Edgar Filing: CONSTELLATION ENERGY GROUP INC

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TABLE OF CONTENTS

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 March 31, 2009


Commission File Number	Exact name of registrant as specified in its charter	IRS Employer Identification No.
1-12869	CONSTELLATION ENERGY GROUP, INC.	52-1964611
1-1910	BALTIMORE GAS AND ELECTRIC COMPANY	52-0280210

MARYLAND
(State of Incorporation of both registrants)

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

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

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 the registrant 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 one):


Large accelerated filer ý		Accelerated filer o		Non-accelerated filer o (Do not check if a smaller reporting company)		Smaller reporting company o

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 one):


Large accelerated filer o		Accelerated filer o		Non-accelerated filer ý (Do not check if a smaller reporting company)		Smaller reporting company o

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 199,192,018 shares outstanding
of Constellation Energy Group, Inc. on April 30, 2009.

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	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		40
		Introduction and Overview	40
		Business Environment	40
		Events of 2009	41
		Results of Operations	42
		Financial Condition	55
		Capital Resources	60
	Item 3—Quantitative and Qualitative Disclosures About Market Risk		66
	Items 4 and 4(T)—Controls and Procedures		66
Part II—Other Information			67
	Item 1—Legal Proceedings		67
	Item 2—Issuer Purchases of Equity Securities		67
	Item 5—Other Information		68
	Item 6—Exhibits		69
	Signature		70

Table of Contents

PART 1—FINANCIAL INFORMATION

Item 1—Financial Statements

CONSOLIDATED STATEMENTS OF INCOME (LOSS) (UNAUDITED)

Constellation Energy Group, Inc. and Subsidiaries

		Three Months Ended March 31,

		2009			2008

		(In millions, except per share amounts)
Revenues
	Nonregulated revenues	$	3,112.3		$	3,711.9
	Regulated electric revenues		806.8			709.3
	Regulated gas revenues		384.3			391.0

	Total revenues		4,303.4			4,812.2
Expenses
	Fuel and purchased energy expenses		3,273.2			3,743.1
	Operating expenses		581.7			590.1
	Merger termination and strategic alternatives costs		42.3			—
	Impairment losses and other costs		28.6			—
	Workforce reduction costs		10.8			—
	Depreciation, depletion, and amortization		148.6			148.3
	Accretion of asset retirement obligations		17.9			16.6
	Taxes other than income taxes		77.9			74.8

	Total expenses		4,181.0			4,572.9
Net (loss) gain on divestitures			(334.5	)		15.0

(Loss) Income from Operations			(212.1	)		254.3
Other (Expense) Income			(27.5	)		42.7
Fixed Charges
	Interest expense		143.9			78.8
	Interest capitalized and allowance for borrowed funds used during construction		(21.6	)		(7.1	)

	Total fixed charges		122.3			71.7

(Loss) Income from Continuing Operations Before Income Taxes			(361.9	)		225.3
Income Tax (Benefit) Expense			(242.2	)		75.9

Net (Loss) Income			(119.7	)		149.4
Less: Net Income Attributable to Noncontrolling Interests and BGE Preference Stock Dividends			3.8			3.7

Net (Loss) Income Attributable to Common Stock		$	(123.5	)	$	145.7

Average Shares of Common Stock Outstanding—Basic			198.5			178.2
Average Shares of Common Stock Outstanding—Diluted			198.5			180.2

(Loss) Earnings Per Common Share—Basic		$	(0.62	)	$	0.82

(Loss) Earnings Per Common Share—Diluted		$	(0.62	)	$	0.81

Dividends Declared Per Common Share		$	0.24		$	0.4775

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) (UNAUDITED)

Constellation Energy Group, Inc. and Subsidiaries

				Three Months Ended March 31,

				2009			2008

				(In millions)
Net (Loss) Income				$	(119.7	)	$	149.4
	Other comprehensive (loss) income (OCI)
		Hedging instruments:
			Reclassification of net loss on hedging instruments from OCI to net (loss) income, net of taxes		459.9			177.0
			Net unrealized (loss) gain on hedging instruments, net of taxes		(336.2	)		361.6
		Available-for-sale securities:
			Reclassification of net loss (gain) on sales of securities from OCI to net (loss) income, net of taxes		29.7			(0.3	)
			Net unrealized loss on securities, net of taxes		(26.7	)		(45.1	)
		Defined benefit obligations:
			Amortization of net actuarial loss, prior service cost, and transition obligation included in net periodic benefit cost, net of taxes		7.9			5.1
		Net unrealized gain (loss) on foreign currency, net of taxes			2.0			(2.5	)

	Comprehensive income				16.9			645.2
		Less: Comprehensive income attributable to noncontrolling interests, net of taxes			3.8			3.7

Comprehensive Income Attributable to Common Stock				$	13.1		$	641.5

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

Constellation Energy Group, Inc. and Subsidiaries

			*March 31,* 2009*			December 31, 2008


			(In millions)
Assets
	Current Assets
		Cash and cash equivalents	$	546.7		$	202.2
		Accounts receivable (net of allowance for uncollectibles of $249.1 and $240.6, respectively)		3,163.6			3,389.9
		Fuel stocks		451.1			717.9
		Materials and supplies		221.2			224.5
		Derivative assets		1,257.3			1,465.0
		Unamortized energy contract assets		170.2			81.3
		Restricted cash		51.3			1,030.5
		Deferred income taxes		280.6			268.0
		Other		426.9			815.5

		Total current assets		6,568.9			8,194.8

Investments and Other Noncurrent Assets
		Nuclear decommissioning trust funds		983.3			1,006.3
		Other investments		412.5			421.0
		Regulatory assets (net)		470.0			494.7
		Goodwill		4.6			4.6
		Derivative assets		767.5			851.8
		Unamortized energy contract assets		244.2			173.1
		Other		375.9			421.3

		Total investments and other noncurrent assets		3,258.0			3,372.8

Property, Plant and Equipment
		Property, plant and equipment		15,496.1			15,285.6
		Nuclear fuel (net of amortization)		454.6			443.0
		Accumulated depreciation		(5,011.6	)		(5,012.1	)

		Net property, plant and equipment		10,939.1			10,716.5

	Total Assets		$	20,766.0		$	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

				*March 31,* 2009*			December 31, 2008


				(In millions)
Liabilities and Equity
	Current Liabilities
		Short-term borrowings		$	1,062.9		$	855.7
		Current portion of long-term debt			1,591.1			2,591.5
		Accounts payable and accrued liabilities			2,024.1			2,370.1
		Customer deposits and collateral			146.6			120.3
		Derivative liabilities			1,180.6			1,241.8
		Unamortized energy contract liabilities			497.0			393.5
		Accrued expenses			380.6			373.1
		Other			523.0			514.2

		Total current liabilities			7,405.9			8,460.2

	Deferred Credits and Other Noncurrent Liabilities
		Deferred income taxes			480.1			677.0
		Asset retirement obligations			1,004.9			987.3
		Derivative liabilities			1,095.5			1,115.0
		Unamortized energy contract liabilities			955.3			906.4
		Defined benefit obligations			1,096.2			1,354.3
		Deferred investment tax credits			42.6			44.1
		Other			196.0			249.6

		Total deferred credits and other noncurrent liabilities			4,870.6			5,333.7

	Long-term Debt, Net of Current Portion				5,134.2			5,098.7
	Equity
		Common shareholders' equity:
			Common stock		3,177.1			3,164.5
			Retained earnings		2,042.7			2,228.7
			Accumulated other comprehensive loss		(2,075.2	)		(2,211.8	)

		Total common shareholders' equity			3,144.6			3,181.4
		BGE preference stock not subject to mandatory redemption			190.0			190.0
		Noncontrolling interests			20.7			20.1

		Total equity			3,355.3			3,391.5

	Commitments, Guarantees, and Contingencies (see Notes)
	Total Liabilities and Equity			$	20,766.0		$	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.

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CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)

Constellation Energy Group, Inc. and Subsidiaries

Three Months Ended March 31,				2009			2008


				(In millions)
Cash Flows From Operating Activities
	Net (loss) income			$	(119.7	)	$	149.4
	Adjustments to reconcile to net cash provided by operating activities
		Depreciation, depletion, and amortization			148.6			148.3
		Amortization of nuclear fuel			30.8			28.7
		Amortization of energy contracts			(43.3	)		(43.7	)
		All other amortization			35.1			4.3
		Accretion of asset retirement obligations			17.9			16.6
		Deferred income taxes			(308.8	)		(53.7	)
		Investment tax credit adjustments			(1.5	)		(1.6	)
		Deferred fuel costs			16.6			15.9
		Defined benefit obligation expense			30.7			28.8
		Defined benefit obligation payments			(282.2	)		(91.2	)
		Workforce reduction costs			10.8			—
		Impairment losses and other costs			28.6			—
		Impairment losses on nuclear decommissioning trust assets			60.5			7.8
		Merger termination and strategic alternatives costs			37.2			—
		Loss (gain) on divestitures			334.5			(21.8	)
		Gains on termination of contracts			—			(65.7	)
		Equity in earnings of affiliates less than (more than) dividends received			5.7			(3.6	)
		Derivative sales contracts classified as financing activities under SFAS No. 149			296.8			1.5
		Changes in:
			Accounts receivable, excluding margin		219.9			(219.2	)
			Derivative assets and liabilities, excluding collateral		67.6			(1.2	)
			Net collateral and margin		211.6			323.7
			Materials, supplies, and fuel stocks		270.0			(19.4	)
			Other current assets		240.9			23.1
			Accounts payable and accrued liabilities		(345.9	)		313.5
			Other current liabilities		7.5			(223.2	)
		Other			19.9			31.1

	Net cash provided by operating activities				989.8			348.4

Cash Flows From Investing Activities
	Investments in property, plant and equipment				(392.1	)		(388.4	)
	Asset acquisitions, net of cash acquired				—			(156.9	)
	Investments in nuclear decommissioning trust fund securities				(135.4	)		(124.7	)
	Proceeds from nuclear decommissioning trust fund securities				116.7			106.0
	Proceeds from sales of investments and other assets				31.4			63.8
	Contract and portfolio acquisitions				(866.3	)		—
	Decrease (increase) in restricted funds				979.3			(39.3	)
	Other				(0.9	)		(0.6	)

	Net cash used in investing activities				(267.3	)		(540.1	)

Cash Flows From Financing Activities
	Net issuance (repayment) of short-term borrowings				207.2			(14.0	)
	Proceeds from issuance of common stock				5.8			3.9
	Proceeds from issuance of long-term debt				109.0			—
	Repayment of long-term debt				(1,119.6	)		(149.7	)
	Debt issuance costs				(62.7	)		—
	Common stock dividends paid				(85.7	)		(79.3	)
	BGE preference stock dividends paid				(3.3	)		(3.3	)
	Proceeds from contract and portfolio acquisitions				863.8			—
	Derivative sales contracts classified as financing activities under SFAS No. 149				(296.8	)		(1.5	)
	Other				4.3			2.3

	Net cash used in financing activities				(378.0	)		(241.6	)

Net Increase (Decrease) in Cash and Cash Equivalents					344.5			(433.3	)
Cash and Cash Equivalents at Beginning of Period					202.2			1,095.9

Cash and Cash Equivalents at End of Period				$	546.7		$	662.6

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

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CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED)

Baltimore Gas and Electric Company and Subsidiaries

			Three Months Ended March 31,

			2009			2008

			(In millions)
Revenues
	Electric revenues		$	806.8		$	709.4
	Gas revenues			386.9			396.4

	Total revenues			1,193.7			1,105.8
Expenses
	Operating expenses
		Electricity purchased for resale		525.2			455.3
		Gas purchased for resale		258.1			270.0
		Operations and maintenance		127.0			133.6
	Depreciation and amortization			66.9			62.7
	Taxes other than income taxes			47.8			46.5

	Total expenses			1,025.0			968.1

Income from Operations				168.7			137.7
Other Income				7.5			7.9
Fixed Charges
	Interest expense			36.7			35.0
	Allowance for borrowed funds used during construction			(1.0	)		(1.0	)

	Total fixed charges			35.7			34.0

Income Before Income Taxes				140.5			111.6
Income Taxes				55.5			35.4

Net Income				85.0			76.2
Preference Stock Dividends				3.3			3.3

Net Income Attributable to Common Stock before Noncontrolling Interests				81.7			72.9
Net Loss Attributable to Noncontrolling Interests				—			0.1

Net Income Attributable to Common Stock			$	81.7		$	73.0

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

Table of Contents

CONSOLIDATED BALANCE SHEETS

Baltimore Gas and Electric Company and Subsidiaries

				*March 31,* 2009*			December 31, 2008


				(In millions)
Assets
	Current Assets
		Cash and cash equivalents		$	13.0		$	10.7
		Accounts receivable (net of allowance for uncollectibles of $34.3 and $33.3, respectively)			426.1			327.0
		Accounts receivable, unbilled (net of allowance for uncollectibles of $0.9 and $0.9, respectively)			178.9			232.3
		Investment in cash pool, affiliated company			387.7			148.8
		Accounts receivable, affiliated companies			3.0			4.3
		Fuel stocks			32.9			143.7
		Materials and supplies			36.0			38.4
		Prepaid taxes other than income taxes			25.0			51.0
		Regulatory assets (net)			60.0			79.7
		Restricted cash			48.2			23.7
		Other			7.6			10.8

		Total current assets			1,218.4			1,070.4

	Investments and Other Assets
		Regulatory assets (net)			470.0			494.7
		Receivable, affiliated company			311.9			161.1
		Other			123.9			131.6

		Total investments and other assets			905.8			787.4

	Utility Plant
		Plant in service
			Electric		4,523.1			4,493.7
			Gas		1,225.7			1,221.1
			Common		488.5			476.3

			Total plant in service		6,237.3			6,191.1
		Accumulated depreciation			(2,218.5	)		(2,191.0	)

		Net plant in service			4,018.8			4,000.1
		Construction work in progress			244.1			225.7
		Plant held for future use			2.3			2.6

		Net utility plant			4,265.2			4,228.4

	Total Assets			$	6,389.4		$	6,086.2

* Unaudited
See Notes to Consolidated Financial Statements.

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

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CONSOLIDATED BALANCE SHEETS

Baltimore Gas and Electric Company and Subsidiaries

				*March 31,* 2009*			December 31, 2008


				(In millions)
Liabilities and Equity
	Current Liabilities
		Short-term borrowings		$	370.0		$	370.0
		Current portion of long-term debt			90.0			90.0
		Accounts payable and accrued liabilities			164.3			231.0
		Accounts payable and accrued liabilities, affiliated companies			269.8			97.0
		Customer deposits			74.3			72.3
		Current portion of deferred income taxes			32.5			40.2
		Accrued taxes			128.7			18.8
		Accrued expenses and other			95.6			98.4

		Total current liabilities			1,225.2			1,017.7

	Deferred Credits and Other Liabilities
		Deferred income taxes			861.4			843.3
		Payable, affiliated company			243.3			243.2
		Deferred investment tax credits			10.4			10.6
		Other			24.5			28.6

		Total deferred credits and other liabilities			1,139.6			1,125.7

	Long-term Debt
		Rate stabilization bonds			564.4			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 business			25.0			25.0
		Unamortized discount and premium			(2.3	)		(2.4	)
		Current portion of long-term debt			(90.0	)		(90.0	)

		Total long-term debt			2,197.8			2,197.7

	Equity
		Common shareholder's equity:
			Common stock		912.2			912.2
			Retained earnings		707.1			625.4
			Accumulated other comprehensive income		0.6			0.6

		Total common shareholder's equity			1,619.9			1,538.2
		Preference stock not subject to mandatory redemption			190.0			190.0
		Noncontrolling interest			16.9			16.9

		Total equity			1,826.8			1,745.1

	Commitments, Guarantees, and Contingencies (see Notes)
	Total Liabilities and Equity			$	6,389.4		$	6,086.2

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

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CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)

Baltimore Gas and Electric Company and Subsidiaries

Three Months Ended March 31,				2009			2008


				(In millions)
Cash Flows From Operating Activities
	Net income			$	85.0		$	76.2
	Adjustments to reconcile to net cash provided by operating activities
		Depreciation and amortization			66.9			62.7
		Other amortization			0.9			3.3
		Deferred income taxes			9.0			(6.1	)
		Investment tax credit adjustments			(0.3	)		(0.4	)
		Deferred fuel costs			16.6			15.9
		Defined benefit plan expenses			9.2			9.5
		Allowance for equity funds used during construction			(2.0	)		(1.9	)
		Changes in
			Accounts receivable		(45.7	)		(49.4	)
			Accounts receivable, affiliated companies		1.3			1.0
			Materials, supplies, and fuel stocks		113.2			81.6
			Other current assets		29.3			26.7
			Accounts payable and accrued liabilities		(66.7	)		(26.3	)
			Accounts payable and accrued liabilities, affiliated companies		14.8			(3.2	)
			Other current liabilities		102.2			52.7
			Long-term receivables and payables, affiliated companies		(1.9	)		(1.2	)
			Other		16.5			22.2

	Net cash provided by operating activities				348.3			263.3

Cash Flows From Investing Activities
	Utility construction expenditures (excluding equity portion of allowance for funds used during construction)				(79.3	)		(114.0	)
	Change in cash pool at parent				(238.9	)		37.3
	Proceeds from sales of property, plant and equipment				—			12.9
	Increase in restricted funds				(24.5	)		(38.7	)

	Net cash used in investing activities				(342.7	)		(102.5	)

Cash Flows From Financing Activities
	Repayment of long-term debt				—			(144.7	)
	Preference stock dividends paid				(3.3	)		(3.3	)

	Net cash used in financing activities				(3.3	)		(148.0	)

Net Increase in Cash and Cash Equivalents					2.3			12.8
Cash and Cash Equivalents at Beginning of Period					10.7			17.6

Cash and Cash Equivalents at End of Period				$	13.0		$	30.4

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

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

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.

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.

Reclassifications

We have reclassified certain prior-period amounts:

•

In accordance with Statement of Financial Accounting Standards (SFAS) No. 160, Noncontrolling Interests in Consolidated Financial Statements, an amendment of ARB No. 51, which we adopted on January 1, 2009, we have separately presented:

•: "Net (loss) income attributable to noncontrolling interests" on our, and BGE's, Consolidated Statements of Income (Loss),
•: "Noncontrolling interests" and "BGE Preference Stock Not Subject to Mandatory Redemption" as noncontrolling interests on our Consolidated Balance Sheets,
•: "Comprehensive income attributable to noncontrolling interests, net of taxes" in our Statements of Comprehensive Income (Loss), and
•: "BGE preference stock dividends paid" in the financing section of our Statement of Cash Flows.

We discuss our adoption of SFAS No. 160 in more detail on page 38.

•

We also made the following reclassifications:

•: We have separately presented "Net (loss) gain on divestitures" from "Nonregulated revenues" on our Consolidated Statement of Income (Loss).
•: We have separately presented "Amortization of nuclear fuel," "Amortization of energy contracts," and "All other amortization" that were previously reported within "Depreciation, depletion, and amortization" on our Consolidated Statements of Cash Flows.
•: We have separately presented "Net collateral and margin" that was previously reported within other working capital accounts on our Consolidated Statements of Cash Flows.
•: We have separately presented "Other amortization" that was previously reported within "Depreciation and amortization" on BGE's Consolidated Statements of Cash Flows.

Investment Agreement with EDF Group

On December 17, 2008, we entered into an Investment Agreement with EDF Group 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 of our 2008 Annual Report on Form 10-K.

Merger Termination and Strategic Alternatives Costs

We incurred costs during the quarter ended March 31, 2009 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 $42.3 million pre-tax and primarily relate to the 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.

Variable Interest Entities

As of March 31, 2009, we consolidated two variable interest entities (VIE) in which we were the primary beneficiary, and we had significant interests in seven VIEs for which we did not have controlling financial interests and, accordingly, were 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

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pursuant to 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 variable interest entity for which it is the primary beneficiary. As a result, BGE, and we, consolidated BondCo.

The carrying amounts and classification of BondCo's assets and liabilities included in our consolidated financial statements at March 31, 2009 are as follows:

	(In millions)


Current assets	$	48.2
Noncurrent assets		—

Total Assets	$	48.2

Current liabilities	$	69.5
Noncurrent liabilities		510.9

Total Liabilities	$	580.4

The BondCo assets above 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 ended March 31, 2009, BGE remitted $24.5 million to BondCo.

BGE did not provide any additional financial support to BondCo during the quarter ended March 31, 2009. Further, BGE does not have any contractual commitments or obligations to provide additional financial support to BondCo unless additional rate stabilization bonds are issued. Alternatively, 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.

We 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.

Unconsolidated Variable Interest Entities

As of March 31, 2009, we had significant interests in seven VIEs for which we were not the primary beneficiary. We have not provided any material financial or other support to these entities during the quarter ended March 31, 2009.

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	$43.0 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 million debt guarantee and working capital funding	Prior to 2003
Retail gas supply (1 entity)	Equity financing and proceeds from gas sales	Gas supply agreement	$3.2 million in obligations under gas supply agreement	February 2008

We discuss the nature of our involvement with the power contract monetization VIEs in detail in Note 4 of our 2008 Annual Report on Form 10-K.

The following is summary information available as of March 31, 2009 about the VIEs in which we have a significant interest, but are not the primary beneficiary:

		Power Contract Monetization VIEs		All Other VIEs		Total


		(In millions)
Total assets		$	576.6	$	321.9	$	898.5
Total liabilities			468.7		104.6		573.3
Our ownership interest			—		54.0		54.0
Other ownership interests			107.9		163.3		271.2
Our maximum exposure to loss			43.0		59.2		102.2
Carrying amount and location of variable interest on balance sheet:
	-Other investments		—		54.0		54.0

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 associated with these entities. Our maximum exposure to loss as of March 31, 2009 consists of the following:

•: outstanding receivables, loans, and letters of credit totaling $46.2 million,

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•: the carrying amount of our investment totaling $54.0 million, and
•: debt and payment guarantees totaling $2.0 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

Equity Securities

We evaluated certain of our investments in equity securities in light of continued declines in market prices during the first quarter of 2009. The investments we evaluated included our investment in Constellation Energy Partners LLC (CEP), 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 our carrying value and the decline is "other than temporary." We do not record an impairment charge if the decline in value is temporary and we have the ability and intent to hold the investment until its value recovers.

In making this determination, we evaluate the reasons for an investment's decline in value, the extent and length 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.

As of March 31, 2009, the fair value of our investment in 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 reflects 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 is 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). To the extent that the market price of our investment declines further in future quarters, we may record additional write-downs if we determine that those additional declines are other than temporary.

As a result of declines in the stock market during the first quarter of 2009, the fair values of certain of our marketable securities and many of the securities held in our nuclear decommissioning trust fund declined below book value. As a result, we recorded a $60.5 million pre-tax impairment charge for our nuclear decommissioning trust fund assets in the "Other (expense) income" 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 discuss our impairment policy for our nuclear decommissioning trust fund assets in more detail in Note 1 to our 2008 Annual Report on Form 10-K. We also recorded an impairment charge of $0.5 million for other marketable securities during the quarter ended March 31, 2009.

The estimates we utilize in evaluating impairment of our equity 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.

Other Costs

During the quarter ended March 31, 2009, we recorded a $14.1 million pre-tax charge in the "Impairment losses and other costs" line in our Consolidated Statements of Income (Loss) primarily related to certain long-lived assets that ceased to be used as of March 31, 2009 in connection with the divestiture of a majority of our international commodities operation and our Houston-based gas trading operation.

Workforce Reduction Costs

We incurred workforce reduction costs during the quarter ended March 31, 2009 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 a $10.8 million pre-tax charge in 2009 related to the elimination of approximately 180 positions. We expect all of these restructurings will be completed within the next 12 months.

We incurred costs related to workforce reduction efforts initiated at our Customer Supply operations in

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2008. The following table summarizes the status of the involuntary severance liability at March 31, 2009:



	(In millions)
Initial severance liability balance	$	2.5
Amounts recorded as pension and postretirement liabilities		—

Net cash severance liability		2.5
Cash severance payments		(2.0	)
Other		—

Severance liability balance at March 31, 2009	$	0.5

We also incurred costs related to workforce reduction efforts initiated across all of our operations in 2008.

The following table summarizes the status of this involuntary severance liability at March 31, 2009:



	(In millions)
Initial severance liability balance	$	19.7
Amounts recorded as pension and postretirement liabilities		(3.0	)

Net cash severance liability		16.7
Cash severance payments		(5.8	)
Other		(0.2	)

Severance liability balance at March 31, 2009	$	10.7

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

Earnings Per Share

Basic earnings per common share (EPS) is computed by dividing earnings applicable 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 March 31,

	2009		2008

	(In millions)
Non-dilutive stock options		5.5		0.6
Dilutive common stock equivalent shares		0.4		2.0

As a result of the Company incurring a loss for the quarter ended March 31, 2009, dilutive common stock equivalent shares were not included in calculating diluted EPS.

We issued to MidAmerican 19,897,322 shares of Constellation Energy's common stock upon the conversion of the Series A Preferred Stock, which happened upon the termination of the merger agreement with MidAmerican on December 17, 2008. We discuss the conversion feature of the Series A Preferred Stock in more detail in Note 9 of our 2008 Annual Report on Form 10-K. These additional shares impacted our earnings per share for the quarter ended March 31, 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		17.9
Liabilities incurred		0.1
Liabilities settled		(0.2	)
Revisions to cash flows		—
Other		(0.2	)

Liability at March 31, 2009	$	1,004.9

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.

International Commodities Operation

In January 2009, we entered into a definitive agreement to sell a majority of our international commodities operation.

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We completed this transaction on March 23, 2009 and recognized the following impacts:

•: 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 Statement of Income (Loss),
•: workforce reduction costs of $9.8 million, recorded as part of "Workforce reduction costs" in the Consolidated Statement of Income (Loss), and
•: other costs of $10.1 million related to leasehold improvements, furniture and computer hardware and software, recorded as part of "Impairment losses and other costs" in the Consolidated Statement of Income (Loss).

The transaction to sell a majority of our international commodities operation was 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.

We removed the contracts that were assigned from our 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.

Under the TRS, we entered into offsetting trades with the buyer that matched the terms of the remaining third party contracts for which we were unable to complete assignment to the buyer as of March 23, 2009. This structure transferred the risks associated with changes in commodity prices after March 23, 2009 to the buyer 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 buyer under the TRS with no right of either financial or legal offset. We continue to pursue the assignment of these remaining contracts to the buyer.

The matching contracts under the TRS are both derivatives and non-derivatives and were executed at prices that differed from market prices at closing, which resulted in a net cash payment of approximately $3 million to the buyer. We recorded the underlying contracts at fair value on a gross basis as assets or liabilities in our Consolidated Balance Sheets depending on whether they 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 resulted in a net liability of approximately $75 million that 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 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

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:

Quarter Ended March 31, 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	)

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, which were liabilities at inception. We record the ongoing cash flows from these contracts as financing activities, regardless of whether they are purchase or sales contracts, as required by SFAS No. 149.

In addition to the March 23, 2009 transaction for a majority of our international commodities operation, we entered into a separate agreement to sell certain other international assets, which is expected to close in the second quarter of 2009. We expect to receive cash proceeds of approximately $45 million and record an approximately $30 million loss on this sale.

Houston-Based Gas Trading Operation

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, received proceeds of approximately $46 million, and expect to record an approximately $130 million loss on this sale in

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the second quarter of 2009. The 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 transaction to sell our Houston-based gas trading operation was structured so that the buyer would assume the market risks of the operation during March 2009 and ultimately assume the performance risks at the closing date, which was April 1, 2009. At March 1, 2009, we terminated our exchange transactions, and transferred our storage contracts and storage inventory at market prices, and we executed transactions with the buyer that matched the terms of the third party derivative and non-derivative transactions to transfer the market risks for the remainder of the operation prior to the assignment of the underlying transactions to the buyer. We remain the principal to the third party transactions and the newly executed offsetting transactions until the third party transactions are successfully assigned. The derivative contracts, including the newly executed offsetting transactions, have been included in "Derivative Assets and Liabilities" in our Consolidated Balance Sheets.

The matching derivative and nonderivative transactions were executed at prices that differed from market prices at March 1, 2009. As a result, we record the ongoing cash flows related to the out-of-the-money derivative contracts as financing cash flows in accordance with SFAS No. 149. This resulted in cash outflows related to financing activities of $317.4 million in our Consolidated Statements of Cash Flows for the month of March 2009 associated with derivatives that were out of the money at March 1, 2009.

In addition, we incurred other costs of $4.0 million 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) during the first quarter of 2009.

We also have entered into 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. In connection with this agreement, we were required to post approximately $160 million of collateral. This represents approximately 25 percent of the previous collateral requirements to support this operation.

Impacts on Collateral Requirements

As a result of the divestitures of the international commodities operation, the Houston-based gas trading operation, and other smaller operations, by April 30, 2009 we have realized substantially all of the $1 billion of previously posted net collateral that supported these operations. Due to the successful execution of the announced divestitures, we estimate our collateral requirements in the event of a credit ratings downgrade would be decreased by $400 million based on current commodity prices. The actual amount of the reduction will be impacted by the actual timing of the remaining contract assignments.

Information by Operating Segment

Our reportable operating segments are Merchant Energy, Regulated Electric, and Regulated Gas:

•

Our merchant energy business is nonregulated and includes:

—: fossil, nuclear, and interests in hydroelectric generating facilities and qualifying facilities, and power projects in the United States,
—: full requirements load-serving sales of energy and capacity to utilities, cooperatives, and commercial, industrial, and governmental customers,
—: gas retail energy products and services to commercial, industrial, and governmental customers,
—: structured transactions and risk management services for various customers (including hedging of output from generating facilities and fuel costs),
—: deployment of risk capital through portfolio management and trading activities,
—: upstream (exploration and production) and downstream (transportation and storage) natural gas operations (downstream operations sold in April 2009),
—: coal sourcing and logistics services and uranium marketing services for the variable or fixed supply needs of global customers (a majority of these activities were sold in March 2009), and
—: generation operations and maintenance.

•

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 and provide water and energy savings projects and performance contracting for commercial, industrial, and governmental customers throughout North America,

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•: 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.

In connection with efforts to improve our liquidity and reduce our business risk:

•: we completed the sale of a majority of our international commodities operation in March 2009,
•: we completed the sale of our gas trading operation on April 1, 2009,
•: we entered into an Investment Agreement with EDF on December 17, 2008. See Note 15 of our 2008 Annual Report on Form 10-K for more detail on the Investment Agreement with EDF.

We believe that the successful execution of these initiatives, as well as our other initiatives being undertaken to reduce risk in our merchant energy business, will reduce our exposure to activities that require contingent capital support and improve our liquidity. In turn, 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, 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.

	Reportable Segments

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

	(In millions)
Quarter ended March 31,
2009
Unaffiliated revenues	$	3,055.0		$	806.8	$	384.3	$	57.3		$	—		$	4,303.4
Intersegment revenues		224.5			—		2.6		—			(227.1	)		—

Total revenues		3,279.5			806.8		386.9		57.3			(227.1	)		4,303.4
Net (loss) income		(202.7	)		45.4		39.6		(2.0	)		—			(119.7	)
Net (loss) income attributable to common stock		(203.2	)		42.9		38.8		(2.0	)		—			(123.5	)
2008
Unaffiliated revenues	$	3,652.8		$	709.3	$	391.0	$	59.1		$	—		$	4,812.2
Intersegment revenues		294.2			0.1		5.4		0.1			(299.8	)		—

Total revenues		3,947.0			709.4		396.4		59.2			(299.8	)		4,812.2
Net income		72.7			36.2		40.2		0.3			—			149.4
Net income attributable to common stock		72.2			33.7		39.4		0.4			—			145.7

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

Our merchant energy business operating results for the quarter ended March 31, 2009 include the following after-tax charges:

•: impairment losses and other costs of $11.1 million,
•: merger termination and strategic alternatives costs of $42.3 million,
•: loss on sale of a majority of our international commodities operation, the reclassification 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 $184.2 million,
•: impairment charge related to our nuclear decommissioning trust fund assets of $23.8 million,
•: workforce reduction costs of $4.2 million, and
•: amortization of credit facility amendment fees in connection with the EDF transaction of $3.7 million.

Total assets decreased approximately $1.5 billion during 2009. Most of the decrease relates to our Holding Company and Other Nonregulated Businesses and is primarily related to the decline in restricted cash as a result of the repayment of the 14% Senior Notes to MidAmerican.

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Pension and Postretirement Benefits

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

	Quarter Ended March 31,

	2009			2008

	(In millions)
Components of net periodic pension benefit cost
Service cost	$	15.2		$	15.0
Interest cost		27.2			27.5
Expected return on plan assets		(29.6	)		(30.9	)
Recognized net actuarial loss		10.6			5.9
Amortization of prior service cost		3.3			2.9
Amount capitalized as construction cost		(2.6	)		(2.7	)

Net periodic pension benefit cost¹	$	24.1		$	17.7

1 BGE's portion of our net periodic pension benefit cost, excluding amounts capitalized, was $5.0 million in 2009 and $4.5 million in 2008.

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

	Quarter Ended March 31,

	2009			2008

	(In millions)
Components of net periodic postretirement benefit cost
Service cost	$	1.6		$	1.7
Interest cost		5.8			6.7
Amortization of transition obligation		0.5			0.5
Recognized net actuarial loss		0.7			1.0
Amortization of prior service cost		(0.8	)		(0.9	)
Amount capitalized as construction cost		(1.5	)		(2.1	)

Net periodic postretirement benefit cost¹	$	6.3		$	6.9

1 BGE's portion of our net periodic postretirement benefit cost, excluding amounts capitalized, was $3.2 million in 2009 and $3.7 million in 2008.

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 $21 million in pension benefit payments for our non-qualified pension plans and approximately $32 million for retiree health and life insurance benefit payments during 2009. We contributed $271 million to our qualified pension plans in March 2009 and an additional $26 million in April 2009.

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.

Constellation Energy

Constellation Energy had bank and other lines of credit under committed unsecured credit facilities totaling $6.2 billion at March 31, 2009 for short-term financial needs. We enter into these facilities to ensure adequate liquidity to support our operations.

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, 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 business.

These facilities can issue letters of credit, commercial paper, if available, and/or cash borrowings up to approximately $6.2 billion as shown below. As of March 31, 2009, we had approximately $3.4 billion in letters of credit issued and borrowed approximately $700 million against those facilities. The weighted-average effective interest rate for this outstanding borrowing was 3.15% at March 31, 2009. At April 30, 2009, we had approximately $3.1 billion in letters of credit issued and borrowed approximately $350 million against those facilities.

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We have also included the pro forma effect on our credit facilities, which are reduced or terminated upon the occurrence of certain events, of closing the transactions contemplated by the Investment Agreement with EDF, which is expected to occur in the third quarter of 2009:

Facility Expiration	Facility Size		Facility Size Upon Completion of the EDF Transaction


	(In billions)
July 2012	$	3.85	$	2.32
November 2009¹		1.23		—
June 2009²		0.60		—
September 2013		0.35		—
December 2009		0.15		—

Total	$	6.18	$	2.32

1 Size of facility may be reduced by proceeds received from certain securities offerings or asset sales.
2 This facility terminated during April 2009 as a result of the EDF put arrangement becoming effective. We discuss this in more detail in the Other Sources of Liquidity section below.

BGE

BGE has a $400.0 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. As of March 31, 2009 and April 30, 2009, BGE had $1.0 million in letters of credit issued under this facility and borrowed $370.0 million against this facility. The weighted-average effective interest rate for this outstanding borrowing was 0.94% at March 31, 2009.

In addition, at March 31, 2009, BGE had no commercial paper outstanding. At April 30, 2009, BGE had $20.0 million in commercial paper outstanding.

Net Available Liquidity

The following table provides a summary of our net available liquidity at March 31, 2009:

	As of March 31, 2009

	Constellation Energy			BGE			Total Consolidated

	(In billions)
Credit facilities	$	6.2		$	0.4		$	6.6
Less: Letters of credit issued		(3.4	)		—			(3.4	)
Less: Cash drawn on credit facilities		(0.7	)		(0.4	)		(1.1	)

Undrawn facilities		2.1			—			2.1
Less: Commercial paper outstanding		—			—			—

Net available facilities		2.1			—			2.1
Add: Cash		0.5			—			0.5

Net available liquidity	$	2.6		$	—		$	2.6

The following table provides our estimated net available liquidity at April 30, 2009:

	As of April 30, 2009

	Constellation Energy			BGE			Total Consolidated

	(In billions)
Credit facilities	$	5.6		$	0.4		$	6.0
Less: Letters of credit issued		(3.1	)		—			(3.1	)
Less: Cash drawn on credit facilities		(0.3	)		(0.4	)		(0.7	)

Undrawn facilities		2.2			—			2.2
Less: Commercial paper outstanding		—			—			—

Net available facilities		2.2			—			2.2
Add: Cash		0.7			—			0.7
Add: EDF put arrangement		1.1			—			1.1

Net available liquidity	$	4.0		$	—		$	4.0

Other Sources of Liquidity

In December 2008, we executed an 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

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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 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 received regulatory approvals and consents for the majority of the assets covered by the put arrangement. As of April 30, 2009, 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 third quarter of 2009, which will increase the net after-tax liquidity to approximately $1.4 billion. The $600 million interim backstop liquidity facility provided by EDF terminated as a result of the put arrangement becoming available.

We are actively seeking 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 other initiatives as discussed in more detail in the Divestitures section beginning on page 14. As of April 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.

Due to the successful execution of the announced divestitures, we estimate our collateral requirements in the event of a downgrade in our credit ratings decreased by $400 million based on current commodity prices. The actual amount of the reduction will be impacted by the timing of the remaining contract assignments for our divested operations.

We believe that we will have sufficient liquidity to meet our ongoing requirements over the next 12 months. However, our liquidity projections include assumptions for commodity price changes, which are subject to significant volatility, and continued changes in our business operations resulting from our strategic initiatives. Also, we are exposed to certain operational risks that could have a significant impact on our liquidity. In addition, if we cannot successfully execute on our strategies, our available liquidity would be negatively affected, which would have a material adverse effect on our results of operations and financial condition.

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 March 31, 2009, the debt to capitalization ratio as defined in the credit agreements was 56%.

Under our $3.85 billion and $1.23 billion credit facilities, we will be required to grant a lien on certain of our generating facilities and pledge our ownership interests in our nuclear business to the lenders upon the earlier of (i) the closing of the Investment Agreement with EDF or (ii) the date on which both the Investment Agreement is terminated and our Standard & Poors (S&P) or Fitch senior unsecured debt credit rating is below BBB- or our Moody's senior unsecured debt credit rating is below Baa3.

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 unsecured debt rating is BBB- or lower and our Moody's senior unsecured debt rating is Baa3 or lower. Compliance with the covenant is not required as of April 30, 2009 as S&P's senior unsecured debt rating is above BBB-.

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 March 31, 2009, the debt to capitalization ratio for BGE as defined in this credit agreement was 53%.

Income Taxes

We compute the income tax benefit (expense) for each quarter based on the estimated annual effective tax rate for the year. The effective tax rate was 66.9% for the quarter ended March 31, 2009 compared to 33.7% for the same period of 2008. The higher effective tax rate for 2009 reflects the impact of unfavorable nondeductible adjustments (primarily related to dividends on the Series B Preferred Stock and the write-off of the unamortized debt discount on the 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 39.5% for the quarter ended March 31, 2009 compared to 31.7% for the same period of 2008. This reflects the impact of the lower 2008 taxable income related to the Maryland settlement agreement, which increased the relative impact of favorable

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permanent tax adjustments on BGE's 2008 effective tax rate.

Unrecognized Tax Benefits

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

At March 31, 2009

	(In millions)
Total unrecognized tax benefits, January 1, 2009	$	189.7
Increases in tax positions related to the current year		1.4
Reductions in tax positions related to prior years		(5.1	)

Total unrecognized tax benefits, March 31, 2009¹	$	186.0

1 BGE's portion of our total unrecognized tax benefits at March 31, 2009 was $4.0 million.

Increases in current year and reductions in prior year tax positions are primarily due to unrecognized tax benefits for repair and depreciation deductions measured at amounts consistent with prior IRS examination results and state income tax accruals.

If the total amount of unrecognized tax benefits of $186.0 million were ultimately realized, our income tax expense would decrease by approximately $159 million. However, the $159 million includes state tax refund claims of approximately $48 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. These state refund claims may be resolved by December 31, 2009. For this reason, we believe it is reasonably possible that reductions to our total unrecognized tax benefits in the range of $40 to $50 million may occur by March 31, 2010, although these reductions are not expected to materially impact income tax expense.

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

	For the Quarter Ended March 31,

	2009			2008

	(In millions)
Interest and penalties recorded as tax (benefit) expense	$	(0.7	)	$	1.0

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

Accrued interest and penalties recognized in our Consolidated Balance Sheets were $9.6 million, of which BGE's portion was $0.8 million at March 31, 2009, and $10.3 million, of which BGE's portion was $0.7 million at December 31, 2008.

Taxes Other Than Income Taxes

BGE collects from certain customers franchise and other taxes 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. The taxes imposed on the customer are accounted for on a net basis, which means we do not recognize revenue and an offsetting tax expense for the taxes collected from customers. The taxes imposed on BGE are accounted for on a gross basis, which means we recognize revenue for the taxes collected from customers. Accordingly, the taxes accounted for on a gross basis are recorded as revenues in the accompanying Consolidated Statements of Income for BGE as follows:

Quarter Ended March 31,	2009		2008


	(In millions)
Taxes other than income taxes included in revenues—BGE	$	21.6	$	20.9

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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 March 31, 2009	Stated Limit


	(In billions)
Constellation Energy guarantees	$	15.4
Merchant energy business guarantees		0.1
BGE guarantees		0.3

Total guarantees	$	15.8

At March 31, 2009, Constellation Energy had a total of $15.8 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 $15.4 billion.

•: Constellation Energy guaranteed a face amount of $14.4 billion on behalf of our merchant energy subsidiaries to allow those 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 $3 billion at March 31, 2009, which represents the total amount the parent company could be required to fund based on March 31, 2009 market prices. For those guarantees related to our derivative liabilities, the fair value of the obligation is recorded in our Consolidated Balance Sheets.
•: Constellation Energy guaranteed $0.9 billion and provides an intercompany credit facility primarily on behalf of our 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.
•: Constellation Energy guaranteed $0.1 billion to its other nonregulated businesses of which $25.0 million was recorded in our Consolidated Balance Sheets at March 31, 2009.

•

Our merchant energy business guaranteed $67.9 million for loans, performance guarantees and other related 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.

In connection with the divestiture of our international commodities operation, we agreed to indemnify the purchaser for potential contingencies arising prior to the sales date. The indemnities are subject to certain monetary and non-monetary limitations, including an overall cap of $75 million, except with respect to a breach of certain warranties in the sales agreement. We believe payment under the indemnifications is remote and have estimated an immaterial liability for the fair value of the indemnifications at inception.

Commitments and Contingencies

We have made substantial commitments in connection with our merchant energy, 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 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 and 2028. In addition, our merchant energy 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 and 2030.

Our merchant energy business also has 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. These contracts expire during 2009, 2010, and 2011, representing 100% of our estimated requirements for residential customers until May 2010, approximately 75% of our estimated requirements from June 2010 to September 2010, approximately 50% of our estimated requirements from October 2010 to May 2011, and approximately 25% of our estimated requirements from June 2011 to September 2011. These contracts are recoverable under the Provider of Last Resort agreement reached with the Maryland PSC.

Our regulated gas business enters into various long-term contracts for the procurement, transportation,

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and storage of gas. Our regulated gas business has gas procurement contracts that expire between 2009 and 2011, and transportation and storage contracts that expire between 2012 and 2027. These contracts are recoverable under BGE's gas cost adjustment clause discussed in Note 1 of our 2008 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 March 31, 2009, the total amount of commitments was $5,690.2 million. These commitments are primarily related to our merchant energy business.

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 2015 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. 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 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. We believe there are meritorious defenses to the remaining claims or requests for relief. However, we are unable at this time to determine the ultimate outcome of these lawsuits or their possible effect on our financial results.

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.

A lead plaintiff has not yet been appointed pursuant to the provisions of the Private Securities Litigation Reform Act and Constellation Energy and other defendants have accordingly not been required to respond to the complaints or take other action to defend the litigation. 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

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filed there. 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 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. A consolidated and amended complaint is expected to be filed on or before May 18, 2009. 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.

In rulings applicable to all but three of the cases, involving claims related to approximately 47 children, the Circuit Court for Baltimore City dismissed with prejudice all claims against BGE and Constellation Energy. 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 remaining 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 hazard. In addition to BGE and Constellation Energy, numerous other parties are defendants in these cases.

Approximately 512 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 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

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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 costs related to this settlement, as well as any clean-up costs. The clean-up costs will not be known until the investigation is closer to completion. However, those costs 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.

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 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 $4.1 million of these costs as of March 31, 2009, resulting in a remaining liability at March 31, 2009 of $3.8 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 in Note 12 of our 2008 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 regulated electric and gas business. Our merchant energy business includes:

•: 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,

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•: 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 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.
•: 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; 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:

•: optimizing the margin on surplus electricity generation and load positions and surplus fuel supply and demand positions,
•: obtaining knowledge of prices and developing expertise in less-liquid markets, and
•: deploying risk capital in an effort to generate returns.

Accounting for Derivative Instruments

The accounting requirements for derivatives are governed by SFAS No. 133 which requires 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. SFAS No. 133 permits several possible accounting treatments for derivatives that meet all of the applicable requirements of that standard. SFAS No. 133 requires mark-to-market 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 prescribed by SFAS No. 133, both at the time of designation and on an ongoing basis. The permissible accounting treatments under SFAS No. 133 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 in Note 1 to our 2008 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.

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Commodity Cash Flow Hedges

Our merchant energy business has 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 through 2016. Our merchant energy business had net unrealized pre-tax losses on these cash-flow hedges recorded in "Accumulated other comprehensive loss" of $2,407.3 million at March 31, 2009 and $2,614.9 million at December 31, 2008.

We expect to reclassify $1,584.3 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 March 31, 2009. However, the actual amount reclassified into earnings could vary from the amounts recorded at March 31, 2009, 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:

•: $166.4 million net pre-tax loss for the quarter ended March 31, 2009, and
•: $0.7 million net pre-tax gain for the quarter ended March 31, 2008.

Substantially all of the pre-tax loss reclassified in 2009 resulted from the sale of a majority of our international commodities operation since 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 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 $12.0 million at both March 31, 2009 and December 31, 2008. We expect to reclassify $1.3 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.

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. The objectives for electing fair value hedging in these situations are to manage our exposure, to optimize the mix of our fixed and floating-rate debt, and to hedge the value of our natural gas in storage.

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 interest rate swaps qualifying as fair value hedges relating to $450 million of our fixed-rate debt 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 $60.8 million at March 31, 2009 and $55.9 million at December 31, 2008 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.

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 March 31,	2009		2008


	(In millions)
Cash-flow hedges	$	29.1	$	(45.1	)
Fair value hedges		23.9		6.5

Total	$	53.0	$	(38.6	)

The ineffectiveness amounts in the table above exclude $30.6 million and $24.7 million of pre-tax losses for the quarters ended March 31, 2009 and 2008, respectively, representing the change in fair value of derivatives that no longer qualify for cash-flow hedge accounting. These

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amounts relate to periods of insufficient price correlation between the hedge and the risk being hedged, but the derivatives qualify for and remain designated as hedges prospectively. In addition, we did not recognize any gain/loss during the quarter ended March 31, 2009 related to the change in fair value for the portion of our fair value hedges excluded from ineffectiveness testing. However, we recognized a $0.2 million pre-tax gain for the quarter ended March 31, 2008 related to the change in value for the portion of our fair value hedges excluded from ineffectiveness testing.

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 SFAS No. 161, Disclosures About Derivative Instruments and Hedging Activities, (SFAS No. 161). SFAS No. 161 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 information about the types of market risks we manage using derivatives. In accordance with SFAS No. 161, this table only includes derivatives and does not reflect the price risks we are hedging that arise from physical assets or nonderivative accrual contracts within our generating plants, customer supply, and global commodities activities.

As discussed more fully following the table, SFAS No. 161 requires us to 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 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 we provide a reconciliation of the gross fair value components to the net fair value amounts as presented in the Fair Value Measurements section of this note and our Consolidated Balance Sheets.

The gross asset and liability values in the table 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 retail gas customer supply operation, economic hedges of accrual activities, the international commodities and Houston-based gas trading operations we are exiting, and trading and risk management 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 March 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	$	2,898.8	$	(4,716.1	)	$	29,270.0	$	(30,162.8	)	$	32,168.8		$	(34,878.9	)
	Gas contracts		2,613.9		(1,977.4	)		12,594.7		(12,198.4	)		15,208.6			(14,175.8	)
	Coal contracts		29.2		(145.1	)		2,650.5		(2,662.2	)		2,679.7			(2,807.3	)
	Other commodity contracts¹		50.1		(24.1	)		377.4		(320.7	)		427.5			(344.8	)
	Interest rate contracts		60.8		—			41.1		(61.0	)		101.9			(61.0	)
	Foreign exchange contracts		—		(5.9	)		59.7		(43.1	)		59.7			(49.0	)

Total gross fair values		$	5,652.8	$	(6,868.6	)	$	44,993.4	$	(45,448.2	)	$	50,646.2		$	(52,316.8	)

	Netting arrangements⁵												(49,411.2	)		49,411.2
	Cash collateral												(196.2	)		629.5

Net fair values												$	1,038.8		$	(2,276.1	)

Net fair value by balance sheet line item:
Accounts receivable²												$	(986.0	)
Derivative assets—current													1,257.3
Derivative assets—noncurrent													767.5
Derivative liabilities—current																(1,180.6	)
Derivative liabilities—noncurrent																(1,095.5	)

Total Derivatives												$	1,038.8		$	(2,276.1	)

1 Other commodity contracts include oil, freight, emission allowances, uranium, 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 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 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 SFAS No. 161 requires separate presentation of 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.

The primary purpose of this table is to disaggregate the risks being managed using derivatives. In order to achieve this objective, SFAS No. 161 requires us to prepare this table 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 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.

Gain and (Loss) Tables

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

•: cash flow hedges,

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•: 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, 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 in Note 1 to our 2008 Annual Report on Form 10-K.

The following table presents 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).

Cash Flow Hedges		Quarter Ended March 31, 2009


Contract type:		Amount of Derivative Gain (Loss) Recorded in AOCI			Statement of Income (Loss) Line Item	Amount of Gain (Loss) Reclassified from AOCI into Earnings			Amount of Derivative Ineffectiveness Gain (Loss) Recorded in Earnings

		(In millions)
Hedges of forecasted sales:					Nonregulated revenues
	Power contracts	$	161.8			$	(92.0	)	$	59.8
	Gas contracts		(31.8	)			(21.4	)		2.1
	Coal contracts		10.0				(229.9	)		—
	Other commodity contracts¹		13.7				(2.8	)		(3.0	)
Foreign exchange contracts			0.3				(0.9	)		—

Total gains (losses)		$	154.0		Total included in nonregulated revenues	$	(347.0	)	$	58.9

Hedges of forecasted purchases:					Fuel and purchased energy expense
	Power contracts		(774.1	)			(426.5	)		(29.3	)
	Gas contracts		175.2				25.9			0.7
	Coal contracts		(84.6	)			(13.3	)		(1.2	)
	Other commodity contracts²		1.8				25.8			—
	Foreign exchange contracts		0.1				0.1			—

Total gains (losses)		$	(681.6	)	Total included in fuel and purchased energy expense	$	(388.0	)	$	(29.8	)

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

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

Grand total gains (losses)		$	(527.9	)		$	(735.1	)	$	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.

Fair Value Hedges			Quarter Ended March 31, 2009


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

			(In millions)
Commodity contracts:
	Gas contracts	Nonregulated revenues	$	40.6	$	(16.7	)
Interest rate contracts		Interest expense		4.9		(4.9	)

Total gains (losses)			$	45.5	$	(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. As discussed more fully in Note 1 to our 2008 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 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			Quarter Ended March 31, 2009


Contract type:		Statement of Income (Loss) Line Item	Amount of Gain (Loss) Recorded in Income on Derivative

			(In millions)
Commodity contracts:
	Power contracts	Nonregulated revenues	$	88.6
	Gas contracts	Nonregulated revenues		(162.6	)
	Coal contracts	Nonregulated revenues		(42.3	)
	Other commodity contracts¹	Nonregulated revenues		(3.9	)
	Coal contracts	Fuel and purchased energy expense		(105.5	)
Other contracts²		Nonregulated revenues		7.3

Total gains (losses)			$	(218.4	)

1 Other commodity contracts include oil, freight, uranium, weather, and emission allowances.
2 Other contracts include interest rate and foreign currency contracts.

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 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

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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 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 information designed to provide insight into the overall volume of our derivatives usage. However, the volumes presented in this table 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, as required by SFAS No. 161. Accordingly, this table does 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 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. It also does 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 activities is reduced by derivatives, and the exposure from our trading activities is managed and controlled through the risk measures discussed above. Therefore, the information in the table 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 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, consistent with the principles of SFAS No. 161.

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 represent 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 below.

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The following table presents the volume of our derivative activities as of March 31, 2009 shown by contractual settlement year.

Quantities¹ Under Derivative Contracts											As of March 31, 2009


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

	(In millions)
Power (MWh)		33.5		15.8		4.3		3.2		3.9		5.5		66.2
Gas (MMBTU)		22.3		50.0		25.7		31.6		14.2		36.0		179.8
Coal (Tons)		7.5		2.1		0.1		0.5		—		—		10.2
Oil (BBL)		0.4		0.1		—		0.1		—		—		0.6
Emission Allowances (Tons)		2.0		—		—		—		—		—		2.0
Interest Rate Contracts	$	1,834.0	$	140.0	$	210.0	$	355.0	$	26.7	$	275.0	$	2,840.7
Foreign Exchange Rate Contracts	$	8.8	$	24.4	$	24.6	$	16.7	$	16.8	$	32.3	$	123.6

1 Amounts in the table 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, uranium, 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 information related to these derivatives. 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 $0.4 billion as of March 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 $2.7 billion after reflecting legally binding master netting agreements and collateral already posted.

Interpretations of SFAS No. 161 indicate that the gross fair value of derivatives in a net liability position that have credit-risk-related contingent features should be disclosed, and we present this amount in the first column in the table 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-binding master netting agreements with the same counterparty, as shown in the second column in the table. 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 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 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.

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Credit-Risk Related Contingent Feature							As of March 31, 2009


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)
$	23.4	$	(20.7	)	$	2.7	$	2.0	$	0.4

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 $629.5 million and letters of credit of $1,411.2 million.
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.

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 in 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 of credit risk to be any single obligor or counterparty whose concentration exceeds 10% of total credit exposure. As of March 31, 2009, no single counterparty concentration comprises more than 10% of the total exposure of the portfolio, and no collection of counterparties based in a single country comprises more than 10% of the total exposure of the portfolio.

Fair Value Measurements

SFAS No. 157, Fair Value Measurements, (SFAS No. 157) defines fair value, establishes a framework for measuring fair value, and requires certain disclosures about 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 at the measurement date (exit price).

SFAS No. 157 also creates a fair value hierarchy that prioritizes 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.
•: 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 fair value of our assets and liabilities using unadjusted quoted prices in active markets (Level 1) or pricing inputs that are observable (Level 2) whenever that information is available. We use unobservable inputs (Level 3) to estimate fair value only when relevant observable inputs are not available.

We classify assets and liabilities within the fair value hierarchy based on the lowest level of input that is significant to the fair value measurement of each individual asset and liability taken 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 or liability. We primarily

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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 in pricing the asset or liability.

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 the Financing Activities section.

Recurring Measurements

BGE's assets and liabilities measured at fair value on a recurring basis are immaterial. Our merchant energy business segment's assets and liabilities measured at fair value on a recurring basis consist of the following:

			As of March 31, 2009

			Assets			Liabilities

			(In millions)
Cash equivalents			$	376.9		$	—
Debt and equity securities				1,039.9			—
Derivative instruments:
	Classified as derivative assets and liabilities:
		Current		1,257.3			(1,180.6	)
		Noncurrent		767.5			(1,095.5	)

		Total classified as derivative assets and liabilities		2,024.8			(2,276.1	)
	Classified as accounts receivable*			(986.0	)		—

	Total derivative instruments			1,038.8			(2,276.1	)

Total recurring fair value measurements			$	2,455.6		$	(2,276.1	)

* 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" in the Consolidated Balance Sheets. Debt and equity securities 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 on a gross contract-by-contract basis as required by SFAS No. 157. A primary focus of SFAS No. 157 is the fair value hierarchy that provides information about how fair value measurements are determined. SFAS No. 157 requires each individual asset or liability that is remeasured at fair value on a recurring basis to be presented in this table and classified, in its entirety, within the appropriate level in the fair value hierarchy. 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 March 31, 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 March 31, 2009		Level 1			Level 2			Level 3			Netting and Cash Collateral*			Total Net Fair Value


		(In millions)
Cash equivalents		$	376.9		$	—		$	—		$	—		$	376.9
Debt and equity securities			298.1			741.8			—			—			1,039.9
Derivative assets			602.2			45,400.7			4,643.3			(49,607.4	)		1,038.8
Derivative liabilities			(706.1	)		(46,692.3	)		(4,918.4	)		50,040.7			(2,276.1	)

	Net derivative position		(103.9	)		(1,291.6	)		(275.1	)		433.3			(1,237.3	)

Total		$	571.1		$	(549.8	)	$	(275.1	)	$	433.3		$	179.5

* 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 March 31, 2009, we included $196.2 million of cash collateral held and $629.5 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 amounts in the table above are unrelated to the existence or level of actual market or credit risk from our operations. Thus, the gross components of the derivatives amounts in this table increased from the corresponding amounts as of December 31, 2008, due to substantial decreases in commodity prices and the execution of additional contracts to transfer portions of our operations and reduce risk in our activities. These increases occurred despite reductions in the overall level of our positions and risk during the quarter. We describe the primary factors that change the gross components below.

SFAS No. 157 requires us to prepare this table by separating each individual derivative contract that is in the money from each contract that is out of the money. It also requires us to ignore master netting agreements and collateral for our derivatives. As a result, the gross "asset" and "liability" amounts under 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 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 SFAS No. 157 requires separate presentation of contracts that are in the money from those that are out of the money. As a result, even 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 comprised of exchange traded money market funds and money market mutual funds. These instruments are valued based upon unadjusted quoted prices in active markets and are classified within Level 1.

Debt and 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 unadjusted quoted prices in active markets and are classified within Level 1. Our other marketable securities consist of publicly traded individual securities, which are valued based on unadjusted quoted prices in active markets and are classified within Level 1. Nuclear decommissioning trust funds consist of a number of different types of securities, including the following:

•: publicly traded individual securities 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

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•: commingled funds 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 unadjusted quoted prices in active markets 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.

The following table sets forth a reconciliation of changes in Level 3 fair value measurements:

		Quarter ended March 31, 2009			Quarter ended March 31, 2008


		(In millions)
Balance at beginning of period		$	37.0		$	(147.1	)
Realized and unrealized gains (losses):
	Recorded in income		(147.5	)		(15.1	)
	Recorded in other comprehensive (loss) income		(90.7	)		175.9
Purchases, sales, issuances, and settlements			1.9			31.1
Transfers into and out of Level 3			(75.8	)		355.6

Balance at end of period		$	(275.1	)	$	400.4

Change in unrealized gains recorded in income relating to derivatives still held at end of period		$	164.7		$	(34.8	)

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.

Nonrecurring Measurements

The table below sets forth by level within the fair value hierarchy our assets and liabilities that were measured at fair value on a nonrecurring basis during the quarter ended March 31, 2009:

	Fair Value at March 31, 2009		Level 1		Level 2		Level 3		Losses for the quarter ended March 31, 2009


	(In millions)
Equity method investment	$	10.0	$	10.0	$	—	$	—	$	14.0

As described in more detail on page 13, during the first quarter of 2009, we recorded an other-than-temporary impairment charge of $14.0 million on our equity method investment in Constellation Energy Partners LLC (CEP). The fair value of CEP is a level 1 measurement because CEP is a publicly-traded stock on the New York Stock Exchange and,

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therefore, the fair value is based on a quoted price in an active market.

Accounting Standards Issued

FSP SFAS No. 115-2 and SFAS No. 124-2

In April 2009, the FASB issued Staff Position (FSP) SFAS No. 115-2 and SFAS No. 124-2, Recognition and Presentation of Other-Than-Temporary Impairments, which is effective for interim periods ending after June 15, 2009. The FSP amends the other-than-temporary guidance for debt securities and expands 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 will likely not affect CEG's policy of recognizing impairments for any of these investments for which fair value declines below our book value. The FSP also amends SFAS No. 115 and FSP SFAS No. 115-1 and No. 124-1 to require disclosures regarding available-for-sale securities in interim financial statements as well as in annual financial statements. We are currently evaluating the impact of the FSP, but, we do not expect the adoption of this standard to have a material impact on our, or BGE's, financial results.

FSP SFAS No. 107-1 and APB No. 28-1

In April 2009, the FASB issued FSP SFAS No. 107-1 and APB No. 28-1, Interim Disclosures about Fair Value of Financial Instruments, which is effective for interim periods ending after June 15, 2009. The FSP amends SFAS No. 107 to require disclosures about fair value of financial instruments in interim financial statements as well as in annual financial statements. We do not expect the adoption of this standard to have a material impact on our, or BGE's, financial results because it only provides for additional disclosure.

FSP SFAS No. 157-4

In April 2009, the FASB issued FSP SFAS No. 157-4, 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, which is effective for interim periods ending after June 15, 2009. The FSP provides additional guidance for estimating fair value in accordance with SFAS No. 157 when the volume and level of activity for the asset or liability have decreased. The FSP also includes guidance on identifying circumstances that indicate a transaction is not orderly. Finally, the FSP expands the disclosure requirements in SFAS No. 157 to include further disaggregation in the tabular disclosures. We are currently evaluating the impact of the FSP, but, we do not expect the adoption of this standard to have a material impact on our, or BGE's, financial results.

Accounting Standards Adopted

SFAS No. 160

In December 2007, the FASB issued SFAS No. 160, Noncontrolling Interests in Consolidated Financial Statements, an amendment of ARB No. 51. SFAS No. 160 provides that a noncontrolling interest in a subsidiary is an ownership interest in the consolidated entity that should be reported as 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.

SFAS No. 160 requires that companies:

•: 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. Specifically, we:

•: reclassified $190.0 million of BGE preference stock to a separate line within total equity,
•: reclassified approximately $20 million of noncontrolling interests to a separate line within total equity,
•: recorded $3.8 million of income attributable to our noncontrolling interests and BGE preference stock dividends in a separate line on the Consolidated Statement of Income (Loss) after net income in order to arrive at net (loss) income available to common stock,
•: recorded $3.8 million of comprehensive income attributable to noncontrolling interests in a separate line on the Consolidated Statement of Comprehensive Income (Loss), and
•: recorded $3.3 million of "BGE preference stock dividends paid" as a separate line in our Consolidated Statement of Cash Flows.

SFAS No. 161

In March 2008, the FASB issued SFAS No. 161. SFAS No. 161 requires entities to provide expanded disclosure about derivative instruments and hedging activities, but does not change the accounting for derivatives. We adopted SFAS

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No. 161 on January 1, 2009 and provide these additional disclosures beginning on page 28.

FSP SFAS No. 157-2

In February 2008, the FASB issued FSP SFAS No. 157-2, Effective Date of FASB Statement No. 157. FSP SFAS No. 157-2 delayed the effective date of SFAS No. 157 for many nonfinancial assets and liabilities, including asset retirement obligations, long-lived assets, and goodwill, to fiscal years beginning after November 15, 2008. Prospectively, we will disclose subsequent measurements of nonfinancial assets and liabilities at fair value as part of our SFAS No. 157 footnote. We adopted FSP SFAS No. 157-2 on January 1, 2009 with no effect on our, or BGE's, financial results. See page 34 for our disclosures about fair value measurements.

EITF No. 08-5

In September 2008, the FASB ratified EITF No. 08-5, Third Party Credit Enhancements. EITF No. 08-5 clarifies that an entity shall not include the effects of a third party credit enhancement in the fair value measurement of a liability. We adopted EITF No. 08-5 on January 1, 2009 and recorded a reduction in our derivative liability of approximately $4 million.

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 business will supply a portion of BGE's market-based standard offer service obligation to residential electric customers through September 30, 2011.

The cost of BGE's purchased energy from nonregulated subsidiaries of Constellation Energy to meet its standard offer service obligation was $204.3 million for the quarter ended March 31, 2009 compared to $271.3 million for the same period in 2008.

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. These costs were approximately $29.6 million for the quarter ended March 31, 2009 compared to $35.1 million for the quarter ended March 31, 2008.

BGE—Balance Sheet

BGE participates 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 $387.7 million at March 31, 2009 and had invested $148.8 million at December 31, 2008.

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

We believe our allocation methods are reasonable and approximate the costs that would be charged to unaffiliated entities.

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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 and Baltimore Gas and Electric Company (BGE). We describe our operating segments in the Notes to Consolidated Financial Statements beginning on page 16.

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 in Item 1—Business section of our 2008 Annual Report on Form 10-K and we discuss the risks affecting our business in Item 1A. Risk Factors section of our 2008 Annual Report on Form 10-K.

Our 2008 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, evaluation of assets for impairment and other than temporary decline in value, and asset retirement obligations.

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, 2009 and 2008. 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 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.
•: 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 the Forward Looking Statements section on page 68 and in Item 1A. Risk Factors section of our 2008 Annual Report on Form 10-K. We discuss our market risks in the Risk Management section beginning on page 62.

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 the Financial Condition section and our customer (counterparty) credit and other risks in more detail in the Risk Management section.

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

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Environmental Matters

Air Quality

Capital Expenditures

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 $300 million in 2009, $35 million in 2010, $15 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.

Accounting Standards Issued and Adopted

We discuss recently issued and adopted accounting standards in the Accounting Standards Issued and Accounting Standards Adopted sections of the Notes to Consolidated Financial Statements beginning on page 38.

Events of 2009

Divestitures

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. Additionally, we entered into an agreement to sell an additional international holding, which is expected to close in the second quarter of 2009.

In February 2009, we entered into a definitive agreement to sell our Houston-based 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.

We discuss these divestitures in more detail in the Notes to Consolidated Financial Statements beginning on page 14.

Merger Termination and Strategic Alternatives Costs

During the quarter ended March 31, 2009, we incurred merger termination and strategic alternative costs related to the terminated merger with MidAmerican Energy Holdings Company (MidAmerican), the conversion of our Series A Preferred Stock, the transactions related to EDF Group and related entities (EDF), and other strategic alternatives costs. We discuss costs related to the mergers and strategic alternatives in more detail on page 11 in Notes to Consolidated Financial Statements.

Impairment losses and other costs

During the quarter ended March 31, 2009, we recorded impairment losses and other costs on certain of our investments in equity securities and other assets. We discuss these charges in more detail in the Notes to Consolidated Financial Statements on page 13.

Workforce Reduction Costs

During the quarter ended March 31, 2009, we incurred workforce reduction costs primarily related to the divestitures of a majority of our international commodities operation as well as some smaller restructurings elsewhere in our organization. We recognized a $10.8 million pre-tax charge in 2009 related to the elimination of approximately 180 positions. We expect all of these restructurings will be completed within the next 12 months. We discuss our workforce reduction costs in more detail in the Notes to Consolidated Financial Statements beginning on page 13.

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Results of Operations for the Quarter Ended March 31, 2009 Compared with the Same Period of 2008

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 income and expense, fixed charges, and income taxes are discussed, as necessary, in the aggregate for all segments in the Consolidated Nonoperating Income and Expenses section on page 54.

Overview

Results

		Quarter Ended March 31,

		2009			2008

		(In millions, after-tax)
Merchant energy		$	(202.7	)	$	72.7
Regulated electric			45.4			36.2
Regulated gas			39.6			40.2
Other nonregulated			(2.0	)		0.3

Net (Loss) Income		$	(119.7	)	$	149.4

Net (Loss) Income attributable to common stock		$	(123.5	)	$	145.7

Other Items Included in Operations (after-tax):
	Non-qualifying hedges	$	—		$	(34.6	)
	International commodities operation and gas trading operation¹		(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	)		(3.9	)
	Workforce reduction costs		(4.2	)		—
	Credit facility amendment fees		(3.7	)		—

Total Other Items		$	(269.3	)	$	(38.5	)

Change from prior year		$	(230.8	)

1 These amounts include the loss on sale of the international commodities 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 are divesting.

Quarter Ended March 31, 2009

Our total net loss attributable to common stock for the quarter ended March 31, 2009 was unfavorable compared to net income for the same period of 2008 by $269.2 million, or $1.43 per share, primarily due to the following:

	2009 vs. 2008


	(in millions, after-tax)
Generation gross margin	$	7
Customer Supply gross margin		38
Global Commodities gross margin		(150	)
Hedge ineffectiveness		51
Credit loss—coal supplier bankruptcy		33
Merchant interest expense		(28	)
Regulated businesses		9
Other nonregulated businesses		(2	)
Total change in Other Items included in operations per Overview—Results table		(231	)
All other changes		4

Total Change	$	(269	)

In the following sections, we discuss our net 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.

Our merchant energy business focuses on delivery of physical, customer-oriented products to producers and consumers, manages the risk and optimizes the value of our owned generation assets and customer supply activities, and uses our portfolio management and trading capabilities both to manage risk and to deploy risk capital.

We are continuing to assess the ongoing capital requirements of the merchant energy business, including evaluating the proper size of our Customer Supply and Global Commodities operations, and we are continuing to implement various strategic initiatives for our Global Commodities operation. We discuss our strategy in more detail in the Strategy section of our 2008 Annual Report on Form 10-K.

While we have completed the sale of a majority of our international commodities operation and our gas trading operation, the execution of our strategy in the future will be affected by continued instability in financial, credit, and commodities markets. Execution of our goals could have a

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substantial effect on the nature and mix of our business activities. In particular, upon closing the transactions contemplated by our Investment Agreement with EDF, we expect that our subsidiary that owns our nuclear generation assets will be deconsolidated. 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 to Consolidated Financial Statements beginning on page 14.

We record merchant energy 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 the Critical Accounting Policies section and in Note 1 of our 2008 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 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 the Mark-to-Market and Risk Management sections.

Results

		Quarter Ended March 31,

		2009			2008

		(In millions)
Revenues		$	3,279.5		$	3,947.0
Fuel and purchased energy expenses			(2,694.8	)		(3,298.9	)
Operating expenses			(434.6	)		(429.8	)
Merger and strategic alternatives costs			(42.3	)		—
Impairment losses and other costs			(28.6	)		—
Workforce reduction costs			(10.8	)		—
Depreciation, depletion, and amortization			(63.6	)		(71.1	)
Accretion of asset retirement obligations			(17.9	)		(16.6	)
Taxes other than income taxes			(29.4	)		(27.7	)
(Loss) gain on divestitures			(334.5	)		15.0

Income from Operations		$	(377.0	)	$	117.9

Net (Loss) Income		$	(202.7	)	$	72.7

Net (Loss) Income attributable to common stock		$	(203.2	)	$	72.2

Other Items Included in Operations (after-tax):
	Non-qualifying hedges	$	—		$	(34.6	)
	International commodities operation and gas trading operation¹		(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	)		(3.9	)
	Workforce reduction costs		(4.2	)		—
	Credit facility amendment fees		(3.7	)		—

Total Other Items		$	(269.3	)	$	(38.5	)

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 17 provides a reconciliation of operating results by segment to our Consolidated Financial Statements.

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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 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 revenues decreased $667.5 million in the first quarter of 2009 compared to 2008, primarily due to the following:

	2009 vs. 2008


	(In millions)
Change in Global Commodities mark-to-market revenues due to favorable changes in power and gas prices	$	25
Decrease in contract prices and volume of business primarily related to our international coal and freight operation, which we have divested		(409	)
Increase in contract prices and volume related to our domestic coal operation		87
Realization of lower prices and volume of business at our gas trading operation and absence of revenue due to the sales of certain of our upstream gas properties in 2008		(90	)
Realization of lower volumes on wholesale and retail load at our Global Commodities and Customer Supply operations, partially offset by higher contract prices		(267	)
All other		(14	)

Total decrease in merchant revenues	$	(668	)

Fuel and Purchased Energy Expenses

Our merchant energy fuel and purchased energy expenses decreased $604.1 million in the first quarter of 2009 compared to 2008, primarily due to the following:

	2009 vs. 2008


	(In millions)
Increase in Global Commodities mark-to-market expenses related to international coal purchase contracts due to decreasing prices, which we have divested	$	169
Decrease in contract prices and volume of business primarily related to our international coal and freight operation, which we have divested		(333	)
Increase in contract prices and volume related to our domestic coal operation		80
Realization of lower volumes at our gas trading operations		(35	)
Realization of lower contract prices and volumes on wholesale and retail purchases at our Global Commodities and Customer Supply operations		(508	)
All other		23

Total decrease in merchant energy fuel and purchased energy expenses	$	(604	)

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.

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•: 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, international coal and freight assets, 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.

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

		Quarter Ended March 31,

		2009						2008

		(Dollar amounts in millions)
					% of Total					% of Total
Gross Margin:
	Generation	$	532			91	%	$	498		77	%
	Customer Supply		169			29			99		15
	Global Commodities		(116	)		(20	)		51		8

	Total	$	585			100	%	$	648		100	%

Generation

The $34 million increase in generation gross margin during the quarter ended March 31, 2009 compared to the same period of 2008 is primarily due to the following:

•: $35 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 the first quarter of 2009), and
•: $25 million due to shorter planned and unplanned outages at our nuclear and fossil generating plants.

These increases were partially offset by $26 million of lower earnings primarily related to our investments in power projects.

Customer Supply

The $70 million increase in customer supply gross margin during the quarter ended March 31, 2009 compared to the same period of 2008 is primarily due to:

•: $60 million of higher realization of contracts executed in prior periods and new business realized during the first quarter of 2009 primarily at our wholesale power operation,
•: $30 million of lower costs due to higher customer retention and from managing variable load risk associated with wholesale and retail power primarily due to less extreme weather during the quarter ended March 31, 2009, and
•: $27 million of higher gross margin primarily related to higher prices in our retail gas operation.

These increases were partially offset by $47 million of lower mark-to-market results in our retail gas operation. We discuss these transactions in more detail in the Mark-to-Market section beginning on page 46.

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. It also deploys risk capital in traded energy markets.
•: 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).
•: Energy Investments—investments in energy assets that primarily include natural gas properties and a

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joint interest in an entity that owns dry bulk cargo vessels.

The $167 million decrease in gross margin from our Global Commodities activities during the quarter ended March 31, 2009 compared to the same period of 2008 is primarily due to:

•: $155 million of lower gross margin related to our structured products portfolio primarily due to the absence of in-the-money energy purchase contracts that were terminated in the quarter ended March 31, 2008 for an upfront cash payment and the cancellation of future performance obligation, which reduced our performance and credit risk exposures, and
•: $34 million of lower gross margin related to our energy investments portfolio primarily related to the absence of gross margin due to the divestiture of certain of our upstream gas assets in 2008.

These decreases in Global Commodities gross margin were partially offset by $22 million of higher gross margin related to our portfolio management and trading operation. The increase in portfolio management and trading is due to the following factors:

•: $139 million of higher gross margin related to portfolio management of positions arising from hedges with our Generation and Customer Supply activities due to the favorable impact of changes in prices of power, natural gas, and coal on those positions,
•: $86 million related to lower losses recognized on hedges due to ineffectiveness, and certain cash-flow hedges that no longer qualified for hedge accounting during the quarter,
•: $80 million of higher gross margin at our international coal and freight operations primarily due to decreasing freight costs, excluding the impact of hedge ineffectiveness, and
•: $55 million loss related to the bankruptcy of one of our domestic coal suppliers that occurred during the first quarter 2008.

These increases were mostly offset by the following:

•: In connection with the closing of the sale of our international commodities operation, we reclassified an $166 million loss from accumulated other comprehensive loss to earnings as a result of hedged transactions that were probable of not occurring by the end of the specified contract period,
•: $158 million of lower earnings related to our portfolio of contracts subject to mark-to-market accounting, including lower earnings of approximately $60 million due to the absence of origination gains recognized in the first quarter 2008. We discuss these transactions in more detail in the Mark-to-Market section below, and
•: $14 million of lower gross margin due to a write-down of emissions inventory as a result of market prices declining below our cost.

Mark-to-Market

Mark-to-market results include net gains and losses from origination, trading, and risk management 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 the Critical Accounting Policies section of our 2008 Annual Report on Form 10-K.

The nature of our operations and the use of mark-to-market accounting for certain activities creates 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 the Risk Management section beginning on page 62. 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, 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 liquidity requirements. These actions may impact the future results of the merchant energy 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 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.

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

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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. 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 March 31,

			2009			2008

			(In millions)
Unrealized mark-to-market results
	Origination gains		$	—		$	59.7
	Risk management and trading—mark-to-market
		Unrealized changes in fair value		(194.5	)		(49.6	)
		Changes in valuation techniques		—			—
		Reclassification of settled contracts to realized		(316.7	)		32.6

	Total risk management and trading—mark-to-market			(511.2	)		(17.0	)

Total unrealized mark-to-market*				(511.2	)		42.7
Realized mark-to-market				316.7			(32.6	)

Total mark-to-market results**			$	(194.5	)	$	10.1

* 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 decreased $204.6 million during the quarter ended March 31, 2009 compared to the same period of 2008 primarily due to unrealized changes in fair value. The period-to-period variance in unrealized changes in fair value was primarily due to higher unrealized risk management and trading losses of $144.9 million and the decrease in origination gains of $59.7 million. We discuss origination gains below.

The increase in risk management and trading losses of $144.9 million was primarily due to:

•: $93 million of losses primarily due to a less favorable price environment related to our domestic coal portfolio,
•: $55 million of losses primarily due to unfavorable changes in prices related to our natural gas portfolio,
•: $28 million of losses on open positions in our power and transmission risk management and trading activities in the PJM, Northeast, and ERCOT regions primarily resulting from an unfavorable price environment, and
•: $26 million of lower gains related to our emissions trading activities primarily due to less favorable price changes.

These unfavorable impacts were partially offset by the absence of $57 million of prior year losses related to certain economic hedges, primarily used to manage our gas transportation and storage and freight activities, that do not qualify for or are not designated as cash-flow hedges.

We did not record any origination gains during the three months ended March 31, 2009. During the three months ended March 31, 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 under Statement of Financial Accounting Standard (SFAS) No. 133, Accounting for Derivative Instruments and Hedging Activities, as amended. 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.

Derivative Assets and Liabilities

Derivative assets and liabilities consisted of the following:

	March 31, 2009			December 31, 2008


	(In millions)
Current Assets	$	1,257.3		$	1,465.0
Noncurrent Assets		767.5			851.8

Total Assets		2,024.8			2,316.8

Current Liabilities		1,180.6			1,241.8
Noncurrent Liabilities		1,095.5			1,115.0

Total Liabilities		2,276.1			2,356.8

Net Derivative Position	$	(251.3	)	$	(40.0	)

Composition of net derivative position:
Hedges	$	(1,721.0	)	$	(1,837.6	)
Mark-to-market		1,036.4			1,485.9
Net cash collateral included in derivative balances		433.3			311.7

Net Derivative Position	$	(251.3	)	$	(40.0	)

As discussed in the Critical Accounting Policies section of our 2008 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

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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 in our net derivative liability subject to hedge accounting since December 31, 2008 of $116.6 million was due primarily to $415 million of realization of out-of-the-money cash-flow hedges, partially offset by $298 million of increases on our out-of-the-money cash-flow hedge positions primarily related to decreases in power, natural gas, and coal prices during the first quarter of 2009.

The following are the primary sources of the change in our net derivative asset subject to mark-to-market accounting during the quarter ended March 31, 2008:



		(In millions)
Fair value beginning of period					$	1,485.9
Changes in fair value recorded in earnings
	Origination gains	$	—
	Unrealized changes in fair value		(194.5	)
	Changes in valuation techniques		—
	Reclassification of settled contracts to realized		(316.7	)

Total changes in fair value						(511.2	)
Changes in value of exchange-listed futures and options						404.5
Net change in premiums on options						(6.6	)
Contracts acquired						80.5
Dedesignated contracts and other changes in fair value						(416.7	)

Fair value at end of period					$	1,036.4

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 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 quarter ended March 31, 2009 related to the divestiture of our international commodities operation in order to transfer risk and reward to the buyer. We discuss this divestiture in more detail beginning on page 14 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 and those derivative contracts that did not meet the qualifications of cash flow hedge accounting. In the quarter ended March 31, 2009, substantially all of the activity related to dedesignations in connection with the strategic objective of restructuring and reducing the risk of our portfolio.

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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 established by SFAS No. 157 are as follows as of March 31, 2009:

	Settlement Term

	2009		2010			2011			2012			2013			2014			Thereafter			Fair Value

	(In millions)
Level 1	$	66.1	$	26.4		$	5.8		$	0.7		$	0.6		$	—		$	—		$	99.6
Level 2		436.3		(10.8	)		326.2			130.9			(17.5	)		(1.5	)		1.7			865.3
Level 3		278.9		164.3			(192.2	)		(167.4	)		(13.2	)		3.1			(2.0	)		71.5

Total net derivative asset subject to mark-to-market accounting	$	781.3	$	179.9		$	139.8		$	(35.8	)	$	(30.1	)	$	1.6		$	(0.3	)	$	1,036.4

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 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, 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.

Impairment losses and Other Costs

Our impairment losses and other costs are discussed in more detail on page 13 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 beginning on page 13 in Notes to Consolidated Financial Statements.

Merger Termination and Strategic Alternatives Costs

We discuss costs related to the mergers and strategic alternatives in more detail on page 11 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 business incurred lower depreciation, depletion and amortization expenses of $7.5 million during the quarter ended March 31, 2009 compared to the same period of 2008 primarily due to the absence of depletion expenses as a result of divestitures made in 2008 in our upstream gas operations.

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Regulated Electric Business

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

Results

	Quarter Ended March 31,

	2009			2008

	(In millions)
Revenues	$	806.8		$	709.4
Electricity purchased for resale expenses		(525.2	)		(455.3	)
Operations and maintenance expenses		(91.1	)		(94.7	)
Depreciation and amortization		(55.5	)		(50.8	)
Taxes other than income taxes		(37.2	)		(36.2	)

Income from Operations	$	97.8		$	72.4

Net Income	$	45.4		$	36.2

Net income attributable to common stock	$	42.9		$	33.7

Other Items Included in Operations (after-tax):
Effective tax rate impact of Maryland settlement agreement	$	—		$	3.0

Net income attributable to common stock from the regulated electric business increased $9.2 million during the quarter ended March 31, 2009 compared to the same period in 2008, primarily due to an increase in revenues less electricity purchased for resale expenses of $16.7 million after-tax and decreased operations and maintenance expenses of $2.2 million after-tax, partially offset by the absence of the impact of reduced earnings from the Maryland settlement agreement on our effective tax rate of $3.0 million and increased depreciation and amortization of $2.9 million after-tax.

Electric Revenues

The changes in electric revenues during the quarter ended March 31, 2009 compared to the same period of 2008 were caused by:

	Quarter Ended March 31, 2009 vs. 2008


	(In millions)
Distribution volumes	$	4.1
Nuclear decommissioning charges		4.8
Smart energy savers program surcharges		5.3
Revenue decoupling		2.1
Standard offer service		69.5
Rate stabilization recovery		1.9
Financing credits		1.0
Senate Bill 1 credits		5.2

Total change in electric revenues from electric system sales		93.9
Other		3.5

Total change in electric revenues	$	97.4

Distribution Volumes

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

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




Residential	(1.7	)%
Commercial	5.2
Industrial	(10.4	)

During the quarter ended March 31, 2009, we distributed less electricity to residential customers compared to the same period of 2008 mostly due to decreased usage per customer, partially offset by colder weather and an increased number of customers. We distributed more electricity to commercial customers compared to the same period of 2008 mostly due to increased usage per customer, colder weather, and an increased number of customers. We distributed less electricity to industrial customers mostly due to decreased usage per customer and a decreased number of customers.

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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 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.

Revenue Decoupling

Beginning in 2008, the Maryland PSC allows us to record a monthly adjustment to our electric distribution revenues from residential and small commercial customers to eliminate the effect of abnormal weather and usage patterns per customer on our electric distribution volumes. Beginning in February 2009, the Maryland PSC allows us to record a monthly adjustment to our electric distribution revenues from the majority of our large commercial and industrial customers to eliminate the effect of abnormal weather and usage patterns per customer on our electric distribution volumes. This means our monthly electric distribution revenues for these customers are based on weather and usage that is considered "normal" for the month. Therefore, while these revenues are affected by customer growth, they will not be affected by actual weather or usage conditions.

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 Item 7. Management's Discussion and Analysis—Business Environment—Regulation—Maryland—Senate Bills 1 and 400 section of our 2008 Annual Report on Form 10-K.

Standard offer service revenues increased during the quarter ended March 31, 2009 compared to the same period of 2008 mostly due to an increase in the standard offer service rates and higher 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. 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 over a 21-month period that began April 1, 2008 and ends on December 31, 2009. The recovery of the first rate stabilization plan will occur over approximately ten years.

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.

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 SOS 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 quarter ended March 31, 2009 compared to the same period in 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, partially offset by lower distribution volumes.

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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 March 31,

	2009		2008

	(In millions)
Actual costs	$	509.4	$	441.2
Recovery under rate stabilization plan		15.8		14.1

Electricity purchased for resale expenses	$	525.2	$	455.3

Actual Costs

BGE's actual costs for electricity purchased for resale increased $68.2 million during the quarter ended March 31, 2009 compared to the same period of 2008 primarily due to higher contract prices to purchase electricity for our customers and higher volumes.

Recovery under Rate Stabilization Plan

In late June 2007, we began recovering previously deferred amounts from customers. We recovered $15.8 million during the quarter ended March 31, 2009 in deferred electricity purchased for resale expenses. Of the $15.8 million recovered, $14.6 million secures 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 decreased $3.6 million in the quarter ended March 31, 2009 compared to the same period in 2008 primarily due to $4.3 million in lower labor and benefit costs and the absence of $1.6 million in incremental distribution service restoration expenses associated with 2008 storms, partially offset by increased uncollectible accounts receivable expense of $3.7 million.

Electric Depreciation and Amortization

Regulated electric depreciation and amortization expense increased $4.7 million during the quarter ended March 31, 2009 compared to the same period in 2008, primarily due to $7.9 million in increased amortization expense associated with the smart energy savers programs and additional property placed in service in 2009, partially offset by 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.

Regulated Gas Business

Our regulated gas business is discussed in detail in Item 1. Business—Gas Business section of our 2008 Annual Report on Form 10-K.

Results

	Quarter Ended March 31,

	2009			2008

	(In millions)
Revenues	$	386.9		$	396.4
Gas purchased for resale expenses		(258.1	)		(270.0	)
Operations and maintenance expenses		(35.9	)		(38.9	)
Depreciation and amortization		(11.4	)		(11.9	)
Taxes other than income taxes		(10.4	)		(10.4	)

Income from operations	$	71.1		$	65.2

Net Income	$	39.6		$	40.2

Net Income attributable to common stock	$	38.8		$	39.4

Other Items Included in Operations (after-tax):
Effective tax rate impact of Maryland settlement agreement	$	—		$	3.6

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Gas Revenues

The changes in gas revenues during the quarter ended March 31, 2009 compared to the same period of 2008 were caused by:

	Quarter Ended March 31, 2009 vs. 2008


	(In millions)
Distribution volumes	$	6.3
Conservation surcharge		0.5
Gas revenue decoupling		(6.0	)
Gas cost adjustments		14.9

Total change in gas revenues from gas system sales		15.7
Off-system sales		(24.5	)
Other		(0.7	)

Total change in gas revenues	$	(9.5	)

Distribution Volumes

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




Residential	7.8	%
Commercial	2.4
Industrial	1.7

During the quarter ended March 31, 2009, we distributed more gas to residential and commercial customers compared to the same period of 2008 mostly due to colder weather and an increased number of customers, partially offset by decreased usage per customer. We distributed more gas to industrial customers mostly due to increased usage per 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.

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. This means our monthly gas distribution revenues are based on weather and usage that is considered "normal" for the month. Therefore, while these revenues are affected by customer growth, they will not be affected by actual weather or usage conditions.

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 in Note 1 of our 2008 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 are included in the gas distribution volume revenues.

Gas cost adjustment revenues increased $14.9 million during the quarter ended March 31, 2009 compared to the same period of 2008 because we sold more gas, partially offset by lower rates.

Off-System Sales

Off-system 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 $24.5 million during the quarter ended March 31, 2009 compared to the same period of 2008 because we sold less gas at lower prices.

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 sales. These costs do not include the cost of gas purchased by delivery service only customers.

Gas costs decreased $11.9 million during the quarter ended March 31, 2009 compared to the same period of 2008 primarily due to lower prices, partially offset by more gas purchased.

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Gas Operations and Maintenance Expenses

Regulated gas operation and maintenance expenses decreased $3.0 million in the quarter ended March 31, 2009 compared to the same period in 2008, primarily due to $3.6 million in lower labor and benefit costs, partially offset by increased uncollectible accounts receivable expense of $1.5 million.

Other Nonregulated Businesses

Results

	Quarter Ended March 31,

	2009			2008

	(In millions)
Revenues	$	57.3		$	59.2
Operating expenses		(42.3	)		(45.4	)
Depreciation and amortization		(18.1	)		(14.5	)
Taxes other than income taxes		(0.8	)		(0.5	)

Loss from Operations	$	(3.9	)	$	(1.2	)

Net (Loss) Income	$	(2.0	)	$	0.3

Net (Loss) Income attributable to common stock	$	(2.0	)	$	0.4

The $2.4 million decrease to a net loss attributable to common stock of $2.0 million during the quarter ended March 31, 2009 compared to the net income attributable to common stock for the quarter ended March 31, 2008, is primarily due to increased depreciation and amortization expense as a result of increased property additions during 2008.

Consolidated Nonoperating Income and Expenses

Other (Expense) Income

In the first quarter of 2009, we had other expenses of $27.5 million and, in the first quarter of 2008, we had other income of $42.7 million. The $70.2 million decrease in 2009 compared to 2008 is mostly due to an increase in other-than-temporary impairment charges related to our nuclear decommissioning trust fund assets of $52.7 million.

Fixed Charges

Fixed charges increased $50.6 million during the quarter ended March 31, 2009 compared to the same period of 2008 mostly due to 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.

Income Taxes

Income tax expense decreased $318.1 million during the quarter ended March 31, 2009 compared to the same period of 2008 mostly due to a loss before income taxes in 2009 compared to income before income taxes in 2008. Additionally, a higher effective tax rate in 2009 decreased income tax expense because it produced a higher income tax benefit when applied to the loss before income taxes.

BGE's income tax expense increased $20.1 million during the quarter ended March 31, 2009 mostly due to a higher effective tax rate. For the quarter ended March 31, 2008, BGE had a lower effective tax rate. BGE projected a reduction in its 2008 taxable income, which increased the relative impact of the favorable permanent tax adjustments in its effective tax rate, as a result of the impact of certain provisions of the 2008 Maryland settlement agreement.

Defined Benefit Plans Funded Status

Our actual return on qualified pension plan assets for the quarter ended March 31, 2009 was a loss of 7.0% as compared to our assumption of an expected annual return on pension plan assets of 8.5%. This loss reflects the continued declines in financial markets that began in 2008 and have continued through March 31, 2009. If our qualified pension plan assets continue to underperform for the remainder of 2009, our actual 2010 pension expense and future contribution levels may be affected.

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Financial Condition

Cash Flows

The following table summarizes our cash flows for the quarter ended March 31, 2009 and 2008, excluding the impact of changes in intercompany balances.

			2009 Segment Cash Flows									Consolidated Cash Flows


			Quarter Ended March 31, 2009									Quarter Ended March 31,
			Merchant			Regulated			Holding Company and Other			2009			2008

			(In millions)
Operating Activities
	Net (loss) income		$	(202.7	)	$	85.0		$	(2.0	)	$	(119.7	)	$	149.4
	Non-cash merger termination and strategic alternatives costs			37.2			—			—			37.2			—
	Derivative sales contracts classified as financing activities under SFAS No. 149			296.8			—			—			296.8			1.5
	Other non-cash adjustments to net (loss) income			217.1			92.2			26.2			335.5			31.5
	Changes in working capital
		Derivative assets and liabilities, excluding collateral		62.9			0.1			4.6			67.6			(1.2	)
		Net collateral and margin		209.6			2.0			—			211.6			323.7
		Other changes		320.3			137.9			(65.8	)		392.4			(125.2	)
	Defined benefit obligations¹			—			—			—			(251.5	)		(62.4	)
	Other			(80.1	)		6.5			93.5			19.9			31.1

Net cash provided by operating activities				861.1			323.7			56.5			989.8			348.4

Investing activities
	Investments in property, plant and equipment			(310.3	)		(79.1	)		(2.7	)		(392.1	)		(388.4	)
	Asset acquisitions, net of cash acquired			—			—			—			—			(156.9	)
	Contributions to nuclear decommissioning trust funds			(18.7	)		—			—			(18.7	)		(18.7	)
	Proceeds from sale of investments and other assets			0.2			—			31.2			31.4			63.8
	Contract and portfolio acquisitions			(866.3	)		—			—			(866.3	)		—
	Decrease (increase) in restricted funds²			0.2			(24.5	)		1,003.6			979.3			(39.3	)
	Other investments			(0.9	)		—			—			(0.9	)		(0.6	)

Net cash (used in) provided by investing activities				(1,195.8	)		(103.6	)		1,032.1			(267.3	)		(540.1	)

Cash flows from operating activities less cash flows from investing activities			$	(334.7	)	$	220.1		$	1,088.6			722.5			(191.7	)

Financing Activities¹
	Net repayment of debt (includes $1 billion of 14% Senior Notes to MidAmerican)												(803.4	)		(163.7	)
	Proceeds from issuance of common stock												5.8			3.9
	Debt issuance costs												(62.7	)		—
	Common stock dividends paid												(85.7	)		(79.3	)
	BGE preference stock dividends paid												(3.3	)		(3.3	)
	Proceeds from contract and portfolio acquisitions												863.8			—
	Derivative sales contracts classified as financing activities under SFAS No. 149												(296.8	)		(1.5	)
	Other												4.3			2.3

Net cash used in financing activities													(378.0	)		(241.6	)

Net increase (decrease) in cash and cash equivalents												$	344.5		$	(433.3	)

1 Items are not allocated to the business segments because they are managed for the company as a whole.
2 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 payment of the 14% Senior Notes held by MidAmerican. The 14% Senior Notes were repaid in full in January 2009.

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Cash Flows from Operating Activities

Cash provided by operating activities was $989.8 million in 2009 compared to $348.4 million in 2008. This $641.4 million increase in cash flows was primarily due to $474.3 million of net favorable changes in working capital and a net increase of $295.3 million as a result of a reclassification of proceeds from derivative power sales contracts as financing activities under SFAS No. 149. We discuss the impact on cash flows from financing activities below. These favorable changes were partially offset by a $195.0 million increase in pension contributions.

The net favorable changes in working capital of $474.3 million included $266.8 million in declines in fuel stock inventory, $179.6 million in increased income tax refunds, $153.5 million reduction in cash paid for performance based compensation, partially offset by $112.1 million less net collateral and margin returned in 2009 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	)
Additional collateral held associated with nonderivative contracts		26.3
Net return of collateral posted associated with nonderivative contracts*		128.2
Return of initial and variation margin posted on exchange-traded transactions recorded in accounts receivable		178.7
Additional fair value net cash collateral posted (netted against derivative assets / liabilities)**		(121.6	)

Change in net collateral and margin posted		211.6

Net collateral and margin posted, March 31, 2009	$	(1,234.0	)

* Includes approximately $214 million of additional collateral posted due to certain counterparties that would not accept letters of credit issued by certain financial institutions.
** 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 Annual Report on Form 10-K.

The $211.6 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, and
•: collateral returned as part of the divestiture of a majority of our international commodities operation and gas trading operation.

These decreases were offset by 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 in the Available Sources of Funding section.

Cash Flows from Investing Activities

Cash used in investing activities was $267.3 million in 2009 compared to $540.1 million in 2008. The $272.8 million decrease in 2009 compared to 2008 was primarily due to:

•: $1,018.6 million decrease in restricted funds, primarily due to the release of funds for the repayment of the $1 billion of 14% Senior Notes to MidAmerican in January 2009, and
•: the absence of cash used for acquisitions. $156.9 million was used in the quarter ended March 31, 2008 for the acquisition of the Hillabee Energy Center, a partially completed 774 MW gas-fired combined cycle power generation facility in Alabama.

This decrease in cash used for investing activities was partially offset by $866.3 million in cash used for contract and portfolio acquisitions as a result of the structure of the divestiture of a majority of our international commodities operation in March 2009. We discuss our divestitures in more detail beginning on page 14 of the Notes to Consolidated Financial Statements. There was no such activity in 2008.

Cash Flows from Financing Activities

Cash used in financing activities was $378.0 million in 2009 compared to $241.6 million in 2008. The increase in cash used for financing activities of $136.4 million was primarily due to:

•: a $639.7 million net increase in cash used to repay short-term borrowings and long-term debt primarily due to the repayment of the $1 billion 14% Senior Notes to MidAmerican in January 2009,
•: a $62.7 million increase in credit facility costs paid in the quarter ended March 31, 2009,
•: $295.3 million in cash outflows related to derivative power sales contracts classified as financing activity under SFAS No. 149. These contracts relate to transactions associated with the divestiture of our Houston-based gas trading operation. During the month of March 2009, we executed transactions at prices that differed from

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market prices. As a result, for cash flows associated with the out-of-the money derivative transactions executed, we recorded the ongoing cash flows related to these contracts in March 2009 as financing cash flows. We discuss our divestiture of our Houston-based gas trading operation in more detail beginning on page 15 of the Notes to Consolidated Financial Statements.

This increase in cash used for financing activities was partially offset by $863.8 million in cash received for contract and portfolio acquisitions as a result of the structure of the divestiture of a majority of our international commodities operation in March 2009. We discuss our divestitures on more detail beginning on page 14 of the Notes to Consolidated Financial Statements. There was no such activity in 2008.

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, 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 business.

The primary drivers of our use of liquidity have been our capital expenditure requirements and collateral requirements associated with hedging our generating assets, hedging our Customer Supply business in both power and gas, and hedging our coal businesses. 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. The current disruptions in the credit and capital markets have made it more difficult for us to raise capital and access the credit necessary to obtain sufficient liquidity to meet our business requirements.

Constellation Energy

At March 31, 2009, we had approximately $6.2 billion in committed credit facilities available as shown below. We have also included the pro forma effect on our credit facilities, which are reduced or terminated upon the occurrence of certain events, of closing the EDF transactions:

Facility Expiration		Facility Size		Facility Size Upon Completion of the EDF Transactions


		(In billions)
July 2012		$	3.85	$	2.32
November 2009¹			1.23		—
June 2009²			0.60		—
September 2013			0.35		—
December 2009			0.15		—

	Total	$	6.18	$	2.32

Collectively, these facilities currently support the issuance of letters of credit and/or cash borrowings up to approximately $6.2 billion as of March 31, 2009. At March 31, 2009, we had approximately $3.4 billion in letters of credit issued, and we borrowed approximately $0.7 billion under one of our credit facilities, and we had no commercial paper outstanding. During the month of April 2009, Constellation Energy issued no commercial paper. We may utilize commercial paper as a primary source of short-term debt if market conditions return to normal.

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 April 30, 2009, we have approximately $1.1 billion after-tax of liquidity becoming available. We expect to receive regulatory approval for an additional asset in the third quarter of 2009, which will increase the net after-tax liquidity to $1.4 billion. The $600 million interim backstop liquidity facility provided by EDF terminated as a result of the put arrangement becoming available. The put arrangement will expire at the

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earlier of December 31, 2010 or the termination of the Investment Agreement by EDF in the event of a breach of contract by us.

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 is not required as of April 30, 2009 as S&P's senior unsecured debt rating is above BBB-.

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%.

Under our $3.85 billion and $1.23 billion credit facilities, we will be required to grant a lien on certain generating facilities and pledge our ownership interests in our nuclear business to the lenders upon the earlier of (i) the closing of the Investment Agreement with EDF or (ii) the date on which both the Investment Agreement is terminated and our S&P or FitchRatings senior unsecured debt credit rating is below BBB- or our Moody's senior unsecured debt credit rating is below Baa3.

BGE

BGE currently maintains 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. At March 31, 2009, BGE had $370.0 million on its $400 million credit facility outstanding to secure funds in advance of maturing commercial paper and other obligations.

At March 31, 2009, BGE had no commercial paper outstanding. During the month of April 2009, BGE issued $20.0 million in commercial paper. BGE may utilize commercial paper as a primary source of short-term debt if market conditions return to normal.

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.

Net Available Liquidity

The following tables provide a summary of our net available liquidity at December 31, 2008 and March 31, 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 March 31, 2009

	Constellation Energy			BGE			Total Consolidated

	(In billions)
Credit facilities	$	6.2		$	0.4		$	6.6
Less: Letters of credit issued		(3.4	)		—			(3.4	)
Less: Cash drawn on credit facilities		(0.7	)		(0.4	)		(1.1	)

Undrawn facilities		2.1			—			2.1
Less: Commercial paper outstanding		—			—			—

Net available facilities		2.1			—			2.1
Add: Cash		0.5			—			0.5

Net available liquidity	$	2.6		$	—		$	2.6

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The following table provides our estimated net available liquidity at April 30, 2009:

	As of April 30, 2009

	Constellation Energy			BGE			Total Consolidated

	(In billions)
Credit facilities	$	5.6		$	0.4		$	6.0
Less: Letters of credit issued		(3.1	)		—			(3.1	)
Less: Cash drawn on credit facilities		(0.3	)		(0.4	)		(0.7	)

Undrawn facilities		2.2			—			2.2
Less: Commercial paper outstanding		—			—			—

Net available facilities		2.2			—			2.2
Add: Cash		0.7			—			0.7
Add: EDF put arrangement		1.1			—			1.1

Net available liquidity	$	4.0		$	—		$	4.0

Net available liquidity increased from December 31, 2008 to April 30, 2009 by approximately $1.7 billion as follows:



	(In billions)
Decrease in letters of credit issued	$	0.5
Increase in cash		0.5
Decrease in cash drawn on credit facilities		0.2
Decrease in credit facilities		(0.6	)
EDF put arrangement		1.1

Increase in net available liquidity	$	1.7

Through our efforts to reduce risk, we have significantly improved our liquidity. Through April 30, 2009, our risk management actions have resulted in a net increase in available liquidity of approximately $300 million since December 31, 2008. Specifically, we restructured and terminated existing transactions and amended certain credit agreements, which led to lower working capital requirements and reduced posting of initial margin. In addition, through April 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. Lastly, the change in credit facilities and EDF put arrangement was due to the receipt of required regulatory approvals on all but one asset covered by the EDF put arrangement, which resulted in the termination of the EDF interim backstop liquidity facility.

As discussed in our 2008 Annual Report on Form 10-K, we have made substantial changes in our strategy to improve our liquidity and our credit profile, including focusing on the following immediate goals:

•: reducing the collateral and liquidity needs of our Global Commodities and Customer Supply operations,
•: executing strategic initiatives for our Global Commodities operation, which we discuss in more detail in the Merchant Energy Business—Background section,
•: focusing on our core strengths, including owning, developing, and operating nuclear and non-nuclear generation assets, providing regulated utility service to customers, and maintaining strong supply relationships with retail and wholesale customers, and
•: working to close the sale to EDF of 49.99% of our nuclear generation and operation business as expeditiously as possible.

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. Also, we are exposed to certain operational risks that could have a significant impact on our liquidity. We discuss these risks in more detail in the Risk Factors section of our 2008 Annual Report on Form 10-K.

We believe that the actions that we have taken will be sufficient to meet our ongoing liquidity requirements over the next 12 months. However, if we cannot successfully execute on our strategies and/or actual changes in commodity prices differ from our estimates, our available liquidity would be negatively affected, which would have a material adverse effect on our financial results and condition.

Collateral

Constellation Energy's collateral requirements arise from its merchant energy business' need to participate in certain organized markets, such as Independent System Operators (ISOs) or financial exchanges as well as from our goal of

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remaining economically hedged in our Generation and power and gas Customer Supply operations, third party coal business, and our trading activities. To support wholesale and retail power Customer Supply obligations, as well as some 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, 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 quarter ended March 31, 2009, our initial margin requirements continued to decrease. In March 2009, we closed out our exchange positions related to our international commodities operation and gas trading operation, 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 counterparties. These collateral amounts may be fixed or may vary with price levels.

There are certain asymmetries relating to the use of collateral that create liquidity requirements for our merchant energy businesses. These asymmetries arise as a result of our actions to be economically hedged as well as market conditions or conventions for conducting business that result in some transactions being collateralized while others are not, including:

•: In our third party coal business, we generally buy coal from suppliers that do not post collateral, but we enter into physical or financial sales contracts that require us to post collateral.
•: In our Customer Supply operation, we generally do not receive collateral under contractual obligations to supply power or gas to our customers but our Global Commodities operation hedges these transactions through purchases of power and gas that generally require us to post collateral.
•: In our Generation operation, we may have to post collateral on our power sale or fuel purchase contracts, but our generating plants are not a source of collateral.

Customers of our merchant energy 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 March 31, 2009, 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**


	(In billions)
Below investment grade		1	$	1.8

* If there are split ratings among the independent credit-rating agencies, the lowest credit rating is used to determine our incremental collateral obligations.

** Includes $0.4 billion related to derivative contracts as discussed in Notes to Consolidated Financial Statements beginning on page 33.

We estimate that our additional collateral obligations in the event of a downgrade to one level below the investment grade threshold would be $1.5 billion as of April 30, 2009, which primarily reflects the successful execution of the announced divestitures. The actual amount of the reduction will be impacted the timing of the remaining contract assignments.

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 section.

Capital Resources

Our estimated annual cash requirement amounts for the years 2009 and 2010 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.

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Capital requirements for 2009 and 2010 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,
•: the availability of cash from operations, and
•: business decisions to invest in capital projects.

Our estimates are also subject to additional factors. Please see the Forward Looking Statements section on page 68 and Risk Factors section in our 2008 Annual Report on Form 10-K. We discuss the potential impact of environmental legislation and regulation in more detail in Business Environment section beginning on page 40 and Item 1. Business—Environmental Matters section of our 2008 Annual Report on Form 10-K.

Calendar Year Estimates			2009		2010


			(In billions)
Nonregulated Capital Requirements:
	Merchant energy
		Generation plants	$	0.5	$	0.2
		Environmental controls		0.3		—
		Portfolio acquisitions/investments		0.1		0.1
		Technology/other		0.1		—
		Nuclear Fuel¹		0.2		—

	Total merchant energy capital requirements			1.2		0.3
	Other nonregulated capital requirements			—		—

	Total nonregulated capital requirements			1.2		0.3

Regulated Capital Requirements:
	Regulated electric			0.4		0.6
	Regulated gas			0.1		0.1

	Total regulated capital requirements			0.5		0.7

Total Capital Requirements			$	1.7	$	1.0

1 Assumes the Investment Agreement with EDF closes in the third quarter of 2009 and we deconsolidate our nuclear generation and operation business. As a result, we are reflecting nine months of nuclear fuel capital requirements for 2009 and none for 2010.

Capital Requirements

Merchant Energy Business

Our merchant energy business' capital requirements consist of its continuing requirements, including expenditures for:

•: improvements to generating plants,
•: nuclear fuel costs,
•: costs of complying with the EPA, Maryland, and Pennsylvania environmental regulations and legislation, and
•: enhancements to our information technology infrastructure.

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.

Funding for Capital Requirements

We discuss our funding for capital requirements in our 2008 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 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 March 31, 2009 in the following table:

			Payments

			2009			2010- 2011			2012- 2013			There- after			Total

			(In millions)
Contractual Payment Obligations
Long-term debt:¹
	Nonregulated
		Principal	$	1,501.3		$	0.5		$	730.1		$	2,670.8		$	4,902.7
		Interest		235.6			314.0			260.5			3,027.5			3,837.6

	Total			1,736.9			314.5			990.6			5,698.3			8,740.3
	BGE
		Principal		65.0			138.2			639.1			1,422.8			2,265.1
		Interest		118.0			258.1			231.3			1,336.6			1,944.0

	Total			183.0			396.3			870.4			2,759.4			4,209.1
BGE preference stock				—			—			—			190.0			190.0
Operating leases²
	Operating leases, gross			210.0			431.3			380.6			566.7			1,588.6
	Sublease rentals			(69.9	)		(133.3	)		(77.4	)		(139.1	)		(419.7	)

	Operating leases, net			140.1			298.0			303.2			427.6			1,168.9
Purchase obligations:³
	Purchased capacity and energy⁴			420.7			283.0			187.9			228.3			1,119.9
	Fuel and transportation			966.3			1,247.4			620.3			1,370.8			4,204.8
	Other			199.6			107.3			36.4			22.2			365.5
Other noncurrent liabilities:
	FIN 48 tax liability			—			26.1			99.3			12.4			137.8
	Pension benefits⁵			87.4			302.1			326.6			(39.0	)		677.1
	Postretirement and postemployment benefits⁶			31.0			91.8			105.6			248.4			476.8

Total contractual payment obligations			$	3,765.0		$	3,066.5		$	3,540.3		$	10,918.4		$	21,290.2

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. Investors may require us to repay $240.8 million early through remarketing 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 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 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 Annual Report on Form 10-K.

At March 31, 2009, Constellation Energy had a total face amount of $15.8 billion in guarantees outstanding, of which $14.4 billion related to our merchant energy business. 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 $3 billion at March 31, 2009, which represents the total amount the parent company could be required to fund based on March 31, 2009 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 the Notes to Consolidated Financial Statements on page 22.

Risk Management

Market Risk

Economic Value at Risk (EVaR)

EVaR is a measure that attempts to estimate the sensitivity of our total portfolio economic value to changes in market prices. The EVaR measure includes all positions of our merchant 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. EVaR is a one-day measure calculated at a 95% confidence level using a 5 year time horizon. At March 31, 2009, our EVaR was approximately $92 million, which represents a 32% decline from its level of $136 million at December 31, 2008.

Due to the inherent limitations of statistical measures such as EVaR and the seasonality of changes in market prices, the EVaR calculation may not reflect the full extent of our commodity price risk exposure. Additionally, because our EVaR methodology uses a linear approximation method, actual changes in the value of options in our portfolio resulting from significant price changes may differ from estimates generated using this methodology. As a result, actual changes in the fair value of derivative assets and liabilities subject to mark-to-market accounting could

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differ from the calculated EVaR, and such changes could have a material impact on our financial results.

While EVaR reflects the risk of loss under normal market conditions, stress testing captures Constellation Energy's 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 changes in both price level and spreads. Additional scenarios focus on the risks predominant in individual portions of our business segments and include scenarios that focus on loss of generation, customer demand growth or demand destruction, or a shift in 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 senior management and to the lines of business to help them better measure and manage risks and to understand event risk-sensitive positions.

Value at Risk (VaR)

Where EVaR is a measure that attempts to estimate the sensitivity of our total portfolio economic value, VaR is a measure that attempts to measure the sensitivity of our mark-to-market energy contracts of our Global Commodities operation to potential changes in market prices. VaR is a statistical model designed to predict risk 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 changes over the most recent rolling three-month period. Our VaR calculation includes all of our Global Commodities operation derivative assets and liabilities subject to mark-to-market accounting, including contracts for energy commodities and derivatives that result in physical settlement and contracts that require cash settlement. VaR is a statistical risk measurement model subject to limitations similar to those of EVaR.

The VaR calculation does not include market risks associated with activities that are subject to accrual accounting, primarily our generating facilities and our customer supply load-serving activities.

The VaR amounts below represent the potential pre-tax loss in the fair value of our Global Commodities operation derivative assets and liabilities 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 March 31, 2009


		(In millions)
99% Confidence Level, One-Day Holding Period
	Average	$	34.0
	High		55.0
95% Confidence Level, One-Day Holding Period
	Average		25.9
	High		41.9
95% Confidence Level, Ten-Day Holding Period
	Average		81.9
	High		132.3

We experienced higher average VaR for the quarter ended March 31, 2009, primarily as a result of dedesignating hedge contracts that increased our mark-to-market portfolio that is subject to the VaR calculation. The dedesignation was primarily attributable to the divestitures of our international commodities operations and efforts to reduce risk in our portfolio.

For the quarter ended March 31, 2009, the average VaR for the trading activities of our Global Commodities Group operation's derivative assets and liabilities subject to mark-to-market accounting for a one- day holding period at a 99% confidence level, was $14.1 million. This was further reduced to $7.2 million at April 30, 2009. This is lower than the $17.8 million average VaR for the year ended December 31, 2008 and the $23.7 million VaR for the quarter ended September 30, 2008 and reflects Constellation Energy's strategic initiative to reduce its proprietary trading activities, which are managed through daily VaR limits, stop loss limits and liquidity guidelines. We expect this reduced level of trading activity and VaR to continue in future periods.

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 credit risk of our Global Commodities operation through credit policies and procedures, which include an established credit approval process, daily

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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.

As of March 31, 2009 and December 31, 2008, counterparties in the credit portfolio of our Global Commodities operation had the following public credit ratings:




Rating
	Investment Grade¹	58	%	52	%
	Non-Investment Grade	12		15
	Not Rated	30		33

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 $1.2 billion at March 31, 2009 compared to $1.5 billion at December 31, 2008. This decrease was mostly due to a decrease in our portfolio's credit exposure to natural gas customers, international coal customers, and freight companies that do not have public credit ratings as a result of the divestiture of a majority of our international commodities operation.

Many of our not rated counterparties are considered investment grade equivalent 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 $580 million or 48% of the exposure to not rated counterparties was rated investment grade equivalent at March 31, 2009 and approximately $883.7 million or 60% was rated investment grade equivalent at December 31, 2008.

The following table provides the breakdown of the credit quality of our wholesale credit portfolio based on our internal credit ratings:




Investment Grade Equivalent	75	%	74	%
Non-Investment Grade	25		26

Our total exposure, net of collateral, to counterparties across our entire wholesale portfolio is $4.1 billion as of March 31, 2009. The top ten counterparties account for approximately 33% of our total exposure. As shown in the table below, no single counterparty concentration comprises more than 10% of the total exposure of the portfolio.

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 total exposure of $4.1 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 $1.5 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 under SFAS No. 133, as well as amounts owed by wholesale counterparties for transactions that settled but have not yet been paid.

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The following table highlights the credit quality and exposures related to these activities at March 31, 2009:

Rating	Total Exposure Before Credit Collateral		Credit Collateral		Net Exposure			Net Exposure of Counterparties Greater than 10% of Net Exposure


	(In millions)
Investment grade	$	1,782	$	591	$	1,191	—	$	—
Split rating		5		—		5	—		—
Non-investment grade		127		46		81	—		—
Internally rated—investment grade		179		73		106	—		—
Internally rated—non-investment grade		95		17		78	—		—

Total	$	2,188	$	727	$	1,461	—	$	—

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 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). 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 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 the Risk Management section of our 2008 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:

•: SFAS No. 133 hedging activities section in the Notes to Consolidated Financial Statements beginning on page 25,
•: activities of our Global Commodities operation in the Merchant Energy Business section of Management's Discussion and Analysis beginning on page 45,
•: evaluation of commodity and credit risk in the Risk Management section of Management's Discussion and Analysis beginning on page 62, and
•: changes to our business environment in the Business Environment section of Management's Discussion and Analysis beginning on page 40.

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 officers and principal financial officer of both Constellation Energy and BGE have 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 and BGE's disclosure controls and procedures are effective.

Changes in Internal Control over Financial Reporting

During the quarter ended March 31, 2009, 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.

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PART II. OTHER INFORMATION

Item 1. Legal Proceedings

We discuss our Legal Proceedings in the Notes to Consolidated Financial Statements beginning on page 23.

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		Average Price Paid for Shares			Maximum Dollar Amounts of Shares that May Yet Be Purchased Under the Plans and Programs (at month end)²


January 1 – January 31, 2009	—		—	—	$	750 million
February 1 – February 28, 2009	241,730	$	21.03	—		750 million
March 1 – March 31, 2009	4,282		25.71	—		750 million

Total	246,012	$	21.11	—		—

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. Pursuant to the terms of our Series B Preferred Stock, we are prohibited from engaging in a common share repurchase in an aggregate amount in excess of $100 million without the approval of the holders of more than 50% of the then outstanding shares of Series B Preferred Stock.

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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 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 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,
•: the likelihood and timing of the completion of the pending transaction with EDF Group and related entities (EDF), the terms and conditions of any required regulatory approvals for the pending transaction, potential impact of a termination of the pending transaction and potential diversion of management's time and attention from our ongoing business during this time period,
•: 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 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 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 actual outcome of uncertainties associated with assumptions and estimates using judgment when 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. 10(a)	*	Constellation Energy Group, Inc. 2007 Long-Term Incentive Plan, as amended and restated.
Exhibit No. 10(b)	*	Second amended and restated change in control severance agreement between Constellation Energy Group, Inc. and Michael J. Wallace.
Exhibit No. 10(c)	*	Change in control severance agreement between Constellation Energy Group, Inc. and Henry B. Barron, Jr.
Exhibit No. 10(d)	*	Offer letter between Constellation Energy Group, Inc. and Henry B. Barron, Jr.
Exhibit No. 10(e)	*	Letter agreement between Constellation Energy Group, Inc. and Jonathan W. Thayer.
Exhibit No. 10(f)	*	Offer letter between Constellation Energy Group, Inc. and Brenda Boultwood.
Exhibit No. 10(g)	*	Individual Termination Agreement, Release and Waiver between Constellation Energy Group, Inc. and Irving B. Yoskowitz.
Exhibit No. 10(h)		Amendment No. 1, dated as of April 15, 2009, to the Second Amended and Restated Credit Agreement, dated as of December 17, 2008, among Constellation Energy Group, Inc., the Lenders named therein, Wachovia Bank, National Association, as Administrative Agent, LC Bank, Swingline Lender and Collateral Agent.
Exhibit No. 10(i)		Letter Agreement dated April 21, 2009 among Constellation Energy Group, Inc., EDF Development Inc. and E.D.F. International S.A.
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.

*: Management contract or compensatory plan or arrangement.

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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 (Registrant)
Date: May 8, 2009		/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: May 8, 2009		/s/ KEVIN W. HADLOCK Kevin W. Hadlock, Senior Vice President of Baltimore Gas and Electric Company and as Principal Financial Officer