated electric and gas businesses is primarily driven by a Maryland PSC ruling in the second quarter of 2009 and the economic downturn which continues to cause a decreased ability of customers to pay their utility bills. The Maryland PSC ruling in the second quarter of 2009 delayed BGE's ability to terminate service to customers with arrearages and required BGE to offer those customers the option to enter into extended payment plans until September 25, 2009.
        If the current economic recession continues on a prolonged basis, our and BGE's bad debt expense could materially increase in the future despite our efforts to mitigate those risks. We discuss our credit risk in more detail in the~~Risk Management~~ ~~section of our 2008 Annual Report on Form 10-K.~~income before income taxes.

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Financial Condition
Cash Flows
The following table summarizes our cash flows for ~~2009~~the quarter ended March 31, 2010 and ~~2008, excluding the impact of changes in intercompany balances.~~2009.

2009 Segment
Cash Flows
Consolidated
Cash Flows

Nine Months Ended
September 30, 2009
Nine Months Ended
September 30,

Merchant
Regulated
Holding
Company and
Other
2009
2008

(In millions)

Operating Activities

Net (loss) income
$ (39.7 ) $ 132.7 $ (17.0 ) $ 76.0 $ 102.3

Non-cash merger termination and strategic alternatives costs
37.2 — — 37.2 —

Derivative contracts classified as financing activities¹
1,007.0 — — 1,007.0 (37.1 )

Other non-cash adjustments to net (loss) income
573.6 542.3 78.5 1,194.4 810.5

Changes in working capital:

Derivative assets and liabilities, excluding collateral
118.3 — 6.7 125.0 (935.0 )

Net collateral and margin
1,502.4 2.4 — 1,504.8 (568.6 )

Other changes
366.9 (153.2 ) 42.1 255.8 (358.6 )

Defined benefit obligations²
— — — (277.7 ) (34.2 )

Other
(34.7 ) (45.3 ) 133.1 53.1 6.6

Net cash provided by (used in) operating activities
3,531.0 478.9 243.4 3,975.6 (1,014.1 )

Investing Activities

Investments in property, plant and equipment
(961.1 ) (265.5 ) (16.6 ) (1,243.2 ) (1,360.5 )

Asset and business acquisitions, net of cash acquired
— — (20.8 ) (20.8 ) (316.5 )

Contributions to nuclear decommissioning trust funds
(18.7 ) — — (18.7 ) (18.7 )

Proceeds from sale of investments and other assets
49.9 — 31.2 81.1 241.2

Contract and portfolio acquisitions
(2,153.7 ) — — (2,153.7 ) —

Repayments of loans receivable
— — — — 26.0

Decrease (increase) in restricted funds³
(1.6 ) (22.4 ) 1,003.9 979.9 8.3

Other
(0.6 ) — (15.2 ) (15.8 ) (4.1 )

Net cash used in investing activities
(3,085.8 ) (287.9 ) 982.5 (2,391.2 ) (1,424.3 )

Cash flows from operating activities less cash flows from investing activities
$ 445.2 $ 191.0 $ 1,225.9 1,584.4 (2,438.4 )

Financing Activities²

Net (repayment) issuance of debt
(2,080.3 ) 3,041.8

Debt issuance costs
(67.8 ) (50.6 )

Proceeds from issuance of common stock
24.4 17.6

Common stock dividends paid
(179.6 ) (250.7 )

BGE preference stock dividends paid
(9.9 ) (9.9 )

Proceeds from contract and portfolio acquisitions
2,263.1 —

Derivative contracts classified as financing activities¹
(1,007.0 ) 37.1

Other
13.1 (8.8 )

Net cash (used in) provided by financing activities
(1,044.0 ) 2,776.5

Net increase in cash and cash equivalents
$ 540.4 $ 338.1

2010 Segment
Cash Flows
Consolidated
Cash Flows

Quarter Ended
March 31, 2010
Quarter Ended
March 31,

Generation
NewEnergy
Regulated
Eliminations,
Holding
Company and
Other
2010
2009

(In millions)

Operating Activities

Net income (loss)
$ 27.1 $ 104.1 $ 64.4 $ (4.3 ) $ 191.3 $ (119.7 )

Non-cash merger termination and strategic alternatives costs
— — — — — 37.2

Derivative contracts classified as financing activities¹
— 39.1 — — 39.1 296.8

Other non-cash adjustments to net income (loss)
136.2 (97.5 ) 136.6 26.8 202.1 335.5

Changes in working capital

Derivative assets and liabilities, excluding collateral
(2.0 ) (74.2 ) 0.3 — (75.9 ) 67.6

Net collateral and margin
— (110.0 ) 0.9 — (109.1 ) 211.6

Accrued taxes
(1,091.5 ) 374.6 (0.2 ) 2.4 (714.7 ) 88.3

Other changes
(82.9 ) 223.2 (82.6 ) (146.5 ) (88.8 ) 304.1

Defined benefit obligations²
— — — — 5.1 (251.5 )

Other
15.2 (46.8 ) (8.7 ) 27.8 (12.5 ) 19.9

Net cash (used in) provided by operating activities
(997.9 ) 412.5 110.7 (93.8 ) (563.4 ) 989.8

Investing activities

Investments in property, plant and equipment
(77.7 ) (24.5 ) (87.2 ) (1.5 ) (190.9 ) (392.1 )

Change in cash pool³
700.7 (277.8 ) 314.7 (737.6 ) — —

Contributions to nuclear decommissioning trust funds
— — — — — (18.7 )

Proceeds from sale of investments and other assets
— 3.9 — 20.9 24.8 31.4

Contract and portfolio acquisitions
— (3.4 ) — — (3.4 ) (866.3 )

(Increase) decrease in restricted funds
— (42.7 ) (23.8 ) 0.4 (66.1 ) 979.3

Other investments
(0.2 ) 1.8 — (0.1 ) 1.5 (0.9 )

Net cash (used in) provided by investing activities
622.8 (342.7 ) 203.7 (717.9 ) (234.1 ) (267.3 )

Cash flows from operating activities plus cash flows from investing activities
$ (375.1 ) $ 69.8 $ 314.4 $ (811.7 ) (797.5 ) 722.5

Financing Activities²

Net repayment of debt
(625.6 ) (803.4 )

Proceeds from issuance of common stock
11.0 5.8

Debt issuance costs
(4.0 ) (62.7 )

Common stock dividends paid
(46.3 ) (85.7 )

BGE preference stock dividends paid
(3.3 ) (3.3 )

Proceeds from contract and portfolio acquisitions
— 863.8

Derivative contracts classified as financing activities¹
(39.1 ) (296.8 )

Other
2.6 4.3

Net cash used in financing activities
(704.7 ) (378.0 )

Net (decrease) increase in cash and cash equivalents
$ (1,502.2 ) $ 344.5

Certain prior-period amounts have been reclassified to conform with the current period's presentation.
1 All ongoing cash flows from derivative contracts deemed to contain a financing element at inception must be reclassified from operating activities to financing activities.
2 Items are not allocated to the business segments because they are managed for the company as a whole.
3 The decrease in restricted funds at our Holding Company and Other is primarily related to $1.0 billion of restricted cash related to the issuance of Series B Preferred Stock to EDF in December 2008. These funds were held at the holding company and were restricted for paymentAs part of the ~~14% Senior~~ring-fencing measures required by the Maryland PSC in its 2009 order approving the transaction with EDF, BGE ceased participation in the cash pool on January 7, 2010. We discuss this ring-fencing measure in Notes ~~held by MidAmerican. The 14% Senior Notes were repaid in full in January 2009.~~to Consolidated Financial Statements.

Table of Contents
Cash Flows from Operating Activities
~~Cash provided by operating activities was $3,975.6 million in 2009 compared to~~In the first quarter of 2010, cash used in operating activities was $0.6 billion, primarily driven by $0.8 billion in income tax payments, most of ~~$1,014.1 million~~which related to the federal taxes associated with the EDF transaction, which closed in ~~2008. This $4,989.7 million increase~~the fourth quarter of 2009.
        In the first quarter of 2009, the company generated $1.0 billion in cash ~~flows was primarily~~from operating activities, mostly due ~~to $3,747.8 million of net favorable changes~~to:
•
$0.7 billion in working capital including $0.3 billion for materials, supplies, and fuel stocks, $0.2 billion for net collateral and margin, and $0.2 billion for a ~~net increase~~federal tax refund, and
•
$0.3 billion of ~~$1,044.1 million as a result of a reclassification of ongoing cash flows from~~ derivative contracts deemed to contain a financing element at inception that must be classified as financing activities rather than operating ~~activities. We discuss~~activities related to the ~~impact on~~divestiture of our Houston-based gas trading business.
Partially offsetting these cash inflows was $0.3 billion of contributions to our defined benefit pension plans.
        The $1.6 billion decrease in operating cash flows for the first quarter of 2010 compared to the same period of 2009 is primarily due to:
•
$1.0 billion higher income taxes paid,
•
$0.2 billion of lower operating cash flows from our regulated businesses, primarily due to the residential customer rate credit in the first quarter of 2010 and higher distribution service restoration expenses associated with 2010 storms,
•
$0.3 billion lower derivative contract settlements reclassified as financing activities ~~below. This increase was partially offset by an unfavorable change of $240.9 million primarily related to our pension contributions.~~
        ~~The net favorable changes~~ in ~~working capital of $3,747.8 million included $1,060.0 million related to net derivative assets~~2010, and liabilities. Changes in derivative assets and liabilities are driven by fluctuations in commodity prices and the realization of contracts at settlement within our merchant energy business. There was also $2,073.4 million
•
$0.3 billion more in net collateral and margin ~~returned~~posted in ~~2009~~2010 as compared to ~~2008.~~
        ~~We continue to improve our collateral position in 2009. Total net cash collateral posted in~~ 2009 ~~decreased compared to the balance as of December 31, 2008~~ as follows:

(In millions)

Net collateral and margin posted, December 31, 2008
$ (1,445.6 )
Return of collateral held associated with nonderivative contracts
(14.9 )
Net return of collateral posted associated with nonderivative contracts
324.2
Return of initial and variation margin posted on exchange-traded transactions recorded in accounts receivable
709.1
Return of fair value net cash collateral posted (netted against derivative assets / liabilities)*
486.4

Change in net collateral and margin posted
1,504.8

Net collateral and margin held, September 30, 2009
$ 59.2

March 31,

2010
2009

(In millions)

Net collateral and margin held (posted), January 1,
$ 77.2 $ (1,445.6 )
(Return of) additional collateral held associated with nonderivative contracts
(10.2 ) 26.3
Net (additional) return of collateral posted associated with nonderivative contracts
(2.1 ) 128.2
(Additional) return of initial and variation margin posted on exchange-traded transactions recorded in accounts receivable
(42.9 ) 178.7
Additional fair value net cash collateral posted (netted against derivative assets / liabilities)*
(53.9 ) (121.6 )

Change in net collateral and margin (posted) held
(109.1 ) 211.6

Net collateral and margin posted, March 31,
$ (31.9 ) $ (1,234.0 )

* We discuss our netting of fair value collateral with our derivative assets / liabilities in more detail in Note 13 to Consolidated Financial Statements of our ~~2008~~2009 Annual Report on Form 10-K.
        ~~The $1,504.8 million decrease in net collateral and margin posted during 2009 primarily reflects the following:~~
•
~~fewer contracts as a result of reducing the risk in our portfolio,~~
•
collateral returned/reduced as part of the divestiture of a majority of our international commodities operation and gas trading operation as well as the execution of a gas supply agreement with the buyer of the gas trading operation for the retail gas business,
•
~~the termination of in-the-money contracts, and~~
•
~~changes in commodity prices and the level of our open positions.~~
        We discuss all forms of collateral in terms of their impact on our ~~net available liquidity~~business in the~~Available Sources of Funding~~Collateral section.
        Partially offsetting these decreases in operating cash flows was $0.3 billion of lower contributions to our defined benefit pension plans.
Cash Flows from Investing Activities
Cash used in investing activities for the first quarter of 2010 was ~~$2,391.2 million in 2009~~$0.2 billion, compared to ~~$1,424.3 million in 2008. The $966.9 million increase in cash~~$0.3 billion used in ~~2009 compared to 2008~~the first quarter of 2009. The $0.1 billion decrease from the prior year was ~~primarily~~ due ~~to $2,153.7 million for~~to:
•
$0.9 billion lower outflows associated with contract and portfolio acquisitions as ~~a component of our strategic divestitures. As~~ a result of the structure of the ~~divestitures~~divestiture of a majority of our international commodities ~~Houston-based gas trading~~operation in March 2009, and ~~other trading operations, we are required~~
•
$0.2 billion of lower investments in property, plant, and equipment, primarily related to ~~present investing cash outflows for in-the-money contracts on a gross basis separate from financing cash inflows for out-of-the-money contracts executed simultaneously. We discuss~~environmental additions at our ~~divestitures~~Brandon Shores coal-fired generating plant that went into service in ~~more detail beginning on page 16~~the fourth quarter of 2009 and the~~Notes~~ absence of nuclear capital spending in 2010 due to ~~Consolidated Financial Statements~~the deconsolidation of CENG in 2009.

Table of Contents~~. There was no such~~
        These decreases were offset by $1.0 billion of lower restricted funds activity in ~~2008.~~
        ~~This increase was partially offset by:~~
•
~~a $971.6 million decrease in~~2010. In January 2009, our restricted funds decreased by $1.0 billion, primarily due to the release of restricted funds for the repayment of ~~the~~ $1 billion of 14% Senior Notes to ~~MidAmerican in January 2009, and~~
•
a $295.7 million decrease in cash used for acquisitions. $20.8 million was used in the nine months ended September 30, 2009 for the acquisition of CLT Efficient Technologies Group, an energy services company that provides energy performance contracting and energy efficiency engineering services, and $316.5 million was used in the nine months ended September 30, 2008 for the acquisition of the Hillabee Energy Center, a partially completed 774 MW gas-fired combined cycle power generation facility in Alabama, the West Valley Power Plant, a 200MW gas-fired peaking plant, and a uranium market participant.
MidAmerican.
Cash Flows from Financing Activities
Cash used in financing activities was ~~$1,044.0 million~~$0.7 billion in ~~2009~~the first quarter of 2010, compared to cash ~~provided~~used in financing activities of ~~$2,776.5 million~~$0.4 billion in

~~Table~~ the first quarter of ~~Contents~~
~~2008.~~2009. The $0.3 billion increase in cash used ~~for~~in financing activities ~~of $3,820.5 million~~ was primarily due ~~to:~~to $0.9 billion of lower proceeds from contract and portfolio acquisitions related to the structure of the divestiture of the majority of our international commodities operation in March 2009.
        This increase was partially offset by:
•
$~~3,143.2 million net increase in cash used to repay short-term borrowings and long-term debt primarily due to the repayment of the $1~~0.3 billion ~~14% Senior Notes to MidAmerican in January 2009, $1,728.3 million in repayments of short-term credit facilities, and a $500.0 million repayment of a 6.125% fixed rate note,~~
•
~~$1,978.9 million net decrease in cash received from the issuance of long-term debt, and~~
•
~~$1,044.1 million in~~lower cash outflows ~~related to~~associated with derivative contracts deemed to contain a financing element at inception that must be classified as financing activities rather than operating ~~activities.~~activities in the first quarter of 2010 compared to the same period in 2009. These contracts primarily ~~relate~~related to transactions associated with the divestiture of our ~~international commodities operation,~~ Houston-based gas trading ~~operation and certain other trading operations.~~operation. During ~~the nine months ended September 30,~~March 2009, we executed ~~derivatives as part of these divestiture~~ transactions at prices that differed from ~~then-current~~ market prices. As a result, for cash flows associated with the out-of-the money derivative transactions ~~are deemed to contain a financing element, and~~executed, we ~~must record~~recorded the ongoing cash flows related to these contracts as financing cash ~~flows. We discuss~~flows in March 2009, and
•
$0.2 billion lower net debt repayments in the first quarter of 2010 compared to the same period in 2009. In the first quarter of 2009, we repaid $1.0 billion of 14% Senior Notes, offset by $0.2 billion in short term borrowings on our ~~divestitures in more detail beginning on page 16~~credit facilities. In the first quarter of ~~the~~2010, we retired $0.5 billion 7.00% Notes due April 1, 2012 pursuant to ~~Consolidated Financial Statements.~~a cash tender offer and repurchased outstanding tax exempt notes totaling $0.1 billion.
        This increase in cash used for financing activities was partially offset by $2,263.1 million for contract and portfolio acquisitions as a component of our strategic divestitures. As a result of the structure of the divestitures of a majority of our international commodities, Houston-based gas trading and other trading operations, we are required to present financing cash inflows for out-of-the-money contracts on a gross basis separate from investing cash outflows for in-the-money contracts executed simultaneously. We discuss our divestitures in more detail beginning on page 16 of the~~Notes to Consolidated Financial Statements.~~ ~~There was no such activity in 2008.~~

Security Ratings
We discuss our security ratings in our ~~2008~~2009 Annual Report on Form 10-K.
        ~~On July 31, 2009, Fitch Ratings downgraded Constellation Energy's senior unsecured debt rating from BBB to BBB-and~~In March 2010, Moody's Investor Service updated BGE's ~~senior unsecured debt rating from A- to BBB+. Fitch Ratings also updated both companies'~~ ratings outlook from ~~Watch Evolving~~Stable to ~~Stable.~~
        ~~On August 19, 2009, Moody's Investor Service reaffirmed Constellation Energy's senior unsecured debt rating of Baa3 and issued a Stable ratings outlook.~~
        On November 2, 2009, S&P downgraded Constellation Energy's senior unsecured debt rating to BBB- with a Stable outlook from BBB on Watch Negative. As a result of this rating action, we were not required to post any additional collateral pursuant to our counterparty agreements. In addition, BGE's senior unsecured debt rating was upgraded to BBB+ with a Stable outlook from BBB on Watch Negative.Positive.

Available Sources of Funding
In addition to cash generated from ~~business~~ operations, we rely upon access to capital for our capital expenditure programs and for the liquidity required to operate and support our commercial businesses. Our liquidity requirements are funded by credit facilities and cash. We fund our short-term working capital needs with existing cash and with our credit facilities, many of which support direct cash borrowings and the issuance of commercial paper. We also use our credit facilities to support the issuance of letters of credit, primarily for our ~~merchant energy~~NewEnergy business.
        The primary drivers of our use of liquidity have been our capital expenditure requirements and collateral requirements associated with hedging our generating assets and hedging our ~~Customer Supply~~NewEnergy business in both power and gas. ~~As part of our strategic initiatives,~~In order to reduce these collateral requirements, we have modified the structure of certain transactions, ~~and~~ terminated others, ~~in order to reduce these~~and entered into new contracts that either do not have a collateral ~~requirements.~~requirement or allow the posting of alternative forms of collateral. Significant changes in the prices of commodities, depending on hedging strategies we have employed, could require us to post additional letters of credit, and thereby reduce the overall amount available under our credit facilities or to post additional cash, and thereby reduce our available cash balance. Additional regulation of the derivatives markets, as has been proposed recently, could also require us to post additional cash collateral.
~~Constellation Energy~~
~~At September 30, 2009, we had approximately $5.8 billion in committed~~        We discuss our, and BGE's, credit facilities ~~available as shown below. We have included~~ in ~~the table below our credit facilities as of~~

~~Table of Contents~~
~~September 30, 2009 and pro forma following the completion~~detail beginning on page 16 of the ~~transaction with EDF:~~

Facility Expiration
Facility
Size as of
September 30,
2009²
Facility Size
Pro Forma
upon Completion
of the EDF
Transactions²

(In billions)

July 2012
$ 3.85 $ 2.32
November 2009¹
1.23 —
September 2013
0.35 —
December 2009
0.15 —
September 2014
0.25 0.50

Total
$ 5.83 $ 2.82

~~1 Size of facility may be reduced by proceeds received from certain securities offerings or asset sales.~~
~~2 Excludes commodity-linked credit facility discussed below due to its contingent nature.~~
        Collectively, these facilities currently support the issuance of letters of credit and/or cash borrowings up to approximately $5.8 billion as of September 30, 2009. At September 30, 2009, we had approximately $2.0 billion in letters of credit issued, and we had no commercial paper outstanding.
        During the third quarter of 2009, we executed a new committed five year bilateral credit facility that allows for a maximum capacity of $500 million. This facility can be used to issue letters of credit in support of our collateral obligations. At September 30, 2009 and November 3, 2009, we had committed capacity of $250 million and $500 million, respectively. The facility partially replaces a portion of our credit facilities that terminate upon closing of the transaction with EDF.
        During the third quarter of 2009, we also entered into a five year commodity-linked credit facility that allows for the issuance of letters of credit up to a maximum capacity of $500 million. We could increase the maximum facility size to $750 million or alternatively enter into an additional $250 million bilateral facility if certain conditions are met, including the closing of the transaction with EDF. This commodity-linked facility is designed to help manage our contingent collateral requirements associated with the hedging of our Customer Supply operations because its capacity increases as natural gas price levels decrease compared to a reference price that is adjusted periodically. As of September 30, 2009, there were no letters of credit outstanding under this facility.
        In connection with the Investment Agreement with EDF, EDF has provided us with up to $2 billion pre-tax, or approximately $1.4 billion after-tax, of additional liquidity pursuant to a put arrangement that will allow us to require EDF to purchase certain non-nuclear generation assets. The amount of after-tax proceeds will be impacted by the assets actually sold and the related tax impacts at that time.
        During April 2009, we received regulatory approvals and consents for the majority of the assets covered by the put arrangement. As of September 30, 2009, we have approximately $1.1 billion after-tax of liquidity available under the put arrangement. We expect to receive regulatory approval for an additional asset in the first quarter of 2010, which will increase the net after-tax liquidity from the put arrangement to approximately $1.4 billion. The put arrangement will expire at the earlier of December 31, 2010 or the termination of the Investment Agreement by EDF in the event of a breach of contract by us.
        Certain credit facilities of Constellation Energy contain a provision requiring Constellation Energy to maintain a ratio of debt to capitalization equal to or less than 65%. At September 30, 2009, the debt to capitalization ratios as defined in the credit agreements were no greater than 46%.
        Our $1.23 billion credit facility requires us to maintain consolidated earnings before interest, taxes, depreciation, and amortization to consolidated interest expense ratio of at least 2.75 when our Standard and Poors (S&P) senior unsecured debt rating is BBB- or lower and our Moody's senior unsecured debt rating is Baa3 or lower. Compliance with the covenant was not required as of September 30, 2009 as S&P's senior unsecured debt rating was above BBB-. Since the $1.23 billion credit facility expires upon the earlier of the closing of the EDF transaction or November 12, 2009, the recent change in rating by S&P to BBB- will not require compliance with this covenant.
        The terms of the Series B Preferred Stock allow us to issue debt without the consent of the holders of the majority of the Series B Preferred Stock only if, after issuance of such debt, we maintain a ratio of debt to capitalization equal to or less than 65%. Upon closing of our transaction with EDF, the Series B Preferred Stock will be redeemed.
        ~~Upon closing of our transaction with EDF, under our $3.85 billion credit facility, we will grant a lien on certain generating facilities and pledge our ownership interests in our nuclear business~~Notes to the ~~lenders.~~

Consolidated Financial Statements~~BGE~~.

As of September 30, 2009, BGE has a $400.0 million five-year revolving credit facility expiring in 2011. BGE can use the facility to issue letters of credit or to issue short-term debt through the issuance of commercial paper or through direct borrowing against the facility. On October 29, 2009, BGE expanded its borrowing capacity to

~~Table of Contents~~

$575 million. The size of the facility may be increased up to $600 million with additional commitments by lenders. At September 30, 2009, BGE had $334.9 million outstanding on its $400 million credit facility to secure funds in advance of maturing commercial paper and other obligations.

The credit agreement of BGE contains a provision requiring BGE to maintain a ratio of debt to capitalization equal to or less than 65%. At September 30, 2009, the debt to capitalization ratio for BGE as defined in this credit agreement was 52%.

~~Constellation Energy and BGE~~

~~Decreases in Constellation Energy's or BGE's credit ratings would not trigger an early payment on any of our, or BGE's, credit facilities.~~

However, the impact of a credit ratings downgrade on our financial ratios associated with our credit facility covenants would depend on our financial condition at the time of such a downgrade and on the source of funds used to satisfy the incremental collateral obligation resulting from a credit ratings downgrade. For example, if we were to use existing cash balances or exercise the put option with EDF to fund the cash portion of any additional collateral obligations resulting from a credit ratings downgrade, we would not expect a material impact on our financial ratios. However, if we were to issue long-term debt or use our credit facilities to fund any additional collateral obligations, our financial ratios could be materially affected. Failure by Constellation Energy, or BGE, to comply with these covenants could result in the acceleration of the maturity of the borrowings outstanding and preclude us from issuing letters of credit under these facilities.

Net Available Liquidity

~~The following tables provide a summary of our~~Constellation Energy's and BGE's net available liquidity at ~~December~~March 31, ~~2008~~2010 was $4.7 billion and ~~September 30, 2009:~~

As of December 31, 2008

Constellation
Energy
BGE
Total
Consolidated

(In billions)

Credit facilities
$ 6.2 $ 0.4 $ 6.6
Less: Letters of credit issued
(3.6 ) — (3.6 )
Less: Cash drawn on credit facilities
(0.5 ) (0.4 ) (0.9 )

Undrawn facilities
2.1 — 2.1
Less: Commercial paper outstanding
— — —

Net available facilities
2.1 — 2.1
Add: Cash
0.2 — 0.2

Net available liquidity
$ 2.3 $ — $ 2.3

As of September 30, 2009

Constellation
Energy
BGE
Total
Consolidated

(In billions)

Credit facilities¹
$ 5.8 $ 0.4 $ 6.2
Less: Letters of credit issued
(2.0 ) — (2.0 )
Less: Cash drawn on credit facilities
— — —

Undrawn facilities
3.8 0.4 4.2
Less: Commercial paper outstanding
— (0.3 ) (0.3 )

Net available facilities
3.8 0.1 3.9
Add: Cash
0.7 — 0.7
Add: EDF put arrangement
1.1 — 1.1

Net available liquidity
$ 5.6 $ 0.1 $ 5.7

~~1 Excludes commodity-linked credit facility due to its contingent nature.~~

~~Table of Contents~~

~~Net available liquidity increased from December 31, 2008 through September 30, 2009 by $3.4~~$0.9 billion, ~~as follows:~~

(In billions)

Decrease in letters of credit issued
$ 1.6
EDF put arrangement
1.1
Decrease in cash drawn on facilities
0.9
Increase in cash
0.5
Decrease in credit facilities
(0.4 )
Increase in commercial paper issued
(0.3 )

Increase in net available liquidity
$ 3.4

Through our efforts to reduce risk, we have significantly improved our liquidity. Specifically, we executed on our planned divestitures, significantly reduced the activities of our Global Commodities operation, and restructured and terminated existing transactions and amended certain agreements, all of which have led to lower collateral requirements. Through September 30, 2009, we received substantially all of the $1 billion of total net collateral expected to be returned as a result of the successful execution of our divestitures. The change in credit facilities and EDF put arrangement was due to the receipt of required regulatory approvals on the majority of assets covered by the EDF put arrangement, which resulted in the termination of the EDF interim backstop liquidity facility. Finally, cash flows from operating activities funded the repayment of all outstanding cash draws on our credit facilities, and BGE was able to issue $334.9 million of commercial paper, demonstrating an ability to access the capital market in a more traditional manner.

Upon the close of the EDF transaction, the amount and composition of our liquidity will change due to the reduction in credit facilities discussed on page 67, as well as the receipt of net cash proceeds from the transaction.

~~The net proceeds from this transaction are expected to be approximately $2.2 billion after repayment of the EDF preferred stock and the payment of taxes.~~respectively. We anticipate using these proceeds to reduce up to $850 million of our long-term debt, as well as for other general corporate purposes, including payments related to BGE under the Maryland PSC order dated October 30, 2009. These net proceeds will partially offset the reduction in credit facilities, although ourdiscuss net available liquidity ~~will be reduced.~~

Our liquidity needs vary as commodity prices change. We regularly evaluate the effects of changing price levels on our liquidity needs by estimating the impacts of volatile power, gas, and coal prices on our price sensitive sources and uses of liquidity. For example, energy contracts settling in the current year may impact our cash flows and changing price levels may impact our collateral requirements. Additionally, we consider the impact of other sources and uses of liquidity, including planned business divestitures, anticipated new business, capital expenditures, operating expenses and credit charges.

We believe that the actions that we have taken and our current net available liquidity will be sufficient to support the ongoing liquidity requirements over the next 12 months. Our liquidity projections include assumptions for commodity price changes, which are subject to significant volatility, and we are exposed to certain operational risks that could have a significant impact on our liquidity. We discuss significant items that could negatively impact our liquiditymore detail in the~~Risk Factors~~Notes to Consolidated Financial Statements ~~section of our 2008 Annual Report~~ on ~~Form 10-K.~~page 17.

Collateral

Constellation Energy's collateral requirements generally arise from the needs of its ~~merchant energy business' need to participate~~NewEnergy business as a result of its participation in certain organized markets, such as Independent System Operators (ISOs) or financial exchanges, as well as from ~~our~~its margining on over-the-counter (OTC) contracts.

To support wholesale and retail power ~~Customer Supply~~NewEnergy obligations ~~as well as some~~and our limited trading activities, Constellation Energy posts collateral to ISOs. Forward hedging of our Generation and ~~Customer Supply obligations, as well as our Global Commodities trading activities,~~NewEnergy businesses creates the need to transact with exchanges such as New York Mercantile Exchange and Intercontinental Exchange. We post initial margin based on exchange rules, as well as variation margin related to the change in value of the net open position with the exchange. Constellation Energy's initial margin requirements increased during the third quarter of 2008 as a result of changes in exchange rules and decreased during the fourth quarter of 2008 as a result of portfolio risk reduction and downsizing activities.

During the nine months ended September 30, 2009, our initial margin requirements continued to decrease. In March 2009 and April 2009, we closed out our exchange positions related to our international commodities operation and Houston-based gas trading operation, respectively, which reduced our margin posted with each exchange with which we transact. Daily variation margin postings to each exchange depend on price moves in the underlying power, gas and coal exchange traded forward and option contracts.

In addition to the collateral posted to ISOs and exchanges, we post collateral with certain OTC

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counterparties. These collateral amounts may be fixed or may vary with price levels.

There are certain inherent asymmetries relating to the use of collateral that create liquidity requirements for our ~~merchant energy~~Generation and NewEnergy businesses. These asymmetries arise ~~as a result of~~from our actions to be economically hedged, as well as market conditions or conventions for conducting business

~~Table of Contents~~

that result in some transactions being collateralized while others are not, including:

•: In our ~~Customer Supply operation,~~NewEnergy business, we generally do not receive collateral under contractual obligations to supply power or gas to our customers but ~~our Global Commodities operation hedges~~we hedge these transactions through purchases of power and gas that generally require us to post collateral. By entering into a gas supply agreement with the buyer of our gas trading operation, we have reduced our collateral requirements to support our retail gas operation. We ~~discuss this gas supply agreement~~also intend to further align our load obligations by buying generation assets in ~~more detail~~regions where we do not have a significant generation presence and entering into longer-tenor agreements with merchant generators, further reducing our dependence on ~~page 13 of the~~~~Notes to Consolidated Financial Statements~~.exchange-traded products, thereby lowering our collateral requirements.
•: In our Generation operation, we may have to post collateral on our power sale or fuel purchase ~~contracts, but~~contracts.

Finally, collateral types may asymmetrically impact our ~~generating plants~~liquidity. For example, in margining with OTC counterparties, we may post letter of credit (LC) collateral for an out-of-the money counterparty. However, we may receive LC collateral when we are in-the-money with a counterparty. Posting LCs reduces our liquidity while the receipt of LC collateral does not ~~a source of collateral.~~increase our liquidity.

Customers of our ~~merchant energy~~NewEnergy business rely on the creditworthiness of Constellation Energy. In this regard, we have certain agreements that contain provisions that would require us to post additional collateral upon a credit rating downgrade in the senior unsecured debt of Constellation Energy. Based on contractual provisions at ~~September 30, 2009,~~March 31, 2010, we estimate that if Constellation Energy's senior unsecured debt were downgraded to one level below the investment grade threshold we would have the following additional collateral obligations:



Credit Ratings Downgraded to*	Level Below Current Rating		Additional Obligations**
Credit Ratings Downgraded to¹					Level Below Current Rating		Additional Obligations²
	(In billions)				(In billions)
Below investment grade		1	$	1.2		1	$	1.1

*1 If there are split ratings among the independent credit-rating agencies, the lowest credit rating is used to determine our incremental collateral obligations.

**2 Includes $0.2 billion related to derivative contracts as discussed in Notes to Consolidated Financial Statements beginning on page ~~36.~~31.

Based on market conditions and contractual obligations at the time of a downgrade, we could be required to post additional collateral in an amount that could exceed the obligation amounts specified above, which could be material. We discuss our credit facilities in the~~Available Sources of Funding~~Notes to Consolidated Financial Statements ~~section.~~beginning on page 16.

Capital Resources

Our estimated annual cash requirement amounts for the years ~~2009~~2010 and ~~2010~~2011 are shown in the table below.

We will continue to have cash requirements for:

•: working capital needs,
•: payments of interest, distributions, and dividends,
•: capital expenditures, and
•: the retirement of ~~debt and redemption of preference stock.~~debt.

Capital requirements for ~~2009~~2010, 2011, and ~~2010~~2012 include estimates of spending for existing and anticipated projects. We continuously review and modify those estimates. Actual requirements may vary from the estimates included in the table below because of a number of factors including:

•: regulation, legislation, and competition,
•: BGE load requirements,
•: environmental protection standards,
•: the type and number of projects selected for construction or acquisition,
•: the effect of market conditions on those projects,
•: the cost and availability of capital,
•: potential capital contributions to CENG and UNE,
•: the availability of cash from operations, and
•: business decisions to invest in capital projects.

Our estimates are also subject to additional factors. Please see theForward Looking Statements section on page 7863 andRisk Factors section in our ~~2008~~2009 Annual Report on Form 10-K. We discuss the potential impact of environmental legislation and regulation in more detail inBusiness Environment section beginning on page 4438 and

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Item 1. Business—Environmental Matters section of our ~~2008~~2009 Annual Report on Form 10-K.

Calendar Year Estimates	Calendar Year Estimates		2009		2010		Calendar Year Estimates	2010		2011


			(In billions)					(In billions)
Nonregulated Capital Requirements:
Generation and Other Capital Requirements:							Generation and Other Capital Requirements:
	Merchant energy						Major Environmental	$	0.1	$	0.1
		Generation plants¹	$	0.4	$	0.1	Maintenance		0.1		0.1
		Environmental controls		0.3		0.1	Growth		0.1		—
		Portfolio acquisitions/investments		0.1		0.1
		Technology/other		0.1		0.1	Total Generation and Other Capital Requirements		0.3		0.2
		Nuclear fuel¹		0.2		—

NewEnergy Capital Requirements:							NewEnergy Capital Requirements:
	Total merchant energy capital requirements			1.1		0.4	Maintenance		0.1		—
	Other nonregulated capital requirements			0.1		—	Growth		0.1		0.1

	Total nonregulated capital requirements			1.2		0.4	Total NewEnergy Capital Requirements		0.2		0.1

Regulated Capital Requirements:	Regulated Capital Requirements:						Regulated Capital Requirements:
	Regulated electric			0.4		0.6	Electric / Gas Distribution		0.4		0.4
	Regulated gas			0.1		0.1	Electric Transmission		0.1		0.1
							Smart Energy Savers^SM Initiatives		0.1		0.2
	Total regulated capital requirements			0.5		0.7
							Total Regulated Capital Requirements		0.6		0.7

Total Capital Requirements	Total Capital Requirements		$	1.7	$	1.1	Total Capital Requirements	$	1.1	$	1.0

~~1 Reflects the closing~~Eligible capital projects are shown net of anticipated investment tax credits or grants.

As of the ~~Investment Agreement with EDF in the fourth quarter~~date of ~~2009 and the deconsolidation of~~this report, we estimate our ~~nuclear generation and operation business. As a result, we are reflecting ten months of nuclear plant related and nuclear fuel~~2012 capital requirements ~~for 2009 and none for 2010.~~will be approximately $1.0 billion.

~~Table of Contents~~

Capital Requirements

~~Merchant Energy Business~~Nonregulated Businesses

Our ~~merchant energy business'~~nonregulated businesses' capital requirements consist of its continuing requirements, including expenditures for:

•: ~~improvements~~maintenance and growth to generating plants,
•: ~~nuclear fuel costs,~~
•: costs of complying with the ~~EPA,~~Environmental Protection Agency (EPA), Maryland, and Pennsylvania environmental regulations and legislation, and
•: enhancements to our information technology infrastructure.

~~Cost for Decommissioning Nuclear Facilities~~

Every two years, the U. S. Nuclear Regulatory Commission (NRC) requires us to demonstrate reasonable assurance that funds will be available to decommission our nuclear generating facilities after these facilities cease operation. In response to our March 2009 biennial report, the NRC notified us that they had identified a potential "shortfall" in the decommissioning fund balance for certain of our nuclear reactors. This condition was a result of declining market performance during the last two quarters of 2008 for the investments held by our decommissioning trusts.

In July 2009, we submitted to the NRC a plan that we expect will enable us to demonstrate by December 2009 reasonable assurance for adequate decommissioning funding in accordance with NRC regulations. Our plan proposes the use of a safe storage approach which allows funds to grow during the extended safe storage period following license termination but prior to decommissioning. In the event the NRC requires additional funding assurance beyond consideration of the safe storage approach, we will provide parental guarantees which would be subject to review and updating as necessary, but which are expected to be less than $70 million in the aggregate as of December 2009. We discuss the costs for decommissioning our nuclear generating facilities in more detail in the~~Business Overview~~ ~~section of our 2008 Annual Report on Form 10-K.~~

Regulated Electric and Gas

Regulated electric and gas construction expenditures primarily include new business construction needs and improvements to existing facilities, including projects to improve reliability and support demand response and conservation initiatives.

In July 2009, BGE filed with the Maryland PSC a proposal for a comprehensive smart grid initiative. The proposal includes the planned installation of 2 million residential and commercial electric and gas smart meters. We expect the total cost of the program to be approximately $480 million. In October 2009, the United States Department of Energy (DOE) selected BGE as a recipient of $200 million in federal funding for our smart grid initiative. This grant allows BGE to be reimbursed for smart grid expenditures up to $200 million, substantially reducing the total cost of this initiative. ~~However,~~In April 2010, BGE and the ~~United States Department~~DOE executed an agreement governing the terms and conditions of ~~Energy may withhold funding until approval~~the grant. The Maryland PSC held hearings on this proposed program in late 2009 and expects to issue an order in the second quarter of 2010. If BGE's proposal is ~~obtained from the Maryland PSC. If~~ approved by the Maryland PSC, BGE plans to proceed with this ~~proposal~~program as soon as practical.

Funding for Capital Requirements

We discuss our funding for capital requirements in our ~~2008~~2009 Annual Report on Form 10-K.

Contractual Payment Obligations and Committed Amounts

We enter into various agreements that result in contractual payment obligations in connection with our business activities. These obligations primarily relate to our financing arrangements (such as long-term debt, preference stock, and operating leases), purchases of capacity and energy to support ~~the growth in~~ our ~~merchant energy~~nonregulated business activities, and purchases of fuel and transportation to satisfy the fuel requirements of our power generating facilities.

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We detail our contractual payment obligations at ~~September 30, 2009~~March 31, 2010 in the following table:

			Payments																	Payments

			2009			2010- 2011			2012- 2013			There- after			Total					2010			2011- 2012			2013- 2014			There- after			Total

			(In millions)																	(In millions)
Contractual Payment Obligations	Contractual Payment Obligations																	Contractual Payment Obligations
Long-term debt:¹	Long-term debt:¹																	Long-term debt:¹
	Nonregulated																	Nonregulated
		Principal	$	1,000.7		$	3.7		$	734.9		$	2,630.7		$	4,370.0			Principal	$	0.2		$	260.8		$	20.0		$	1,799.6		$	2,080.6
		Interest		84.2			376.0			260.7			3,002.1			3,723.0			Interest		111.7			241.2			235.7			2,772.5			3,361.1

	Total			1,084.9			379.7			995.6			5,632.8			8,093.0		Total			111.9			502.0			255.7			4,572.1			5,441.7
	BGE																	BGE
		Principal		38.4			138.2			639.1			1,422.8			2,238.5			Principal		56.5			254.2			537.0			1,352.4			2,200.1
		Interest		50.6			258.1			231.3			1,336.6			1,876.6			Interest		114.4			247.2			194.9			1,253.4			1,809.9

	Total			89.0			396.3			870.4			2,759.4			4,115.1		Total			170.9			501.4			731.9			2,605.8			4,010.0
BGE preference stock	BGE preference stock			—			—			—			190.0			190.0		BGE preference stock			—			—			—			190.0			190.0
Operating leases²	Operating leases²																	Operating leases²
	Operating leases, gross			42.0			419.9			385.0			571.0			1,417.9		Operating leases, gross			166.0			393.0			332.5			338.6			1,230.1
	Sublease rentals			(13.1	)		(119.0	)		(77.5	)		(139.1	)		(348.7	)	Sublease rentals			(43.1	)		(102.3	)		(56.3	)		(114.8	)		(316.5	)

	Operating leases, net			28.9			300.9			307.5			431.9			1,069.2		Operating leases, net			122.9			290.7			276.2			223.8			913.6
Purchase obligations:³	Purchase obligations:³																	Purchase obligations:³
	Purchased capacity and energy⁴			140.7			352.4			188.6			229.9			911.6		Purchased capacity and energy⁴			201.4			517.1			129.6			328.7			1,176.8
	Fuel and transportation			222.5			1,122.0			564.0			2,176.3			4,084.8		Purchased energy from CENG			402.1			1,329.6			1,941.4			—			3,673.1
	Other			120.8			166.7			50.8			37.2			375.5		Fuel and transportation			440.8			390.2			95.1			218.7			1,144.8
																		Other			92.5			56.1			8.6			6.7			163.9
Other noncurrent liabilities:	Other noncurrent liabilities:																	Other noncurrent liabilities:
	Uncertain tax positions liability			—			240.0			(23.6	)		11.9			228.3		Uncertain tax positions liability			—			191.8			4.6			14.5			210.9
	Pension benefits⁵			6.1			291.6			283.9			43.7			625.3		Pension benefits⁵			37.1			217.5			203.7			(47.1	)		411.2
	Postretirement and postemployment benefits⁶			13.1			83.0			95.9			289.9			481.9		Postretirement and postemployment benefits⁶			23.1			72.9			82.8			193.6			372.4

Total contractual payment obligations	Total contractual payment obligations		$	1,706.0		$	3,332.6		$	3,333.1		$	11,803.0		$	20,174.7		Total contractual payment obligations		$	1,602.7		$	4,069.3		$	3,729.6		$	8,306.8		$	17,708.4

1 Amounts in long-term debt reflect the original maturity ~~date and include $697.7 million of principal for the Zero Coupon Senior Notes, assuming the notes are not redeemed prior to June 19, 2023 and the original issue discount accrues until redemption.~~date. Investors may require us to repay ~~$483.8~~$95.0 million early through remarketing ~~and put~~ features. Interest on variable rate debt is included based on the forward curve for interest rates.

2 Our operating lease commitments include future payment obligations under certain power purchase agreements as discussed further in Note 11 of our ~~2008~~2009 Annual Report on Form 10-K.

3 Contracts to purchase goods or services that specify all significant terms. Amounts related to certain purchase obligations are based on future purchase expectations, which may differ from actual purchases.

4 Our contractual obligations for purchased capacity and energy are shown on a gross basis for certain transactions, including both the fixed payment portions of tolling contracts and estimated variable payments under unit-contingent power purchase agreements.

5 Amounts related to pension benefits reflect our current 5-year forecast of contributions for our qualified pension plans and participant payments for our nonqualified pension plans. Refer to Note 7 of our ~~2008~~2009 Annual Report on Form 10-K for more detail on our pension plans.

6 Amounts related to postretirement and postemployment benefits are for unfunded plans and reflect present value amounts consistent with the determination of the related liabilities recorded in our Consolidated Balance Sheets.

Off-Balance Sheet Arrangements

We discuss our off-balance sheet arrangements in our ~~2008~~2009 Annual Report on Form 10-K.

At ~~September 30, 2009,~~March 31, 2010, Constellation Energy had a total face amount of ~~$11.9~~$9.9 billion in guarantees outstanding, of which ~~$10.5~~$8.8 billion related to our ~~merchant energy business.~~Generation and NewEnergy businesses. These amounts do not represent incremental consolidated Constellation Energy obligations; rather, they primarily represent parental guarantees of certain subsidiary obligations to third parties in order to allow our subsidiaries the flexibility needed to conduct business with counterparties without having to post other forms of collateral. Our estimated net exposure for obligations under commercial transactions covered by these guarantees was ~~approximately~~ $2 billion at ~~September 30, 2009,~~March 31, 2010, which represents the total amount the parent company could be required to fund based on ~~September 30, 2009~~March 31, 2010 market prices. For those guarantees related to our derivative liabilities, the fair value of the obligation is recorded in our Consolidated Balance Sheets. We believe it is unlikely that we would be required to perform or incur any losses associated with guarantees of our subsidiaries' obligations.

We discuss our other guarantees in theNotes to Consolidated Financial Statements on page ~~25.~~19.

Risk Management

Market Risk

Economic Value at Risk (EVaR)

EVaR ~~is a measure that attempts to estimate~~measures the ~~sensitivity~~potential pre-tax loss in the fair value of ~~our total portfolio economic value~~the Generation and NewEnergy businesses due to changes in market prices. The EVaR measure includes all positions of our merchant energy business, including Generation, Customer Supply, and Global Commodities operations. Each business day, the Company undertakes EVaR calculations that include both its trading and its non-trading risks. EVaR for non-trading positions measures the amount of potential change in the fair values of the exposures related to accrual exposures.risk factors. EVaR is a one-day value-at-risk measure calculated at a 95% confidence level onassuming a standard normal distribution of prices over the ~~portfolio through 2013. At September 30, 2009,~~most recent rolling 3-month period. EVaR includes all positions over a forward rolling 60-month time horizon that expose us to market price risk, regardless of accounting treatment and business line.

Positions included in EVaR are comprised of all positions, regardless of accounting treatment, that create market risk including:

•

derivative and nonderivative commodity contracts associated with our ~~EVaR was approximately $67 million, which represents a 50% decline from its level of $136 million at December 31, 2008.~~

~~Due to the inherent limitations of statistical measures~~Generation and NewEnergy businesses,

•

physical assets, such as ~~EVaR~~our owned and contractually-controlled generating plants, and

•

our share of investments in generating plants.

We include the ~~seasonality of changes in market prices, the EVaR calculation may not reflect the full extent~~positions related to physical assets to provide a more complete presentation of our commodity market risk exposures. EVaR includes illiquid products and positions for which there is limited price ~~risk exposure. Additionally, because our EVaR methodology uses a linear approximation method, actual changes in~~discovery. Modeling the ~~value of options~~positions in our ~~portfolio resulting from significant price changes may differ from estimates generated using this methodology. As~~Generation and NewEnergy businesses involves a ~~result, actual changes in the fair value~~number of ~~derivative assets~~assumptions, and ~~liabilities subject to mark-to-market accounting could differ from the calculated EVaR, and such changes could have a material impact on our financial results.~~includes

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~~While~~projections of generation, emission rates and costs, customer load growth, load response to weather, and customer response to competitive supply. Changes in our forecast or management estimates will affect the fair value of these positions in a manner not captured by EVaR.

EVaR reflects the risk of loss due to market prices under normal market conditions. An inherent limitation of our value-at-risk measures is the reliance on historical prices. A sudden shift in market conditions can cause the future behavior of market prices to differ materially from the past. We use stress ~~testing captures Constellation Energy's~~tests and scenario analysis to better understand extreme events as a complement to EVaR. This includes exposure to unlikely but plausible events in abnormal ~~markets. We regularly conduct economic value stress tests for our market activities using multiple scenarios that assume stressed~~markets, sensitivity to changes in ~~both~~management projections of customer demand or forecasted generation output, and price ~~level~~sensitivity to illiquid points and regional basis spreads. ~~Additional scenarios focus~~

EVaR is monitored daily and is subject to regional and overall guidelines for the NewEnergy business. We place guidelines on the ~~risks predominant in individual portions of~~risk associated with illiquid delivery locations and regional basis within our ~~business segments~~NewEnergy business. Additionally, we monitor generation plant hedge ratios relative to guidelines specified by management. Stress tests and ~~include scenarios that focus on loss of generation, customer demand growth or demand destruction, or a shift in~~scenario analysis are conducted regularly and the ~~composition of load serving customers.~~

Along with EVaR, stress testing is important in measuring and controlling risk. Stress testing enhances the understanding of Constellation Energy's risk profile and loss potential, and stress losses are monitored against limits. We also use stress testing in approvals of non-standard transactions and for cross-business risk measurement, as well as an input to economic capital allocation. Stress test results, trends, and explanations are ~~provided each month to Constellation Energy's~~reviewed by senior management and torisk committees.

The EVaR amounts below represent the ~~lines~~potential pre-tax change in the fair values of ~~business to help them better measure~~our Generation and ~~manage risks and to understand event risk-sensitive positions.~~NewEnergy businesses positions over a one-day holding period.

EVaR		Quarter Ended March 31, 2010


95% Confidence Level, One-Day Holding Period
	Quarter end	$	45.7
	Average		60.3
	High		71.6
	Low		44.8

Value at Risk (VaR)

~~Where EVaR is a measure that attempts to estimate~~VaR measures the ~~sensitivity~~potential pre-tax loss in the fair value of ~~our total portfolio economic value, VaR estimates~~ the ~~sensitivity of our~~ mark-to-market energy contracts ~~of our Global Commodities operation~~due to ~~potential~~ changes in market ~~prices.~~risk factors. VaR is calculated assuming a ~~statistical model designed to predict risk~~standard normal distribution of loss based on historical market price volatility. We calculate VaR using a historical variance/covariance technique that models option positions using a linear approximation of their value. Additionally, we estimate variances and correlation using historical commodity price changesprices over the most recent rolling ~~three-month~~3-month period. ~~Our~~ VaR ~~calculation~~ includes all ~~of our Global Commodities operation derivative assets and liabilities~~positions subject to mark-to-market accounting, including contracts ~~for energy commodities~~that hedge the economics of NewEnergy nonderivative power and ~~derivatives that result in physical settlement~~fuel contracts, which do not receive hedge accounting treatment, and contracts ~~that require cash settlement.~~designated for trading. Thus, the positions for which we monitor VaR ~~is a statistical risk measurement model~~are included within, and are not incremental, to the positions subject to ~~limitations similar to those of~~ EVaR.

VaR and EVaR have similar limitations. VaR may include some products and positions for which there is limited price discovery or market depth. The modeling of option positions included in VaR ~~calculation does not include~~involves a number of assumptions and approximations. An inherent limitation of our VaR measures is the reliance on historical prices. A sudden shift in market ~~risks associated with activities~~conditions can cause the future behavior of market prices to differ materially from that ~~are subject to accrual accounting, primarily our generating facilities and our customer supply load-serving activities.~~of the past.

The VaR amounts below represent the potential pre-tax loss in the fair value of our ~~Global Commodities operation derivative assets~~Generation and ~~liabilities~~NewEnergy businesses positions subject to mark-to-market accounting, including both trading and non-trading activities, over one and ten-day holding periods.



Total Wholesale VaR		Quarter Ended September 30, 2009
Total Mark-to-Market VaR				Total Mark-to-Market VaR		Quarter Ended March 31, 2010
		(In millions)				(In millions)
99% Confidence Level, One-Day Holding Period	99% Confidence Level, One-Day Holding Period			99% Confidence Level, One-Day Holding Period
	Average	$	11.9		Quarter end	$	9.7
	High		21.7		Average		7.5
					High		12.4
					Low		5.1
95% Confidence Level, One-Day Holding Period	95% Confidence Level, One-Day Holding Period			95% Confidence Level, One-Day Holding Period
					Quarter end		7.4
					Average		5.7
	Average		9.1		High		9.5
	High		16.5		Low		3.9
95% Confidence Level, Ten-Day Holding Period	95% Confidence Level, Ten-Day Holding Period			95% Confidence Level, Ten-Day Holding Period
	Average		28.7		Quarter end		23.4
	High		52.2		Average		18.0
					High		30.0
					Low		12.4

Constellation Energy's proprietary trading activities are greatly reduced from previous years and are largely focused on price discovery. These activities continue to be managed with daily VaR limits, stop loss limits and liquidity guidelines and are immaterial relative to the overall portfolio VaR.

Wholesale Credit Risk

We measure wholesale credit risk as the replacement cost for open energy commodity and derivative transactions (both mark-to-market and accrual) adjusted for amounts owed to or due from counterparties for settled transactions. The replacement cost of open positions represents unrealized gains, net of any unrealized losses, where we have a legally enforceable right of setoff. We monitor and manage ~~the~~our credit risk ~~of our Global Commodities operation~~ through credit policies and procedures, which include an established credit approval process, daily monitoring of counterparty credit limits, the use of credit mitigation measures such as margin, collateral, or prepayment arrangements, and the use of master netting agreements.

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As of ~~September 30, 2009~~March 31, 2010 and December 31, ~~2008,~~2009, counterparties in ~~the~~our credit portfolio ~~of our Global Commodities operation~~ had the following public credit ratings:

September 30,
2009
December 31,
2008

Rating

Investment Grade¹
61 % 52 %

Non-Investment Grade
4 15

Not Rated
35 33




Rating
	Investment Grade¹	50	%	43	%
	Non-Investment Grade	2		2
	Not Rated	48		55

1 Includes counterparties with an investment grade rating by at least one of the major credit rating agencies. If split rating exists, the lower rating is used.

Our exposure to "Not Rated" counterparties was ~~$0.9~~$1.4 billion at ~~September 30, 2009~~March 31, 2010 compared to $1.5 billion at December 31, ~~2008.~~2009. This decrease was mostly ~~due to~~driven by a reduction in our CENG credit concentration exposure, which is not externally rated and a decrease in our portfolio's credit exposure to unrated natural gas customers, international coal customers, and freight ~~companies~~customers that do not have public credit ratings as a result of the divestiture of ~~a majority of our international commodities operation.~~these operations in 2009.

Many of our not rated counterparties are considered investment grade equivalent (including CENG) based on our internal credit ratings. We utilize internal credit ratings to evaluate the creditworthiness of our wholesale customers, including those companies that do not have public credit ratings. Based on internal credit ratings, approximately ~~$535 million~~$1.1 billion or ~~61%~~81% of the exposure to not rated counterparties was rated investment grade equivalent at ~~September 30, 2009~~March 31, 2010 and approximately ~~$883.7 million~~$1.2 billion or ~~60%~~81% was rated investment grade equivalent at December 31, ~~2008.~~

2009. The following table provides the breakdown of the credit quality of our wholesale credit portfolio based on our internal credit ratings:




Investment Grade Equivalent	82	%	74	%	89	%	88	%
Non-Investment Grade	18		26		11		12

Our total exposure, net of collateral, to counterparties across our entire wholesale portfolio is ~~$2.5~~$2.8 billion as of ~~September 30, 2009.~~March 31, 2010. The top ten counterparties account for ~~39%~~approximately 51% of our total ~~exposure. As shown in the table below, no single counterparty concentration comprises more than 10%~~exposure with approximately 4% of ~~the total~~that exposure ~~of the portfolio.~~being non-investment grade.

If a counterparty were to default on its contractual obligations and we were to liquidate transactions with that entity, our potential credit loss would include all forward and settlement exposure plus any additional costs related to termination and replacement of the positions. This would include contracts accounted for using the mark-to-market, hedge, and accrual accounting methods, the amount owed or due from settled transactions, less any collateral held from the counterparty. In addition, if a counterparty were to default under an accrual contract that is currently favorable to us, we may recognize a material adverse impact on our results in the future delivery period to the extent that we are required to replace the contract that is in default with another contract at current market prices. To reduce our credit risk with counterparties, we attempt to enter into agreements that allow us to obtain collateral on a contingent basis, seek third-party guarantees of the counterparty's obligation, and enter into netting agreements that allow us to offset receivables and payables with forward exposure across many transactions.

~~Our~~We consider a significant concentration of credit risk to be any single obligor or counterparty whose concentration exceeds 10% of total credit exposure. As of March 31, 2010, two counterparties, CENG and a large power cooperative, comprise exposure concentrations of 14% and 11%, respectively. No counterparties based in a single country other than the United States in aggregate comprise more than 10% of the total exposure of $2.5 billion, net of collateral, includes accrual positions and derivatives. The portion of our wholesale credit risk related to transactions that are recorded in our Consolidated Balance Sheets, net of collateral, totals approximately $0.9 billion and primarily relates to open energy commodity positions from our Global Commodities operation that are accounted for using mark-to-market accounting, derivatives that qualify for designation as hedges, as well as amounts owed by wholesale counterparties for transactions that settled but have not yet been paid.

~~Table of Contents~~

~~The following table highlights~~ the ~~credit quality and exposures related to these activities at September 30, 2009:~~portfolio.

Rating
Total Exposure
Before Credit
Collateral
Credit
Collateral
Net
Exposure
Number of
Counterparties Greater
than 10% of Net
Exposure
Net Exposure of
Counterparties Greater
than 10% of Net
Exposure

(In millions)

Investment grade
$ 1,082 $ 304 $ 778 — $ —
Split rating
3 — 3 — —
Non-investment grade
95 43 52 — —
Internally rated—investment grade
77 — 77 — —
Internally rated—non-investment grade
10 — 10 — —

Total
$ 1,267 $ 347 $ 920 — $ —

Due to volatility in the prices of energy commodities and derivatives, the market value of contractual positions with individual counterparties could exceed established credit limits or collateral provided by those counterparties. If such a counterparty were then to fail to perform its obligations under its contract (for example, fail to deliver the power ~~our Global Commodities operation~~we had contracted for), we could incur a loss that could have a material impact on our financial results.

If a counterparty were to default and we were to liquidate all contracts with that entity, our credit loss would include the loss in value of derivative contracts recorded at fair value, the amount owed for settled transactions, and additional payments, if any, that we would have to make to settle unrealized losses on accrual contracts. In addition, if a counterparty were to default under an accrual contract that is currently favorable to us, we may recognize a material adverse impact in our results in the future delivery period to the extent that we are required to replace the contract that is in default with another contract at current market prices. These potential losses would be limited to the extent that the in-the-money amount exceeded any credit mitigants such as cash, letters of credit, or parental guarantees supporting the counterparty obligation.

We also enter into various wholesale transactions through ~~Independent System Operators (ISOs).~~ISOs. These ISOs are exposed to counterparty credit risks. Any losses relating to counterparty defaults impacting the ISOs are allocated to and borne by all other market participants in the ISO. These ISOs have

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established credit policies and practices to mitigate the exposure of counterparty credit risks. As a market participant, we continuously assess our exposure to the credit risks of each ISO.

BGE is exposed to wholesale credit risk of its suppliers for electricity and gas to serve its retail customers. BGE may receive performance assurance collateral to mitigate electricity suppliers' credit risks in certain circumstances. Performance assurance collateral is designed to protect BGE's potential exposure over the term of the supply contracts and will fluctuate to reflect changes in market prices. In addition to the collateral provisions, there are supplier "step-up" provisions, where other suppliers can step in if the early termination of a full-requirements service agreement with a supplier should occur, as well as specific mechanisms for BGE to otherwise replace defaulted supplier contracts. All costs incurred by BGE to replace the supply contract are to be recovered from the defaulting supplier or from customers through rates.

Interest Rate Risk, Retail Credit Risk, Foreign Currency Risk, Security Price Risk, and Operational Risk

We discuss our exposure to interest rate risk, retail credit risk, foreign currency risk, security price risk and operational risk in theRisk Management section of our ~~2008~~2009 Annual Report on Form 10-K.

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Item 3. Quantitative and Qualitative Disclosures About Market Risk

We discuss the following information related to our market risk:

•: hedging activities in theNotes to Consolidated Financial Statements beginning on page ~~29,~~23,
•: activities of our ~~Global Commodities operation~~Generation and NewEnergy businesses in ~~the~~~~Merchant Energy Business~~their respective section ofManagement's Discussion and Analysis beginning on page ~~52,~~41,
•: evaluation of commodity and credit risk in theRisk Management section ofManagement's Discussion and Analysis beginning on page ~~72,~~57, and
•: changes to our business environment in theBusiness Environment section ofManagement's Discussion and Analysis beginning on page ~~44.~~38.

Items 4 and 4(T). Controls and Procedures

A control system, no matter how well conceived and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. Because of the inherent limitations in all control systems, no evaluation of controls can provide absolute assurance that all control issues and instances of fraud, if any, within Constellation Energy or BGE have been detected. These inherent limitations include errors by personnel in executing controls due to faulty judgment or simple mistakes, which could occur in situations such as when personnel performing controls are new to a job function or when inadequate resources are applied to a process. Additionally, controls can be circumvented by the individual acts of some persons or by collusion of two or more people.

The design of any system of controls also is based in part upon certain assumptions about the likelihood of future events, and there can be no absolute assurance that any design will succeed in achieving its stated goals under all potential future conditions; over time, controls may become inadequate because of changes in conditions or personnel, or the degree of compliance with the policies or procedures may deteriorate. Because of the inherent limitations in a cost-effective control system, misstatements due to error or fraud may occur and not be detected.

Evaluation of Disclosure Controls and Procedures

The principal executive officer and principal financial officer of Constellation Energy have each evaluated the effectiveness of the disclosure controls and procedures (as such term is defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934, as amended (the "Exchange Act")) as of the end of the fiscal quarter covered by this quarterly report (the "Evaluation Date"). Based on such evaluation, such officers have concluded that, as of the Evaluation Date, Constellation Energy's disclosure controls and procedures are effective in providing reasonable assurance that information required to be disclosed in the reports that Constellation Energy files and submits under the Exchange Act is recorded, processed, summarized, and reported when required and is accumulated and communicated to management, as appropriate, to allow timely decisions regarding required disclosure.

The principal executive officer and principal financial officer of BGE have each evaluated the effectiveness of the disclosure controls and procedures as of the Evaluation Date. Based on such evaluation, such officers have concluded that, as of the Evaluation Date, BGE's disclosure controls and procedures are effective in providing reasonable assurance that information required to be disclosed in the reports that BGE files and submits under the Exchange Act is recorded, processed, summarized, and reported when required and is accumulated and communicated to management, as appropriate, to allow timely decisions regarding required disclosure.

Changes in Internal Control over Financial Reporting

During the quarter ended ~~September 30, 2009,~~March 31, 2010, there has been no change in either Constellation Energy's or BGE's internal control over financial reporting (as such term is defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act) that has materially affected, or is reasonably likely to materially affect, either Constellation Energy's or BGE's internal control over financial reporting.

Table of Contents

PART II. OTHER INFORMATION

Item 1. Legal Proceedings

We discuss our Legal Proceedings in theNotes to Consolidated Financial Statements beginning on page ~~26.~~20.

Item 2. Issuer Purchases of Equity Securities

The following table discloses purchases of shares of our common stock made by us or on our behalf for the periods shown below.

Period
Total Number
of Shares
Purchased¹
Average Price
Paid for Shares
Total Number
of Shares
Purchased as
Part of Publicly
Announced
Plans or
Programs
Maximum Dollar
Amounts of
Shares that
May Yet Be
Purchased Under
the Plans and
Programs (at
month end)²

July 1 – July 31, 2009
6,593 $ 26.59 — $ 750 million
August 1 – August 31, 2009
131 28.78 — 750 million
September 1 – September 30, 2009
815 31.45 — 750 million

Total
7,539 $ 27.16 — —

Period		Average Price Paid for Shares


January 1 – January 31, 2010	37	$	35.63	—	—
February 1 – February 28, 2010	185,400		34.74	—	—
March 1 – March 31, 2010	196		36.44	—	—

Total	185,633	$	34.74	—	—

1 Represents shares surrendered by employees to satisfy tax withholding obligations on vested restricted stock and restricted stock units.

2 In October 2007, our Board of Directors approved a common share repurchase program for up to $1 billion of our outstanding common shares over the 24 months following approval. This program expired in October 2009. Pursuant to the terms of our credit facilities, we are prohibited from engaging in a common share repurchase in an aggregate amount in excess of $100 million without the approval of the lenders.

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Item 5. Other Information

Forward Looking Statements

We make statements in this report that are considered forward looking statements within the meaning of the Securities Exchange Act of 1934. Sometimes these statements will contain words such as "believes," "anticipates," "expects," "intends," "plans," and other similar words. We also disclose non-historical information that represents management's expectations, which are based on numerous assumptions. These statements and projections are not guarantees of our future performance and are subject to risks, uncertainties, and other important factors that could cause our actual performance or achievements to be materially different from those we project. These risks, uncertainties, and factors include, but are not limited to:

•: the timing and extent of changes in commodity prices and volatilities for energy and ~~energy related~~energy-related products including coal, natural gas, oil, electricity, nuclear fuel, ~~freight,~~ and emission allowances, and the impact of such changes on our liquidity requirements,
•: the liquidity and competitiveness of wholesale and retail markets for energy commodities,
•: the conditions of the capital markets, interest rates, foreign exchange rates, availability of credit facilities to support business requirements, liquidity, and general economic conditions, as well as Constellation Energy Group's (Constellation Energy) and Baltimore Gas and Electric's (BGE) ability to maintain their current credit ratings,
•: the effectiveness of Constellation Energy's and BGE's risk management policies and procedures and the ability and willingness of our counterparties to satisfy their financial and performance commitments,
•: ~~the ability to complete our strategic initiatives to improve our liquidity and the impact of such initiatives on our business and financial results,~~
•: losses on the sale or write-down of assets due to impairment events or changes in management intent with regard to either holding or selling certain assets,
•: the ability to successfully identify, finance, and complete acquisitions and sales of businesses and assets, including generating facilities and new nuclear generation development projects,
•: the effect of weather and general economic and business conditions on energy supply, demand, prices, and customers' and counterparties' ability to perform their obligations or make payments,
•: the ability to attract and retain customers in our ~~Customer Supply activities~~NewEnergy business and to adequately forecast their energy usage,
•: the timing and extent of deregulation of, and competition in, the energy markets, and the rules and regulations adopted in those markets,
•: ~~uncertainties associated with estimating natural gas reserves, developing properties, and extracting natural gas,~~
•: regulatory or legislative developments federally, in Maryland, or in other states that affect energy deregulation, the price of energy, transmission or distribution rates and revenues, demand for energy, or increases in costs, including costs related to ~~nuclear power plants,~~ safety, or environmental compliance,
•: the ability of our regulated and nonregulated businesses to comply with complex and/or changing market rules and regulations,
•: the ability of BGE to recover all its costs associated with providing customers service,
•: operational factors affecting commercial operations of our generating facilities ~~(including nuclear facilities)~~ and BGE's transmission and distribution facilities, including ~~catastrophic~~ weather-related damages, unscheduled outages or repairs, unanticipated changes in fuel costs or availability, unavailability of coal or gas transportation or electric transmission services, workforce issues, terrorism, liabilities associated with catastrophic events, and other events beyond our control,
•: the impact of industry consolidation,
•: the impact of increased energy conservation and use of renewable energy,
•: the actual outcome of uncertainties associated with assumptions and estimates ~~using~~requiring judgment when managing our business, applying critical accounting policies and preparing financial statements, including factors that are estimated in determining the fair value of energy contracts, such as the ability to obtain market prices and, in the absence of verifiable market prices, the appropriateness of models and model inputs (including, but not limited to, estimated contractual load obligations, unit availability, forward commodity prices, interest rates, correlation and volatility factors),
•: changes in accounting principles or practices, and
•: cost and other effects of legal and administrative proceedings that may not be covered by insurance, including environmental liabilities.

Given these uncertainties, you should not place undue reliance on these forward looking statements. Please see the other sections of this report and our other periodic reports filed with the Securities and Exchange Commission (SEC) for more information on these factors. These forward looking statements represent our estimates and assumptions only as of the date of this report.

Changes may occur after that date, and neither Constellation Energy nor BGE assumes responsibility to update these forward looking statements.

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Item 6. Exhibits


~~Exhibit No. 2(a)~~	*	~~Amendment No. 1 to the Master Put Option and Membership Interest Purchase Agreement (Designated as Exhibit No. 2.1 to the Current Report on Form 8-K dated September 16, 2009, File No. 1-12869).~~
~~Exhibit No. 2(b)~~	*	~~Amendment No. 2 to the Master Put Option and Membership Interest Purchase Agreement (Designated as Exhibit No. 2.1 to the Current Report on Form 8-K dated September 22, 2009, File No. 1-12869).~~
~~Exhibit No. 2(c)~~	*	~~Amendment No. 3 to the Master Put Option and Membership Interest Purchase Agreement (Designated as Exhibit No. 2.1 to the Current Report on Form 8-K dated October 30, 2009, File No. 1-12869).~~
~~Exhibit No. 2(d)~~	*+	Investor Rights Agreement, dated as of December 17, 2008, by and among Constellation Energy Group, Inc. and EDF Development, Inc. (Designated as Exhibit No. 10.3 to the Current Report on Form 8-K dated December 17, 2008, File No. 1-12869).
~~Exhibit No. 2(e)~~	*	Stock Purchase Agreement, dated as of December 17, 2008, by and among Constellation Energy Group, Inc., EDF Development, Inc. and Electricite de France International, S.A. (Designated as Exhibit No. 10.2 to the Current Report on Form 8-K dated December 17, 2008, File No. 1-12869).
~~Exhibit No. 4(a)~~	*	~~Form of Junior Subordinated Debenture (Designated as Exhibit 4(e) to the Registration Statement on Form S-3 dated August 5, 2003, File No. 333-107681).~~
~~Exhibit No. 4(b)~~		~~Series Supplement to Indenture dated as of June 29, 2007 by and between RSB BondCo LLC and Deutsche Bank Trust Company Americas, as Trustee and Securities Intermediary.~~
~~Exhibit No. 4(c)~~		Supplemental Indenture No. 1, dated as of October 1, 2009, to the Indenture and Security Agreement dated as of July 9, 2009, between Baltimore Gas and Electric Company and Deutsche Bank Trust Company Americas, as trustee.
~~Exhibit No. 10(a)~~	*	~~Form of CENG Operating Agreement (Designated as Exhibit No. 10.1 to the Current Report on Form 8-K dated September 22, 2009, File No. 1-12869).~~
~~Exhibit No. 10(b)~~	*	Grantor Trust Agreement dated as of February 27, 2004 between Constellation Energy Group, Inc. and Citibank, N.A. (Designated as Exhibit No. 10(a) to the Quarterly Report on Form 10-Q for the quarter ended June 30, 2004, File Nos. 1-12869 and 1-1910).
Exhibit No. 12(a)		Constellation Energy Group, Inc. Computation of Ratio of Earnings to Fixed Charges.
Exhibit No. 12(b)		Baltimore Gas and Electric Company Computation of Ratio of Earnings to Fixed Charges and Computation of Ratio of Earnings to Combined Fixed Charges and Preferred and Preference Dividend Requirements.
Exhibit No. 31(a)		Certification of Chairman of the Board, President and Chief Executive Officer of Constellation Energy Group, Inc. pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
Exhibit No. 31(b)		Certification of Senior Vice President and Chief Financial Officer of Constellation Energy Group, Inc. pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
Exhibit No. 31(c)		Certification of President and Chief Executive Officer of Baltimore Gas and Electric Company pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
Exhibit No. 31(d)		Certification of Senior Vice President and Chief Financial Officer of Baltimore Gas and Electric Company pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
Exhibit No. 32(a)		Certification of Chairman of the Board, President and Chief Executive Officer of Constellation Energy Group, Inc. pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
Exhibit No. 32(b)		Certification of Senior Vice President and Chief Financial Officer of Constellation Energy Group, Inc. pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
Exhibit No. 32(c)		Certification of President and Chief Executive Officer of Baltimore Gas and Electric Company pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
Exhibit No. 32(d)		Certification of Senior Vice President and Chief Financial Officer of Baltimore Gas and Electric Company pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
Exhibit No. 101.INS		XBRL Instance Document
Exhibit No. 101.SCH		XBRL Taxonomy Extension Schema Document
Exhibit No. 101.PRE		XBRL Taxonomy Presentation Linkbase Document
Exhibit No. 101.LAB		XBRL Taxonomy Label Linkbase Document
Exhibit No. 101.CAL		XBRL Taxonomy Calculation Linkbase Document
Exhibit No. 101.DEF		XBRL Taxonomy Definition Linkbase Document

*: ~~Incorporated by reference~~
+: ~~Exhibits not filed will be furnished supplementally to the Securities and Exchange Commission upon request.~~

In accordance with Rule 402 of Regulation S-T, the XBRL related information in Exhibit 101 to this Quarterly Report on Form 10-Q shall not be deemed to be "filed" for purposes of Section 18 of the Exchange Act, or otherwise subject to the liability of that section, and shall not be incorporated by reference into any registration statement or other document filed under the Securities Act or the Exchange Act, except as shall be expressly set forth by specific reference in such filing.

Table of Contents

SIGNATURE

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


		CONSTELLATION ENERGY GROUP, ~~INC~~INC. (Registrant)
Date:~~November 6, 2009~~May 7, 2010		/s/ JONATHAN W. THAYER Jonathan W. Thayer, Senior Vice President of Constellation Energy Group, Inc. and as Principal Financial Officer
		BALTIMORE GAS AND ELECTRIC COMPANY (Registrant)
Date:~~November 6, 2009~~May 7, 2010		/s/ KEVIN W. HADLOCK Kevin W. Hadlock, Senior Vice President of Baltimore Gas and Electric Company and as Principal Financial Officer



	(In billions)
Fair value of the consideration received from EDF	$	4.7
Estimated fair value of our retained interest in CENG		4.7
Carrying amount of CENG's assets and liabilities prior to deconsolidation		(2.6	)

Estimated pre-tax gain	$	6.8

	Q1 2009 Program			Q4 2008 Program


Initial severance liability balance	$	10.8		$	19.7
Additional expense recorded in the second quarter of 2009		0.4			—
Additional expense recorded in the third quarter of 2009		0.4			—
Amounts recorded as pension and postretirement liabilities		—			(3.0	)

Net cash severance liability		11.6			16.7
Cash severance payments		(11.4	)		(12.5	)

Severance liability balance at September 30, 2009	$	0.2		$	4.2



	(In millions)
Liability at January 1, 2009	$	987.3
Accretion expense		54.6
Liabilities incurred		0.1
Liabilities settled		(0.7	)
Revisions to cash flows		(0.4	)
Other		(0.1	)

Liability at September 30, 2009	$	1,040.8

At July 1, 2009


	(In millions)
Current assets	$	5.7
Goodwill¹		18.5
Other assets		2.3

Total assets acquired		26.5

Current liabilities		(4.7	)

Net assets acquired	$	21.8

Nine Months Ended September 30, 2009


	(In millions)
Investing activities—Contract and portfolio acquisitions	$	(866.3	)
Financing activities—Proceeds from contract and portfolio acquisitions		863.8

Net cash flows from contract and portfolio acquisitions	$	(2.5	)

Nine Months Ended September 30, 2009


	(In millions)
Investing activities—Contract and portfolio acquisitions	$	(1,287.4	)
Financing activities—Proceeds from contract and portfolio acquisitions		1,379.3

Net cash flows from contract and portfolio acquisitions	$	91.9

At September 30, 2009	Adjusted Cost		Unrealized Gains		Unrealized Losses		Fair Value


	(In millions)
Money market funds	$	20.2	$	—	$	—	$	20.2
Marketable equity securities		214.7		109.9		—		324.6
Mutual fund / common collective trusts		479.6		109.1		—		588.7
Corporate debt securities		144.9		24.3		—		169.2
U.S. Government agencies		42.5		2.5		—		45.0
U.S. Treasuries		18.9		1.1		—		20.0
State municipal bonds		46.4		5.2		—		51.6

Totals	$	967.2	$	252.1	$	—	$	1,219.3

	Quarter Ended September 30, 2009			Nine Months Ended September 30, 2009


	(In millions)
Gross realized gains	$	10.0		$	25.2
Gross realized losses		(3.5	)		(75.5	)

Net realized gains	$	6.5		$	(50.3	)

At September 30, 2009


	(In millions)
Less than 1 year	$	9.6
1-5 years		87.5
5-10 years		86.0
More than 10 years		102.7

Total maturities of debt securities	$	285.8

Facility Expiration	Facility Size as of September 30, 2009²		Facility Size Pro Forma upon Completion of the EDF Transaction²


	(In billions)
July 2012	$	3.85	$	2.32
November 2009¹		1.23		—
September 2013		0.35		—
December 2009		0.15		—
September 2014		0.25		0.50

Total	$	5.83	$	2.82

At September 30, 2009		Level 1			Level 2			Level 3			Netting and Cash Collateral*			Total Net Fair Value


		(In millions)
Cash equivalents		$	576.6		$	20.2		$	—		$	—		$	596.8
Debt and equity securities:
	Marketable equity securities		324.6			—			—			—			324.6
	Mutual funds / common collective trusts		53.2			564.7			—			—			617.9
	Corporate debt securities		—			169.2			—			—			169.2
	U.S. Government agencies		—			45.0			—			—			45.0
	U.S. Treasuries		20.0			—			—			—			20.0
	State municipal bonds		—			51.6			—			—			51.6

Debt and equity securities			397.8			830.5			—			—			1,228.3
Derivative assets			325.1			24,133.4			2,798.5			(26,497.7	)		759.3
Derivative liabilities			(391.7	)		(24,680.1	)		(3,039.1	)		26,323.0			(1,787.9	)

	Net derivative position		(66.6	)		(546.7	)		(240.6	)		(174.7	)		(1,028.6	)

Total		$	907.8		$	304.0		$	(240.6	)	$	(174.7	)	$	796.5

	2010 vs. 2009


	(in millions, after-tax)
Generation gross margin	$	(132	)
NewEnergy gross margin		117
Generation operating expenses, primarily performance-based labor and benefit costs due to the deconsolidation of CENG		100
Gain on NewEnergy international coal contract assignment		38
NewEnergy hedge ineffectiveness		(6	)
Regulated businesses		(18	)
Total change inOther Items included in Operations per table below		175
All other changes		41

Total Change	$	315

	Quarter Ended September 30,			Nine Months Ended September 30,

	2009 vs. 2008

	(In millions, after-tax)
Generation gross margin	$	(11	)	$	62
Customer supply gross margin		(8	)		4
Global Commodities gross margin		169			(232	)
Hedge ineffectiveness		4			100
Absence of sale of upstream gas assets		—			(55	)
Absence of credit loss—coal supplier bankruptcy		—			33
Merchant interest expense		(24	)		(77	)
Regulated businesses, primarily related to absence of Maryland settlement agreement credit		9			137
Other nonregulated businesses		(8	)		(17	)
Total change in Other Items included in operations perOverview—Results table		256			(14	)
All other changes		(24	)		(10	)

Total Change	$	363		$	(69	)

	2010 vs. 2009


	(In millions)
Decrease in volume of output from nuclear generating assets due to the deconsolidation of CENG	$	(159	)
Decrease due to higher planned outages at our fossil plants		(61	)
All other		14

Total decrease in Generation revenues	$	(206	)

	2010 vs. 2009


	(In millions)
Increase in purchased energy costs due to power purchase agreement with CENG compared with nuclear fuel costs in 2009	$	160
Decrease due to higher planned outages at our fossil plants		(40	)
All other		(15	)

Total increase in Generation fuel and purchased energy expenses	$	105

	Quarter Ended September 30,			Nine Months Ended September 30,

	2009 vs. 2008

	(In millions)
Increase (decrease) in Global Commodities mark-to-market revenues due to changes in power and gas prices	$	205		$	(235	)
Decrease in volume of business primarily related to our international coal and freight operation, which we have divested		(143	)		(652	)
Increase in contract prices and volume related to our domestic coal operation		67			240
Realization of lower prices and volume of business at our gas trading operation, which we have divested, and absence of revenue due to the sales of certain of our upstream gas properties in 2008		(5	)		(218	)
Realization of lower volumes on wholesale and retail load at our Customer Supply operation, partially offset by higher contract prices		(1,334	)		(2,097	)
All other		(25	)		(19	)

Total decrease in merchant revenues	$	(1,235	)	$	(2,981	)

	2010 vs. 2009


	(In millions)
Realization of lower volumes on wholesale load	$	(503	)
Decrease in volume and contract prices related to our domestic coal operation		(115	)
Realization of lower volumes primarily due to the absence of revenues at our gas trading operation, which we divested in 2009		(73	)
Change in wholesale mark-to-market revenues due to more favorable changes in power and gas prices		33
All other		(6	)

Total decrease in NewEnergy revenues	$	(664	)

	Quarter Ended September 30,			Nine Months Ended September 30,

	2009 vs. 2008

	(In millions)
Increase in Global Commodities mark-to-market expenses related to the absence of international coal purchase contracts due to divestiture of operations and changes in prices	$	225		$	333
Decrease in volume of business primarily related to our international coal and freight operation, which we have divested		(123	)		(562	)
Increase in contract prices and volume related to our domestic coal operation		87			207
Realization of lower volumes at our gas trading operations, which we have divested		(54	)		(197	)
Realization of lower contract prices and volumes on wholesale and retail power purchases at our Customer Supply operation		(1,696	)		(2,890	)
All other		(13	)		23

Total decrease in merchant energy fuel and purchased energy expenses	$	(1,574	)	$	(3,086	)

	Quarter Ended September 30,		Nine Months Ended September 30,

	2009 vs. 2008

	(In millions)
Increase in portfolio management of positions arising from hedges of accrual positions with Generation and Customer Supply activities due to the favorable impact of changes in prices of power, natural gas, and coal	$	327	$	484
Increase in gains recognized on hedges due to ineffectiveness and certain cash-flow hedges that no longer qualified for hedge accounting		6		160
Increase primarily due to write-downs of our emission allowance inventory recorded in 2008 that did not recur in the same periods of 2009		56		63
Increase (decrease) in earnings related to our portfolio of contracts subject to mark-to-market accounting. We discuss these results in more detail in theMark-to-Market section below.		19		(543	)
Decrease due to loss reclassified from accumulated other comprehensive loss to earnings in connection with the closing of the sale of our international commodities operation as a result of hedged transactions that were probable of not occurring by the end of the specified contract period.		—		(166	)
Increase due to the absence of our international coal and freight operations, which were divested in March 2009, and assignment of certain contracts in the third quarter of 2009		49		108
Increase due to the absence of a loss as a result of the bankruptcy of one of our domestic coal suppliers. During the first quarter of 2008, as a result of a default by the supplier, we terminated our derivative contracts with the supplier, reclassified the related asset to accounts receivable and fully reserved the amount.		—		55

Total increase in portfolio management and trading gross margin	$	457	$	161

	2010 vs. 2009


	(In millions)
Realization of lower volumes on wholesale power purchases	$	(538	)
Decrease due to the absence of costs at our international coal and freight operation, which we divested in 2009		(129	)
Decrease in volume and contract prices related to our domestic coal operation		(116	)
Decrease in wholesale mark-to-market expenses due to the absence of losses on international coal purchase contracts, which we divested in 2009		(106	)
Realization of lower volumes primarily due to the absence of costs at our gas trading operations, which we divested in 2009		(74	)
All other		(18	)

Total decrease in NewEnergy fuel and purchased energy expenses	$	(981	)

	Quarter Ended September 30, 2009 vs. 2008			Nine Months Ended September 30, 2009 vs. 2008			Quarter Ended March 31, 2010 vs. 2009


	(In millions)						(In millions)
Distribution volumes	$	(8.8	)	$	(8.1	)	$	(1.1	)
Nuclear decommissioning charges		5.1			14.2
Smart energy savers program^SM surcharges		10.2			21.3
Maryland settlement credit		0.6			188.8
Revenue decoupling		5.6			16.0
Smart Energy Savers Program^SM surcharges								(1.3	)
Standard offer service		(46.6	)		22.7			(52.4	)
Rate stabilization recovery		(2.8	)		(0.5	)		(1.2	)
Financing credits		1.3			2.4
Senate Bill 1 credits		(0.2	)		7.2

Total change in electric revenues from electric system sales		(35.6	)		264.0			(56.0	)
Other		1.5			6.3			0.5

Total change in electric revenues	$	(34.1	)	$	270.3		$	(55.5	)




Residential	(0.5	)%	(2.2	)%
Commercial	(3.0	)	0.9
Industrial	(13.3	)	(9.8	)

			2009 Segment Cash Flows									Consolidated Cash Flows


			Nine Months Ended September 30, 2009									Nine Months Ended September 30,
			Merchant			Regulated			Holding Company and Other			2009			2008

			(In millions)
Operating Activities
	Net (loss) income		$	(39.7	)	$	132.7		$	(17.0	)	$	76.0		$	102.3
	Non-cash merger termination and strategic alternatives costs			37.2			—			—			37.2			—
	Derivative contracts classified as financing activities¹			1,007.0			—			—			1,007.0			(37.1	)
	Other non-cash adjustments to net (loss) income			573.6			542.3			78.5			1,194.4			810.5
	Changes in working capital:
		Derivative assets and liabilities, excluding collateral		118.3			—			6.7			125.0			(935.0	)
		Net collateral and margin		1,502.4			2.4			—			1,504.8			(568.6	)
		Other changes		366.9			(153.2	)		42.1			255.8			(358.6	)
	Defined benefit obligations²			—			—			—			(277.7	)		(34.2	)
	Other			(34.7	)		(45.3	)		133.1			53.1			6.6

Net cash provided by (used in) operating activities				3,531.0			478.9			243.4			3,975.6			(1,014.1	)

Investing Activities
	Investments in property, plant and equipment			(961.1	)		(265.5	)		(16.6	)		(1,243.2	)		(1,360.5	)
	Asset and business acquisitions, net of cash acquired			—			—			(20.8	)		(20.8	)		(316.5	)
	Contributions to nuclear decommissioning trust funds			(18.7	)		—			—			(18.7	)		(18.7	)
	Proceeds from sale of investments and other assets			49.9			—			31.2			81.1			241.2
	Contract and portfolio acquisitions			(2,153.7	)		—			—			(2,153.7	)		—
	Repayments of loans receivable			—			—			—			—			26.0
	Decrease (increase) in restricted funds³			(1.6	)		(22.4	)		1,003.9			979.9			8.3
	Other			(0.6	)		—			(15.2	)		(15.8	)		(4.1	)

Net cash used in investing activities				(3,085.8	)		(287.9	)		982.5			(2,391.2	)		(1,424.3	)

Cash flows from operating activities less cash flows from investing activities			$	445.2		$	191.0		$	1,225.9			1,584.4			(2,438.4	)

Financing Activities²
	Net (repayment) issuance of debt												(2,080.3	)		3,041.8
	Debt issuance costs												(67.8	)		(50.6	)
	Proceeds from issuance of common stock												24.4			17.6
	Common stock dividends paid												(179.6	)		(250.7	)
	BGE preference stock dividends paid												(9.9	)		(9.9	)
	Proceeds from contract and portfolio acquisitions												2,263.1			—
	Derivative contracts classified as financing activities¹												(1,007.0	)		37.1
	Other												13.1			(8.8	)

Net cash (used in) provided by financing activities													(1,044.0	)		2,776.5

Net increase in cash and cash equivalents												$	540.4		$	338.1



	(In millions)
Net collateral and margin posted, December 31, 2008	$	(1,445.6	)
Return of collateral held associated with nonderivative contracts		(14.9	)
Net return of collateral posted associated with nonderivative contracts		324.2
Return of initial and variation margin posted on exchange-traded transactions recorded in accounts receivable		709.1
Return of fair value net cash collateral posted (netted against derivative assets / liabilities)*		486.4

Change in net collateral and margin posted		1,504.8

Net collateral and margin held, September 30, 2009	$	59.2



	(In billions)
Decrease in letters of credit issued	$	1.6
EDF put arrangement		1.1
Decrease in cash drawn on facilities		0.9
Increase in cash		0.5
Decrease in credit facilities		(0.4	)
Increase in commercial paper issued		(0.3	)

Increase in net available liquidity	$	3.4

Rating	Total Exposure Before Credit Collateral		Credit Collateral		Net Exposure			Net Exposure of Counterparties Greater than 10% of Net Exposure


	(In millions)
Investment grade	$	1,082	$	304	$	778	—	$	—
Split rating		3		—		3	—		—
Non-investment grade		95		43		52	—		—
Internally rated—investment grade		77		—		77	—		—
Internally rated—non-investment grade		10		—		10	—		—

Total	$	1,267	$	347	$	920	—	$	—

Period		Average Price Paid for Shares			Maximum Dollar Amounts of Shares that May Yet Be Purchased Under the Plans and Programs (at month end)²


July 1 – July 31, 2009	6,593	$	26.59	—	$	750 million
August 1 – August 31, 2009	131		28.78	—		750 million
September 1 – September 30, 2009	815		31.45	—		750 million

Total	7,539	$	27.16	—		—