EX-99.3 5 a2200916zex-99_3.htm EXHIBIT 99.3
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Exhibit 99.3

Item 8. Financial Statements and Supplementary Data

REPORTS OF MANAGEMENT

Financial Statements

The management of Constellation Energy Group, Inc. and Baltimore Gas and Electric Company (the "Companies") is responsible for the information and representations in the Companies' financial statements. The Companies prepare the financial statements in accordance with accounting principles generally accepted in the United States of America based upon available facts and circumstances and management's best estimates and judgments of known conditions.

PricewaterhouseCoopers LLP, an independent registered public accounting firm, has audited the financial statements and expressed their opinion on them. They performed their audit in accordance with the standards of the Public Company Accounting Oversight Board (United States).

The Audit Committee of the Board of Directors, which consists of four independent Directors, meets periodically with management, internal auditors, and PricewaterhouseCoopers LLP to review the activities of each in discharging their responsibilities. The internal audit staff and PricewaterhouseCoopers LLP have free access to the Audit Committee.

Management's Report on Internal Control Over Financial Reporting—Constellation Energy Group, Inc.

The management of Constellation Energy Group, Inc. (Constellation Energy), under the direction of its principal executive officer and principal financial officer, is responsible for establishing and maintaining adequate internal control over financial reporting as defined in Exchange Act Rule 13a-15(f).

Constellation Energy's system of internal control over financial reporting is designed to provide reasonable assurance to Constellation Energy's management and Board of Directors regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles in the United States of America.

The management of Constellation Energy conducted an evaluation of the effectiveness of Constellation Energy's internal control over financial reporting using the framework in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). As noted in the COSO framework, an internal control system, no matter how well conceived and operated, can provide only reasonable, not absolute, assurance to management and the Board of Directors regarding achievement of an entity's financial reporting objectives. Based upon the evaluation under this framework, management concluded that Constellation Energy's internal control over financial reporting was effective as of December 31, 2009.

PricewaterhouseCoopers LLP, an independent registered public accounting firm, has audited the effectiveness of Constellation Energy's internal control over financial reporting as of December 31, 2009, as stated in their report on the next page.



Mayo A. Shattuck III Chairman of the Board, President and Chief Executive Officer		Jonathan W. Thayer Senior Vice President and Chief Financial Officer

Management's Report on Internal Control Over Financial Reporting—Baltimore Gas and Electric Company

The management of Baltimore Gas and Electric Company (BGE), under the direction of its principal executive officer and principal financial officer, is responsible for establishing and maintaining adequate internal control over financial reporting as defined in Exchange Act Rule 13a-15(f).

BGE's system of internal control over financial reporting is designed to provide reasonable assurance to BGE's management and Board of Directors regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles in the United States of America.

The management of BGE conducted an evaluation of the effectiveness of BGE's internal control over financial reporting using the framework in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). As noted in the COSO framework, an internal control system, no matter how well conceived and operated, can provide only reasonable, not absolute, assurance to management and the Board of Directors regarding achievement of an entity's financial reporting objectives. Based upon the evaluation under this framework, management concluded that BGE's internal control over financial reporting was effective as of December 31, 2009.

This annual report does not include an attestation report of BGE's independent registered public accounting firm regarding internal control over financial reporting. Management's report was not subject to attestation by BGE's independent registered public accounting firm pursuant to temporary rules of the Securities and Exchange Commission that permit BGE, as a non-accelerated filer, to provide only management's report in this annual report.



Kenneth W. DeFontes, Jr. President and Chief Executive Officer		Kevin W. Hadlock Senior Vice President and Chief Financial Officer

REPORTS OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholders of
Constellation Energy Group, Inc.

In our opinion, the consolidated financial statements listed in the index appearing under Item 15(a) (1) present fairly, in all material respects, the financial position of Constellation Energy Group, Inc. and its subsidiaries (the Company) at December 31, 2009 and 2008, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2009 in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedule listed in the index appearing under Item 15(a) (2) presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2009, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Company's management is responsible for these financial statements and financial statement schedule, for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in Management's Report on Internal Control Over Financial Reporting appearing under Item 8. Our responsibility is to express opinions on these financial statements, on the financial statement schedule, and on the Company's internal control over financial reporting based on our integrated audits. We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.

As discussed in Note 1 to the consolidated financial statements, in 2009 the Company changed its method of presenting noncontrolling interests. As discussed in Note 13 to the consolidated financial statements, in 2008 the Company changed its method of accounting for the measurement of fair value and classifying certain collateral balances. As discussed in Note 1 to the consolidated financial statements, in 2007 the Company changed its method of accounting for uncertain tax positions.

A company's internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company's internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company's assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

We have also previously audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of Constellation Energy Group, Inc. and its subsidiaries as of December 31, 2007, 2006 and 2005, and the related consolidated statements of income (loss), cash flows, and common shareholders' equity and comprehensive income (loss) for the years ended December 31, 2006 and 2005 (none of which are presented herein); and we expressed unqualified opinions on those consolidated financial statements. In our opinion, the information set forth in the Summary of Operations and Summary of Financial Condition of Constellation Energy Group, Inc. and its subsidiaries included in the Selected Financial Data appearing under Item 6 for each of the five years in the period ended December 31, 2009, is fairly stated, in all material respects, in relation to the consolidated financial statements from which it has been derived.

PricewaterhouseCoopers LLP
Baltimore, Maryland

February 26, 2010, except with respect to our opinion on the consolidated financial statements insofar as it relates to Note 3, as to which the date is November 12, 2010

To Board of Directors and Shareholder of Baltimore Gas and Electric Company

In our opinion, the consolidated financial statements listed in the index appearing under Item 15(a) (1) present fairly, in all material respects, the financial position of Baltimore Gas and Electric Company and its subsidiaries (the Company) at December 31, 2009 and 2008, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2009 in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedule listed in the index appearing under Item 15(a) (2) presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements. These financial statements and financial statement schedule are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements and financial statement schedule based on our audits. We conducted our audits of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

As discussed in Note 1 to the consolidated financial statements, in 2009 the Company changed its method of presenting noncontrolling interests. As discussed in Note 13 to the consolidated financial statements, in 2008 the Company changed its method of accounting for the measurement of fair value. As discussed in Note 1 to the consolidated financial statements, in 2007 the Company changed its method of accounting for uncertain tax positions.

We have also previously audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of Baltimore Gas and Electric Company and its subsidiaries as of December 31, 2007, 2006 and 2005, and the related consolidated statements of income and cash flows for the years ended December 31, 2006 and 2005 (none of which are presented herein); and we expressed unqualified opinions on those consolidated financial statements. In our opinion, the information set forth in the Summary of Operations and Summary of Financial Condition of Baltimore Gas and Electric Company and its subsidiaries included in the Selected Financial Data appearing under Item 6 for each of the five years in the period ended December 31, 2009, is fairly stated, in all material respects, in relation to the consolidated financial statements from which it has been derived.

PricewaterhouseCoopers LLP
Baltimore, Maryland
February 26, 2010

CONSOLIDATED STATEMENTS OF INCOME (LOSS)

Constellation Energy Group, Inc. and Subsidiaries

Year Ended December 31,		2009			2008			2007


		(In millions, except per share amounts)
Revenues
	Nonregulated revenues	$	12,024.3		$	16,057.6		$	17,786.5
	Regulated electric revenues		2,820.7			2,679.5			2,455.6
	Regulated gas revenues		753.8			1,004.8			943.0

	Total revenues		15,598.8			19,741.9			21,185.1
Expenses
	Fuel and purchased energy expenses		11,135.6			15,521.3			16,473.9
	Operating expenses		2,228.0			2,378.8			2,447.4
	Merger termination and strategic alternatives costs		145.8			1,204.4			—
	Impairment losses and other costs		124.7			741.8			20.2
	Workforce reduction costs		12.6			22.2			2.3
	Depreciation, depletion, and amortization		589.1			583.2			557.8
	Accretion of asset retirement obligations		62.3			68.4			68.3
	Taxes other than income taxes		290.4			301.8			288.9

	Total expenses		14,588.5			20,821.9			19,858.8
Equity Investment (Losses) Earnings			(6.1	)		76.4			8.1
Gain on Sale of Interest in CENG			7,445.6			—			—
Net (Loss) Gain on Divestitures			(468.8	)		25.5			—

Income (Loss) from Operations			7,981.0			(978.1	)		1,334.4
Gain on Sales of CEP LLC Equity			—			—			63.3
Other (Expense) Income			(140.7	)		(69.5	)		157.4
Fixed Charges
	Interest expense		437.2			399.1			311.8
	Interest capitalized and allowance for borrowed funds used during construction		(87.1	)		(50.0	)		(19.4	)

	Total fixed charges		350.1			349.1			292.4

Income (Loss) from Continuing Operations Before Income Taxes			7,490.2			(1,396.7	)		1,262.7
Income Tax Expense (Benefit)			2,986.8			(78.3	)		428.3

Income (Loss) from Continuing Operations			4,503.4			(1,318.4	)		834.4
Loss from discontinued operations, net of income taxes of $1.5			—			—			(0.9	)

Net Income (Loss)			4,503.4			(1,318.4	)		833.5
Net Income (Loss) Attributable to Noncontrolling Interests and BGE Preference Stock Dividends			60.0			(4.0	)		12.0

Net Income (Loss) Attributable to Common Stock		$	4,443.4		$	(1,314.4	)	$	821.5
Average Shares of Common Stock Outstanding—Basic			199.3			179.1			180.2
Average Shares of Common Stock Outstanding—Diluted			200.3			179.1			182.5
Earnings (Loss) Per Common Share from Continuing Operations—Basic		$	22.29		$	(7.34	)	$	4.56
Loss from discontinued operations			—			—			(0.01	)

Earnings (Loss) Per Common Share—Basic		$	22.29		$	(7.34	)	$	4.55

Earnings (Loss) Per Common Share from Continuing Operations—Diluted		$	22.19		$	(7.34	)	$	4.51
Loss from discontinued operations			—			—			(0.01	)

Earnings (Loss) Per Common Share—Diluted		$	22.19		$	(7.34	)	$	4.50

Dividends Declared Per Common Share		$	0.96		$	1.91		$	1.74

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

CONSOLIDATED BALANCE SHEETS

Constellation Energy Group, Inc. and Subsidiaries

At December 31,			2009			2008


			(In millions)
Assets
	Current Assets
		Cash and cash equivalents	$	3,440.0		$	202.2
		Accounts receivable (net of allowance for uncollectibles of $160.6 and $240.6, respectively)		2,137.6			3,389.9
		Fuel stocks		314.9			717.9
		Materials and supplies		93.3			224.5
		Derivative assets		639.1			1,465.0
		Unamortized energy contract assets (includes $371.3 million related to CENG)		436.5			81.3
		Restricted cash		27.0			1,030.5
		Deferred income taxes		127.9			268.0
		Other		244.4			815.5

		Total current assets		7,460.7			8,194.8

	Investments and Other Noncurrent Assets
		Nuclear decommissioning trust funds		—			1,006.3
		Investment in CENG		5,222.9			—
		Other investments		424.3			421.0
		Regulatory assets (net)		414.4			494.7
		Goodwill		25.5			4.6
		Derivative assets		633.9			851.8
		Unamortized energy contract assets (includes $400.9 million related to CENG)		604.7			173.1
		Other		304.2			421.3

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

	Property, Plant and Equipment
		Nonregulated property, plant and equipment		5,784.6			8,866.2
		Regulated property, plant and equipment		6,749.9			6,419.4
		Nuclear fuel (net of amortization)		—			443.0
		Accumulated depreciation		(4,080.7	)		(5,012.1	)

		Net property, plant and equipment		8,453.8			10,716.5


Total Assets			$	23,544.4		$	22,284.1

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

CONSOLIDATED BALANCE SHEETS

Constellation Energy Group, Inc. and Subsidiaries

At December 31,			2009		2008


			(In millions)
Liabilities and Equity
	Current Liabilities
		Short-term borrowings	$	46.0	$	855.7
		Current portion of long-term debt		56.9		2,591.5
		Accounts payable and accrued liabilities		1,262.4		2,370.1
		Customer deposits and collateral		103.3		120.3
		Derivative liabilities		632.6		1,241.8
		Unamortized energy contract liabilities		390.1		393.5
		Accrued taxes		877.3		51.1
		Accrued expenses		297.9		322.0
		Other		374.2		514.2

		Total current liabilities		4,040.7		8,460.2

	Deferred Credits and Other Noncurrent Liabilities
		Deferred income taxes		3,205.5		677.0
		Asset retirement obligations		29.3		987.3
		Derivative liabilities		674.1		1,115.0
		Unamortized energy contract liabilities		653.7		906.4
		Defined benefit obligations		743.9		1,354.3
		Deferred investment tax credits		32.0		44.1
		Other		388.8		249.6

		Total deferred credits and other noncurrent liabilities		5,727.3		5,333.7

	Long-term Debt, Net of Current Portion			4,814.0		5,098.7
	Equity
		Common shareholders' equity		8,697.1		3,181.4
		BGE preference stock not subject to mandatory redemption		190.0		190.0
		Noncontrolling interests		75.3		20.1

		Total equity		8,962.4		3,391.5

	Commitments, Guarantees, and Contingencies (see Note 12)
Total Liabilities and Equity			$	23,544.4	$	22,284.1

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

CONSOLIDATED STATEMENTS OF CASH FLOWS

Constellation Energy Group, Inc. and Subsidiaries

Year Ended December 31,				2009			2008			2007


				(In millions)
Cash Flows From Operating Activities
	Net income (loss)			$	4,503.4		$	(1,318.4	)	$	833.5
	Adjustments to reconcile to net cash provided by operating activities
		Depreciation, depletion, and amortization			589.1			583.2			557.8
		Amortization of nuclear fuel			117.9			123.9			114.3
		Amortization of energy contracts and derivatives designated as hedges			(138.4	)		(256.3	)		(222.9	)
		All other amortization			135.7			40.5			11.2
		Accretion of asset retirement obligations			62.3			68.4			68.3
		Deferred income taxes			1,846.9			(122.8	)		226.2
		Investment tax credit adjustments			(12.1	)		(6.4	)		(6.7	)
		Deferred fuel costs			68.9			52.0			(248.0	)
		Defined benefit obligation expense			85.3			99.6			111.8
		Defined benefit obligation payments			(372.5	)		(120.4	)		(165.4	)
		Merger termination and strategic alternatives costs			128.2			541.8			—
		Workforce reduction costs			12.6			22.2			2.3
		Impairment losses and other costs			124.7			741.8			20.2
		Impairment losses on nuclear decommissioning trust assets			62.6			165.0			8.5
		Gain on sale of 49.99% membership interest in CENG			(7,445.6	)		—			—
		Gains on sale of CEP LLC equity			—			—			(63.3	)
		Loss (gain) on divestitures			468.8			(38.1	)		—
		Gains on termination of contracts			—			(73.1	)		—
		Accrual of BGE residential customer credit			112.4			—			—
		Equity in earnings of affiliates less than dividends received			15.5			6.3			45.3
		Derivative contracts classified as financing activities			1,138.3			(107.2	)		32.2
		Changes in working capital
			Accounts receivable, excluding margin		543.3			606.7			(664.2	)
			Derivative assets and liabilities, excluding collateral		425.3			(757.9	)		(138.2	)
			Net collateral and margin		1,522.8			(960.3	)		49.6
			Materials, supplies, and fuel stocks		220.6			(33.5	)		(66.4	)
			Other current assets		217.2			(95.4	)		(18.5	)
			Accounts payable and accrued liabilities		(1,105.0	)		(225.8	)		448.8
			Liability for unrecognized tax benefits		102.1			79.7			71.9
			Other current liabilities		788.8			(238.1	)		(14.0	)
		Other			171.7			(38.5	)		(53.3	)

	Net cash provided by (used in) operating activities				4,390.8			(1,261.1	)		941.0

Cash Flows From Investing Activities
	Investments in property, plant and equipment				(1,529.7	)		(1,934.1	)		(1,295.7	)
	Asset acquisitions and business combinations, net of cash acquired				(41.1	)		(315.3	)		(347.5	)
	Investments in nuclear decommissioning trust fund securities				(385.2	)		(440.6	)		(659.5	)
	Proceeds from nuclear decommissioning trust fund securities				366.5			421.9			650.7
	Investments in joint ventures				(201.6	)		—			—
	Issuances of loans receivable				—			—			(19.0	)
	Proceeds from sale of 49.99% membership interest in CENG				3,528.7			—			—
	Proceeds from sales of investments and other assets				88.3			446.3			13.9
	Contract and portfolio acquisitions				(2,153.7	)		—			(474.2	)
	Decrease (increase) in restricted funds				1,003.3			(942.8	)		(109.9	)
	Other				0.1			21.7			(45.3	)

	Net cash provided by (used in) investing activities				675.6			(2,742.9	)		(2,286.5	)

Cash Flows From Financing Activities
	Net (maturity) issuance of short-term borrowings				(809.7	)		813.7			14.0
	Proceeds from issuance of common stock				33.9			17.6			65.1
	Proceeds from issuance of long-term debt				136.1			3,211.4			698.2
	Common stock dividends paid				(228.0	)		(336.3	)		(306.0	)
	Reacquisition of common stock				—			(16.2	)		(409.5	)
	BGE preference stock dividends paid				(13.2	)		(13.2	)		(13.2	)
	Proceeds from contract and portfolio acquisitions				2,263.1			—			847.8
	Repayment of long-term debt				(1,986.8	)		(577.4	)		(745.3	)
	Derivative contracts classified as financing activities				(1,138.3	)		107.2			(32.2	)
	Debt and credit facility costs				(98.4	)		(104.8	)		—
	Other				12.7			8.3			33.4

	Net cash (used in) provided by financing activities				(1,828.6	)		3,110.3			152.3

Net Increase (Decrease) in Cash and Cash Equivalents					3,237.8			(893.7	)		(1,193.2	)
Cash and Cash Equivalents at Beginning of Year					202.2			1,095.9			2,289.1

Cash and Cash Equivalents at End of Year				$	3,440.0		$	202.2		$	1,095.9

Other Cash Flow Information:
	Cash paid during the year for:
		Interest (net of amounts capitalized)		$	369.5		$	341.4		$	291.8
		Income taxes		$	57.1		$	119.2		$	282.4

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

CONSOLIDATED STATEMENTS OF COMMON SHAREHOLDERS' EQUITY AND COMPREHENISVE INCOME (LOSS)

Constellation Energy Group, Inc. and Subsidiaries

				Common Stock									Accumulated Other Comprehensive Loss

Years Ended December 31, 2009, 2008, and 2007				Common Stock						Retained Earnings						Noncontrolling Interests			Total Amount
Years Ended December 31, 2009, 2008, and 2007				Shares			Amount			Retained Earnings						Noncontrolling Interests			Total Amount

				(Dollar amounts in millions, number of shares in thousands)
Balance at December 31, 2006					180,519		$	2,738.6		$	3,474.3		$	(1,603.6	)	$	284.5		$	4,893.8
Decrease in noncontrolling interests from deconsolidation																	(74.1	)		(74.1	)
Comprehensive Income
	Net income										821.5						12.0			833.5
	Other comprehensive income
		Hedging instruments:
			Reclassification of net losses on hedging instruments from OCI to net income, net of taxes of $(682.3)											1,124.8						1,124.8
			Net unrealized loss on hedging instruments, net of taxes of $408.2											(671.1	)					(671.1	)
		Available-for-sale securities:
			Reclassification of net gains on securities from OCI to net income, net of taxes of $1.0											(1.6	)					(1.6	)
			Net unrealized gain on securities, net of taxes of $(25.5)											26.5						26.5
		Defined benefit plans:
			Net gain arising during period, net of taxes of $(7.8)											11.6						11.6
			Amortization of net actuarial loss, prior service cost, and transition obligation included in net periodic benefit cost, net of taxes of $(15.9)											24.6						24.6
		Net unrealized gain on foreign currency translation, net of taxes of $(1.8)												7.0						7.0
		Other												(10.8	)					(10.8	)

Total Comprehensive Income											821.5			511.0			12.0			1,344.5
Effect of adoption of uncertain tax position accounting standard											(7.3	)								(7.3	)
BGE preference stock dividends																	(13.2	)		(13.2	)
Common stock dividend declared ($1.74 per share)											(368.4	)								(368.4	)
Common stock issued and share-based awards					1,789			184.2												184.2
Common stock purchased					(1,847	)		(159.5	)											(159.5	)
Common stock purchased and retired					(2,024	)		(250.0	)											(250.0	)
Other											(0.6	)								(0.6	)

Balance at December 31, 2007					178,437			2,513.3			3,919.5			(1,092.6	)		209.2			5,549.4
Increase in noncontrolling interests from consolidation of a VIE																	18.1			18.1
Comprehensive Loss
	Net loss										(1,314.4	)					(4.0	)		(1,318.4	)
	Other comprehensive loss
		Hedging instruments:
			Reclassification of net losses on hedging instruments from OCI to net income, net of taxes of $(120.2)											200.6						200.6
			Net unrealized loss on hedging instruments, net of taxes of $561.6											(875.3	)					(875.3	)
		Available-for-sale securities:
			Reclassification of net losses on securities from OCI to net income, net of taxes of $(79.1)											81.7						81.7
			Net unrealized losses on securities, net of taxes of 189.8											(197.5	)					(197.5	)
		Defined benefit plans:
			Prior service cost arising during period, net of taxes of $4.9											(7.2	)					(7.2	)
			Net loss arising during period, net of taxes of $229.2											(339.9	)					(339.9	)
			Amortization of net actuarial loss, prior service cost, and transition obligation included in net periodic benefit cost, net of taxes of $(14.9)											21.3						21.3
		Net unrealized loss on foreign currency translation, net of taxes of $0.1												(3.1	)					(3.1	)
		Other												0.2						0.2

Total Comprehensive Loss											(1,314.4	)		(1,119.2	)		(4.0	)		(2,437.6	)
Effect of adoption of fair value measurement accounting standard											0.9									0.9
BGE preference stock dividends																	(13.2	)		(13.2	)
Common stock dividend declared ($1.91 per share)											(341.3	)								(341.3	)
Common stock issued and share-based awards *					21,406			667.3			(35.8	)								631.5
Common stock purchased					(200	)		(16.1	)											(16.1	)
Common stock purchased and retired					(514	)		—												—
Other											(0.2	)								(0.2	)

Balance at December 31, 2008					199,129			3,164.5			2,228.7			(2,211.8	)		210.1			3,391.5

*: Includes 19,897.3 million shares issued to MidAmerican Energy Holdings Company.

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

See Notes to Consolidated Financial Statements.

continued on next page

				Common Stock							Accumulated Other Comprehensive Loss

Years Ended December 31, 2009, 2008, and 2007				Common Stock				Retained Earnings						Noncontrolling Interests			Total Amount
Years Ended December 31, 2009, 2008, and 2007				Shares		Amount		Retained Earnings						Noncontrolling Interests			Total Amount

				(Dollar amounts in millions, number of shares in thousands)
Balance at December 31, 2008					199,129	$	3,164.5	$	2,228.7		$	(2,211.8	)	$	210.1		$	3,391.5
Contribution from noncontrolling interest															8.0			8.0
Other noncontrolling interest activity															0.4			0.4
Comprehensive Income
	Net income								4,443.4						60.0			4,503.4
	Other comprehensive income
		Hedging instruments:
			Reclassification of net losses on hedging instruments from OCI to net income, net of taxes of $(898.5)									1,499.4						1,499.4
			Net unrealized loss on hedging instruments, net of taxes of $251.2									(474.7	)					(474.7	)
		Available-for-sale securities:
			Reclassification of net losses on securities from OCI to net income, net of taxes of $(24.6)									25.4						25.4
			Net unrealized gains on securities, net of taxes of $(78.2)									77.7						77.7
		Defined benefit plans:
			Prior service cost arising during period, net of taxes of $1.0									(1.5	)					(1.5	)
			Net gains arising during period, net of taxes of $(23.9)									26.9						26.9
			Amortization of net actuarial loss, prior service cost, and transition obligation included in net periodic benefit cost, net of taxes of $(19.8)									30.3						30.3
		Deconsolidation of CENG joint venture:
			Net unrealized gains on nuclear decommissioning trust funds, net of taxes of $125.3									(125.3	)					(125.3	)
			Net unrealized losses on defined benefit plans, net of taxes of $(94.6)									138.0						138.0
		Net unrealized gains on foreign currency translation, net of taxes of $(2.7)										7.1						7.1
		Other comprehensive income—equity investment in CENG, net of taxes of $(11.7)										12.9						12.9
		Other comprehensive income related to other equity method investees, net of taxes of $(1.3)										2.1						2.1

Total Comprehensive Income									4,443.4			1,218.3			60.0			5,721.7
BGE preference stock dividends															(13.2	)		(13.2	)
Common stock dividend declared ($0.96 per share)									(192.2	)								(192.2	)
Common stock issued and share-based awards					1,856		65.1		(18.9	)								46.2

Balance at December 31, 2009					200,985	$	3,229.6	$	6,461.0		$	(993.5	)	$	265.3		$	8,962.4

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

CONSOLIDATED STATEMENTS OF INCOME

Baltimore Gas and Electric Company and Subsidiaries

Year Ended December 31,			2009			2008			2007


			(In millions)
Revenues
	Electric revenues		$	2,820.7		$	2,679.7		$	2,455.7
	Gas revenues			758.3			1,024.0			962.8

	Total revenues			3,579.0			3,703.7			3,418.5
Expenses
	Operating expenses
		Electricity purchased for resale		1,217.4			1,078.1			360.8
		Electricity purchased for resale from affiliate		623.5			802.0			1,139.6
		Gas purchased for resale		449.9			694.5			639.8
		Operations and maintenance		433.7			428.2			405.0
		Operations and maintenance from affiliate		126.2			109.6			128.6
		Impairment losses and other costs		20.0			—			—
		Workforce reduction costs		—			6.4			—
	Depreciation and amortization			262.1			227.9			234.2
	Taxes other than income taxes			177.8			174.5			176.2

	Total expenses			3,310.6			3,521.2			3,084.2

Income from Operations				268.4			182.5			334.3
Other Income				25.4			29.6			26.9
Fixed Charges
	Interest expense			143.6			144.2			127.9
	Allowance for borrowed funds used during construction			(4.3	)		(4.3	)		(2.6	)

	Total fixed charges			139.3			139.9			125.3

Income Before Income Taxes				154.5			72.2			235.9
Income Taxes
	Current			(119.8	)		(18.2	)		(2.4	)
	Deferred			184.7			40.2			100.0
	Investment tax credit adjustments			(1.1	)		(1.3	)		(1.6	)

	Total income taxes			63.8			20.7			96.0

Net Income				90.7			51.5			139.9
Preference Stock Dividends				13.2			13.2			13.2

Net Income Attributable to Common Stock before Noncontrolling Interests			$	77.5		$	38.3		$	126.7
Net Loss (Income) Attributable to Noncontrolling Interests				7.3			—			(0.1	)

Net Income Attributable to Common Stock			$	84.8		$	38.3		$	126.6

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

CONSOLIDATED BALANCE SHEETS

Baltimore Gas and Electric Company and Subsidiaries

At December 31,				2009			2008


				(In millions)
Assets
	Current Assets
		Cash and cash equivalents		$	13.6		$	10.7
		Accounts receivable (net of allowance for uncollectibles of $46.2 and $33.3, respectively)			311.7			327.0
		Accounts receivable, unbilled (net of allowance for uncollectibles of $1.0 and $0.9, respectively)			252.7			232.3
		Investment in cash pool, affiliated company			314.7			148.8
		Accounts receivable, affiliated companies			15.4			4.3
		Fuel stocks			73.8			143.7
		Materials and supplies			31.9			38.4
		Prepaid taxes other than income taxes			49.5			51.0
		Regulatory assets (net)			72.5			79.7
		Restricted cash			24.3			23.7
		Deferred income taxes			11.2			—
		Other			11.3			10.8

		Total current assets			1,182.6			1,070.4

	Investments and Other Assets
		Regulatory assets (net)			414.4			494.7
		Receivable, affiliated company			326.2			161.1
		Other			98.2			131.6

		Total investments and other assets			838.8			787.4

	Utility Plant
		Plant in service
			Electric		4,772.4			4,493.7
			Gas		1,260.6			1,221.1
			Common		499.0			476.3

			Total plant in service		6,532.0			6,191.1
		Accumulated depreciation			(2,318.2	)		(2,191.0	)

		Net plant in service			4,213.8			4,000.1
		Construction work in progress			215.5			225.7
		Plant held for future use			2.4			2.6

		Net utility plant			4,431.7			4,228.4

Total Assets				$	6,453.1		$	6,086.2

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

CONSOLIDATED BALANCE SHEETS

Baltimore Gas and Electric Company and Subsidiaries

At December 31,			2009			2008


			(In millions)
Liabilities and Equity
	Current Liabilities
		Short-term borrowings	$	46.0		$	370.0
		Current portion of long-term debt		56.5			90.0
		Accounts payable and accrued liabilities		166.0			231.0
		Accounts payable and accrued liabilities, affiliated companies		98.3			97.0
		Customer deposits		76.0			72.3
		Deferred income taxes		—			40.2
		Accrued taxes		80.2			18.8
		Residential customer rate credit		112.4			—
		Accrued expenses and other		96.1			98.4

		Total current liabilities		731.5			1,017.7

	Deferred Credits and Other Liabilities
		Deferred income taxes		1,087.6			843.3
		Payable, affiliated company		243.4			243.2
		Deferred investment tax credits		9.5			10.6
		Liability for uncertain tax positions		73.3			5.5
		Other		20.0			23.1

		Total deferred credits and other liabilities		1,433.8			1,125.7

	Long-term Debt
		Rate stabilization bonds		510.9			564.4
		Other long-term debt of BGE		1,431.5			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
		Unamortized discount and premium		(2.2	)		(2.4	)
		Current portion of long-term debt		(56.5	)		(90.0	)

		Total long-term debt		2,141.4			2,197.7

	Equity
		Common shareholder's equity:
		Common stock		912.2			912.2
		Retained earnings		1,026.0			625.4
		Accumulated other comprehensive income		0.6			0.6

		Total common shareholder's equity		1,938.8			1,538.2
		Preference stock not subject to mandatory redemption		190.0			190.0
		Noncontrolling interest		17.6			16.9

		Total equity		2,146.4			1,745.1

	Commitments, Guarantees, and Contingencies (see Note 12)
Total Liabilities and Equity			$	6,453.1		$	6,086.2

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

CONSOLIDATED STATEMENTS OF CASH FLOWS

Baltimore Gas and Electric Company and Subsidiaries

Year Ended December 31,				2009			2008			2007


				(In millions)
Cash Flows From Operating Activities
	Net income			$	90.7		$	51.5		$	139.9
	Adjustments to reconcile to net cash provided by operating activities
		Depreciation and amortization			262.1			227.9			234.2
		Other amortization			9.2			13.2			12.5
		Deferred income taxes			184.7			40.2			100.0
		Investment tax credit adjustments			(1.1	)		(1.3	)		(1.6	)
		Deferred fuel costs			68.9			52.0			(248.0	)
		Defined benefit plan expenses			32.7			30.6			39.8
		Allowance for equity funds used during construction			(8.2	)		(8.0	)		(4.9	)
		Accrual of residential customer rate credit			112.4			—			—
		Impairment losses and other costs			20.0			—			—
		Workforce reduction costs			—			6.4			—
		Changes in:
			Accounts receivable		(5.1	)		(33.1	)		(181.5	)
			Receivables, affiliated companies		(11.1	)		(0.1	)		(1.7	)
			Materials, supplies, and fuel stocks		76.4			(40.6	)		9.6
			Other current assets		(10.2	)		(4.5	)		25.9
			Accounts payable and accrued liabilities		(65.0	)		48.6			(4.9	)
			Accounts payable and accrued liabilities, affiliated companies		1.3			(67.5	)		1.1
			Other current liabilities		(44.4	)		(11.4	)		29.6
			Long-term receivables and payables, affiliated companies		(197.8	)		(45.7	)		(42.0	)
		Other			130.3			(29.1	)		(44.8	)

	Net cash provided by operating activities				645.8			229.1			63.2

Cash Flows From Investing Activities
	Utility construction expenditures (excluding equity portion of allowance for funds used during construction)				(372.6	)		(426.4	)		(376.4	)
	Change in cash pool at parent				(165.9	)		(70.4	)		(17.8	)
	Sales of investments and other assets				—			12.9			0.8
	(Increase) decrease in restricted funds				(0.6	)		15.5			(42.3	)

	Net cash used in investing activities				(539.1	)		(468.4	)		(435.7	)

Cash Flows From Financing Activities
	Net (repayment) issuance of short-term borrowings				(324.0	)		370.0			—
	Proceeds from issuance of long-term debt				—			400.0			623.2
	Repayment of long-term debt				(90.0	)		(350.0	)		(124.8	)
	Debt issuance costs				(0.5	)		(2.7	)		—
	Contribution from noncontrolling interest				8.0			—			—
	Preference stock dividends paid				(13.2	)		(13.2	)		(13.2	)
	Contribution from (distribution to) parent				315.9			(171.7	)		(106.0	)

	Net cash (used in) provided by financing activities				(103.8	)		232.4			379.2

Net Increase (Decrease) in Cash and Cash Equivalents					2.9			(6.9	)		6.7
Cash and Cash Equivalents at Beginning of Year					10.7			17.6			10.9

Cash and Cash Equivalents at End of Year				$	13.6		$	10.7		$	17.6

Other Cash Flow Information:
	Cash paid (received) during the year for:
		Interest (net of amounts capitalized)		$	136.9		$	126.6		$	126.3
		Income taxes		$	(250.9	)	$	(5.1	)	$	(37.6	)

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

Notes to Consolidated Financial Statements

1 Significant Accounting Policies

Nature of Our Business

Constellation Energy Group, Inc. (Constellation Energy) is an energy company that conducts its business through various subsidiaries organized around three business segments: a generation business (Generation), a customer supply business (NewEnergy), and Baltimore Gas and Electric Company (BGE). Our Generation and NewEnergy businesses are competitive providers of energy solutions for a variety of customers. BGE is a regulated electric transmission and distribution utility company and a regulated gas distribution utility company with a service territory that covers the City of Baltimore and all or part of ten counties in central Maryland. We describe our operating segments in Note 3.

This report is a combined report of Constellation Energy and BGE. References in this report to "we" and "our" are to Constellation Energy and its subsidiaries. References in this report to the "regulated business(es)" are to BGE.

Subsequent Event Policy

We evaluated events or transactions that occurred after December 31, 2009 for inclusion in these financial statements through February 26, 2010, the date these financial statements were issued.

Consolidation Policy

We use three different accounting methods to report our investments in our subsidiaries or other companies: consolidation, the equity method, and the cost method.

Consolidation

We use consolidation for two types of entities:

•: subsidiaries in which we own a majority of the voting stock and exercise control over the operations and policies of the company, and
•: variable interest entities (VIEs) for which we are the primary beneficiary, which means that we have a controlling financial interest in a VIE. We discuss our investments in VIEs in more detail in Note 4.

Consolidation means that we combine the accounts of these entities with our accounts. Therefore, our consolidated financial statements include our accounts, the accounts of our majority-owned subsidiaries that are not VIEs, and the accounts of VIEs for which we are the primary beneficiary. We have consolidated three VIEs for which we are the primary beneficiary. We eliminate all intercompany balances and transactions when we consolidate these accounts.

The Equity Method

We usually use the equity method to report investments, corporate joint ventures, partnerships, and affiliated companies where we hold approximately a 20% to 50% voting interest. Under the equity method, we report:

•: our interest in the entity as an investment in our Consolidated Balance Sheets, and
•: our percentage share of the earnings from the entity in our Consolidated Statements of Income (Loss). If our carrying value of the investment differs from our share of the investee's equity, we recognize this basis difference as an adjustment of our share of the investee's earnings.

The only time we do not use this method is if we can exercise control over the operations and policies of the company. If we have control, accounting rules require us to use consolidation.

The Cost Method

We usually use the cost method if we hold less than a 20% voting interest in an investment. Under the cost method, we report our investment at cost in our Consolidated Balance Sheets. We recognize income only to the extent that we receive dividends or distributions. The only time we do not use this method is when we can exercise significant influence over the operations and policies of the company. If we have significant influence, accounting rules require us to use the equity method.

Sale of Subsidiary Ownership Interests

We may sell portions of our ownership interests in a subsidiary's stock. Through 2008, we recorded any gains or losses in our Consolidated Statements of Income (Loss), as a component of non-operating income. Beginning in 2009, we treat sales of subsidiary stock as an equity transaction and do not recognize any gains or losses on the transaction as long as we retain a controlling financial interest.

When we sell ownership interests in our subsidiaries such that we do not retain a controlling financial interest, we deconsolidate that subsidiary. Upon deconsolidation, we recognize a gain or loss for the difference between the sum of the fair value of any consideration received and the fair value of our retained investment and the carrying amount of the former subsidiary's assets and liabilities.

On November 6, 2009, we completed the sale of a 49.99% membership interest in Constellation Energy Nuclear Group LLC and affiliates (CENG), our nuclear generation and operation business, to EDF Group and affiliates (EDF). As a result, we ceased to have a controlling financial interest in CENG and deconsolidated CENG at that time. We account for our retained interest in CENG using the equity method. See Note 2 for the gain recognized on our sale of a 49.99% interest in CENG to EDF.

Regulation of Electric and Gas Business

The Maryland Public Service Commission (Maryland PSC) and the Federal Energy Regulatory Commission (FERC) provide the final determination of the rates we charge our customers for our regulated businesses. Generally, we follow the same accounting policies and practices used by nonregulated companies for financial reporting under accounting principles generally accepted in the United States of America. However, sometimes the Maryland PSC or the FERC orders an accounting treatment

different from that used by nonregulated companies to determine the rates we charge our customers.

When this happens, we and BGE must defer (include as an asset or liability in the Consolidated Balance Sheets and exclude from Consolidated Statements of Income (Loss)) certain regulated business expenses and income as regulatory assets and liabilities. We and BGE have recorded these regulatory assets and liabilities in the Consolidated Balance Sheets.

We summarize and discuss regulatory assets and liabilities further in Note 6.

Use of Accounting Estimates

Management makes estimates and assumptions when preparing financial statements under accounting principles generally accepted in the United States of America. These estimates and assumptions affect various matters, including:

•: our revenues and expenses in our Consolidated Statements of Income (Loss) during the reporting periods,
•: our assets and liabilities in our Consolidated Balance Sheets at the dates of the financial statements, and
•: our disclosure of contingent assets and liabilities at the dates of the financial statements.

These estimates involve judgments with respect to numerous factors that are difficult to predict and are beyond management's control. As a result, actual amounts could materially differ from these estimates.

Reclassifications

In accordance with the requirements for the reporting of noncontrolling interests, which were effective on January 1, 2009 (see Accounting Standards Adopted section later in this note), we have separately presented:

•: "Net income (loss) 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 Consolidated Statements of Cash Flows.

We have also made the following reclassifications of prior year amounts for comparative purposes:

•: We have separately presented "Equity investment (losses) earnings" that were previously reported within "Nonregulated revenues" on our Consolidated Statements of Income (Loss).
•: We have separately presented "Accrued taxes" that was previously reported within "Accrued expenses" on our Consolidated Balance Sheets.
•: We have separately presented "Liability for uncertain tax positions" that was previously reported within "Other long-term liabilities" on BGE's Consolidated Balance Sheets.
•: We have separately presented "Electricity purchased for resale from affiliate" that was previously reported within "Electricity purchased for resale" on BGE's Consolidated Statements of Income.
•: We have separately presented "Operations and maintenance from affiliate" that was previously reported within "Operations and maintenance" on BGE's Consolidated Statements of Income.

Revenues

Sources of Revenue

We earn revenues from the following primary business activities:

•: sale of energy and energy-related products, including electricity, natural gas, and other commodities, in nonregulated markets;
•: providing standard offer service and delivering electricity and natural gas to customers of BGE;
•: trading energy and energy-related commodities; and,
•: providing other energy-related nonregulated products and services.

We report BGE's revenues from standard offer service and delivery of electricity and natural gas to its customers as "Regulated electric revenues" and "Regulated gas revenues" in our Consolidated Statements of Income (Loss). We report all other revenues as "Nonregulated revenues."

Revenues from nonregulated activities result from contracts or other sales that generally reflect market prices in effect at the time that we executed the contract or the sale occurred. BGE's revenues from regulated activities reflect provisions of orders of the Maryland PSC and the FERC. In certain cases, these orders require BGE to defer the difference between certain portions of its actual costs and the amount presently billable to customers. BGE records these differences as regulatory assets or liabilities, which we discuss in more detail in Note 6. We describe the effects of these orders on BGE's revenues below.

Regulated Electric

BGE provides market-based standard offer electric service to its residential, commercial, and industrial customers. BGE charges these customers standard offer service (SOS) rates that are designed to recover BGE's wholesale power supply costs and include an administrative fee consisting of a shareholder return component and an incremental cost component. Pursuant to Senate Bill 1, the energy legislation enacted in Maryland in June 2006, BGE suspended collection of the shareholder return component of the administrative fee for residential SOS service beginning January 1, 2007 for a 10-year period. However, under an order issued by the Maryland PSC in May 2007, as of June 1, 2007, BGE reinstated collection of the residential return component of the SOS administration charge and began providing all residential electric customers a credit for the return component of the administrative charge. As part of the 2008 Maryland settlement agreement, which is discussed in more detail in Note 2, BGE resumed collection of the shareholder return portion of the residential standard offer service administrative charge from June 1, 2008 through May 31, 2010 without having to rebate it to all residential electric customers. BGE will cease collecting the residential

shareholder return component again from June 1, 2010 through December 31, 2016. Senate Bill 1 imposed a 15% rate cap for BGE residential electric customers from July 1, 2006 until May 31, 2007 and gave customers the option to further delay paying full market rates until January 1, 2008.

As part of the October 30, 2009 order from the Maryland PSC approving our transaction with EDF, BGE may file an electric distribution case at any time beginning in January 2010 and may not file a subsequent electric distribution rate case until January 2011. Any rate increase in the first electric distribution rate case will be capped at 5%.

Regulated Gas

BGE charges its gas customers for the natural gas they purchase from BGE using "gas cost adjustment clauses." Under these clauses, BGE defers the difference between certain of its actual costs related to the gas commodity and what it collects from customers under the commodity charge in a given period for evaluation under a market-based rates incentive mechanism. For each period subject to that mechanism, BGE compares its actual cost of gas to a market index (a measure of the market price of gas for that period) and shares the difference equally between shareholders and customers through an adjustment to the price of gas service in future periods. This sharing mechanism excludes fixed-price contracts which the Maryland PSC requires BGE to procure for at least 10%, but not more than 20%, of forecasted system supply requirements for the November through March period. As a condition to the October 30, 2009 order from the Maryland PSC approving our transaction with EDF, BGE may file a gas distribution case at any time beginning in January 2010 and may not file a subsequent gas distribution rate case until January 2011.

Selection of Accounting Treatment

We determine the appropriate accounting treatment for recognizing revenues based on the nature of the transaction, governing accounting standards and, where required, by applying judgment as to the most transparent presentation of the economics of the underlying transactions. We utilize two primary accounting treatments to recognize and report revenues in our results of operations:

•: accrual accounting, including hedge accounting, and
•: mark-to-market accounting.

We describe each of these accounting treatments below.

Accrual Accounting

Under accrual accounting, we record revenues in the period when we deliver energy commodities or products, render services, or settle contracts. We generally use accrual accounting to recognize revenues for our sales of electricity, gas, coal, and other commodities as part of our physical delivery activities. We enter into these sales transactions using a variety of instruments, including non-derivative agreements, derivatives that qualify for and are designated as normal purchases and normal sales (NPNS) of commodities that will be physically delivered, sales to BGE's customers under regulated service tariffs, and spot-market sales, including settlements with independent system operators. We discuss the NPNS election later in this Note under Derivatives and Hedging Activities.

However, we also use mark-to-market accounting rather than accrual accounting for recognizing revenue on our competitive retail gas customer supply activities and other physical commodity derivatives if we have not designated those contracts as NPNS.

We record accrual revenues from sales of products or services on a gross basis at the contract, tariff, or spot price because we are a principal to the transaction. Accrual revenues also include certain other gains and losses that relate to these activities or for which accrual accounting is required.

We include in accrual revenues the effects of hedge accounting for derivative contracts that qualify as hedges of our sales of products or services. Substantially all of the derivatives that we designate as hedges are cash flow hedges. We recognize the effective portion of hedge gains or losses in revenues during the same period in which we record the revenues from the hedged transaction. We record any hedge ineffectiveness in revenues when it occurs. We discuss our hedge accounting policy in the Derivatives and Hedging Activities section later in this Note.

We may make or receive cash payments at the time we assume previously existing power sale agreements for which the contract price differs from current market prices. We also may designate a derivative as NPNS after its inception. We recognize the value of these derivatives in our Consolidated Balance Sheets as an "Unamortized energy contract" asset or liability. We amortize these assets and liabilities into revenues based on the present value of the underlying cash flows provided by the contracts.

The following table summarizes the primary components of accrual revenues:

	Activity

Component of Accrual Revenues	Nonregulated Physical Energy Delivery	Regulated Electricity and Gas Sales	Other Nonregulated Products and Services

Gross amounts receivable for sales of products or services based on contract, tariff, or spot price	X	X	X

Reclassification of net gains/losses on cash flow hedges from AOCI	X

Ineffective portion of net gains/losses on cash flow hedges	X

Amortization of acquired energy contract assets or liabilities	X

Recovery or refund of deferred SOS and gas cost adjustment clause regulatory assets/liabilities		X

Mark-to-Market Accounting

We record revenues using the mark-to-market method of accounting for transactions under derivative contracts for which we are not permitted, or do not elect, to use accrual accounting or hedge accounting. These mark-to-market transactions primarily relate to our risk management and trading activities, our competitive retail gas customer supply activities, and economic hedges of other accrual activities. Mark-to-market revenues include:

•: origination gains or losses on new transactions,
•: unrealized gains and losses from changes in the fair value of open contracts,
•: net gains and losses from realized transactions, and
•: changes in valuation adjustments.

Under the mark-to-market method of accounting, we record any inception fair value of these contracts as derivative assets and liabilities at the time of contract execution. We record subsequent changes in the fair value of these derivative assets and liabilities on a net basis in "Nonregulated revenues" in our Consolidated Statements of Income (Loss). We discuss our mark-to-market accounting policy in the Derivatives and Hedging Activities section later in this Note.

Fuel and Purchased Energy Expenses

Sources of Fuel and Purchased Energy Expenses

We incur fuel and purchased energy costs for:

•: the fuel we use to generate electricity at our power plants,
•: purchases of electricity from others, and
•: purchases of natural gas, coal, and other fuel types that we resell.

We report these costs in "Fuel and purchased energy expenses" in our Consolidated Statements of Income (Loss). We also include certain fuel-related direct costs, such as ancillary services purchased from independent system operators, transmission costs, brokerage fees, and freight costs in the same category in our Consolidated Statements of Income (Loss).

Fuel and purchased energy costs from nonregulated activities result from contracts or other purchases that generally reflect market prices in effect at the time that we executed the contract or the purchase occurred. BGE's costs of electricity and gas for resale under regulated activities reflect actual costs of purchases, adjusted to reflect provisions of orders of the Maryland PSC and the FERC. In certain cases, these orders require BGE to defer the difference between certain portions of its actual costs and the amount presently billable to customers. BGE records these differences as regulatory assets or liabilities, which we discuss in more detail in Note 6. We describe the effects of these orders on BGE's fuel and purchased energy expense below.

Regulated Electric

BGE provides market-based standard offer electric service to its residential, commercial, and industrial customers. BGE charges these customers SOS rates that are designed to recover BGE's wholesale power supply costs and include an administrative fee consisting of a shareholder return component and an incremental cost component.

BGE defers the difference between certain of its actual costs related to the electric commodity and what it collects from customers under the commodity charge portion of SOS rates in a given period. BGE either bills or refunds its customers the difference in the future and includes amortization of the deferred amounts in fuel and purchased energy expense. Therefore, BGE's fuel and purchased energy expense approximates the amount of the related commodity charge included in revenues for the period, reflecting actual costs adjusted for the effects of the regulatory deferral mechanism.

Regulated Gas

BGE charges its gas customers for the natural gas they purchase from BGE using "gas cost adjustment clauses." These clauses include a market-based rates incentive mechanism that requires BGE to compare its actual cost of gas to a market index (a measure of the market price of gas for that period) and share the difference equally between shareholders and customers. This sharing mechanism excludes fixed-price contracts which the Maryland PSC requires BGE to procure for at least 10%, but not more than 20%, of forecasted system supply requirements for the November through March period.

BGE defers the difference between the portion of its actual gas commodity costs subject to the market-based rates incentive mechanism and what it collects from customers under the commodity charge in a given period. BGE either bills or refunds its customers the portion of this difference to which they are entitled through an adjustment to the price of gas service in future periods and includes amortization of the deferred amounts in fuel and purchased energy expense. Therefore, BGE's fuel and purchased energy expense approximates the amount of the related commodity charge included in revenues for the period, reflecting actual gas costs adjusted for the effects of the regulatory deferral mechanism.

Selection of Accounting Treatment

We determine the appropriate accounting treatment for fuel and purchased energy costs based on the nature of the transaction, governing accounting standards and, where required, by applying judgment as to the most transparent presentation of the economics of the underlying transactions. We utilize two primary accounting treatments to recognize and report these costs in our Consolidated Statements of Income (Loss):

•: accrual accounting, including hedge accounting, and
•: mark-to-market accounting.

We describe each of these accounting treatments below.

Accrual Accounting

Under accrual accounting, we record fuel and purchased energy expenses in the period when we consume the fuel or purchase the electricity or other commodity for resale. We use accrual accounting to recognize substantially all of our fuel and purchased energy expenses as part of our physical delivery activities. We make these purchases using a variety of instruments, including non-derivative transactions, derivatives that qualify for and are designated as NPNS, and spot-market purchases, including settlements with independent system operators. These transactions also include power purchase agreements that qualify as operating leases, for which fuel and purchased energy consists of both fixed capacity payments and variable payments based on the actual output of the plants. We discuss the NPNS election later in this Note under Derivatives and Hedging Activities.

In certain cases, we use mark-to-market accounting rather than accrual accounting for recognizing fuel and purchased energy expenses on physical commodity derivatives if we have not designated those contracts as NPNS.

We include in accrual fuel and purchased energy expenses the effects of hedge accounting for derivative contracts that qualify as hedges of our fuel and purchased energy costs. Substantially all of the derivatives that we designate as hedges are cash flow hedges. We recognize the effective portion of hedge gains or losses in fuel and purchased energy expenses during the same period in which we record the costs from the hedged transaction. We record any hedge ineffectiveness in expense when it occurs. We discuss our use of hedge accounting in the Derivatives and Hedging Activities section later in this Note.

We may make or receive cash payments at the time we assume previously existing power purchase agreements or other contracts for which the contract price differs from current market prices. We recognize the cash payment at inception in our Consolidated Balance Sheets as an "Unamortized energy contract" asset or liability. We amortize these assets and liabilities into fuel and purchased energy expenses based on the present value of the underlying cash flows provided by the contracts.

The following table summarizes the primary components of accrual purchased fuel and energy expense:

	Activity

Component of Accrual Fuel and Purchased Energy Expense	Nonregulated Physical Energy Delivery	Regulated Electricity and Gas Sales	Other Nonregulated Products and Services

Actual costs of fuel and purchased energy	X	X	X

Reclassification of net gains/losses on cash flow hedges from AOCI	X

Ineffective portion of net gains/losses on cash flow hedges	X

Amortization of acquired energy contract assets or liabilities	X

Deferral or amortization of deferred SOS and gas cost adjustment clause regulatory assets/liabilities		X

Mark-to-Market Accounting

We record fuel and purchased energy expenses using the mark-to-market method of accounting for transactions under derivative contracts for which we are not permitted, or do not elect, to use accrual accounting or hedge accounting in order to match the earnings impacts of those activities to the greatest extent permissible. These mark-to-market transactions primarily relate to our physical international coal purchase contracts. Mark-to-market costs include:

•: unrealized gains and losses from changes in the fair value of open contracts,
•: net gains and losses from realized transactions, and
•: changes in valuation adjustments.

Under the mark-to-market method of accounting, we record any inception fair value of these contracts as derivative assets and liabilities at the time of contract execution. We record subsequent changes in the fair value of these derivative assets and liabilities on a net basis in "Fuel and purchased energy expense" in our Consolidated Statements of Income (Loss). We discuss our mark-to-market accounting policy in the Derivatives and Hedging Activities section later in this Note.

Derivatives and Hedging Activities

We engage in electricity, natural gas, coal, emission allowances, and other commodity marketing and risk management activities

as part of our NewEnergy business. In order to manage our exposure to commodity price fluctuations, we enter into energy and energy-related derivative contracts traded in the over-the-counter markets or on exchanges. These contracts include:

•: forward physical purchase and sales contracts,
•: futures contracts,
•: financial swaps, and
•: option contracts.

We use interest rate swaps to manage our interest rate exposures associated with new debt issuances, to manage our exposure to fluctuations in interest rates on variable rate debt, and to optimize the mix of fixed and floating-rate debt. We use foreign currency swaps to manage our exposure to foreign currency exchange rate fluctuations.

Selection of Accounting Treatment

We account for derivative instruments and hedging activities in accordance with several possible accounting treatments for derivatives that meet all of the requirements of the accounting standard. Mark-to-market is 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 other elective accounting treatments must meet specific, restrictive criteria, both at the time of designation and on an ongoing basis.

The following are permissible accounting treatments for derivatives:

•: mark-to-market,
•: cash flow hedge,
•: fair value hedge, and
•: NPNS.

Each of the accounting treatments for derivatives affects our financial statements in substantially different ways as summarized below:

	Recognition and Measurement

Accounting Treatment	Recognition and Measurement
Accounting Treatment	Balance Sheet	Income Statement

Mark-to-market	• Derivative asset or liability recorded at fair value	• Changes in fair value recognized in earnings

Cash flow hedge	• Derivative asset or liability recorded at fair value • Effective changes in fair value recognized in accumulated other comprehensive income	• Ineffective changes in fair value recognized in earnings • Amounts in accumulated other comprehensive income reclassified to earnings when the hedged forecasted transaction affects earnings or becomes probable of not occurring

Fair value hedge	• Derivative asset or liability recorded at fair value • Book value of hedged asset or liability adjusted for changes in its fair value	• Changes in fair value recognized in earnings • Changes in fair value of hedged asset or liability recognized in earnings

NPNS (accrual)	• Fair value not recorded • Accounts receivable or accounts payable recorded when derivative settles	• Changes in fair value not recognized in earnings • Revenue or expense recognized in earnings when underlying physical commodity is sold or consumed

Mark-to-Market

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

•: our competitive 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.

We may record origination gains associated with derivatives subject to mark-to-market accounting. Origination gains represent the initial fair value of certain structured transactions that our portfolio management and trading operation executes to meet the risk management needs of our customers. Historically, transactions that result in origination gains have been unique and resulted in individually significant gains from a single transaction. We generally recognize origination gains when we are able to obtain observable market data to validate that the initial fair value of the contract differs from the contract price.

Cash Flow Hedge

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 (Generation and NewEnergy businesses) activities because accrual accounting more closely aligns the timing of earnings recognition, cash flows, and the underlying business activities. We only use fair value hedge accounting on a limited basis.

We use regression analysis to determine whether we expect a derivative to be highly effective as a cash flow hedge prior to electing hedge accounting and also to determine whether all derivatives designated as cash flow hedges have been effective. We perform these effectiveness tests prior to designation for all new hedges and on a daily basis for all existing hedges. We calculate the actual amount of ineffectiveness on our cash flow hedges using the "dollar offset" method, which compares changes in the expected cash flows of the hedged transaction to changes in the value of expected cash flows from the hedge.

We discontinue hedge accounting when our effectiveness tests indicate that a derivative is no longer highly effective as a hedge; when the derivative expires or is sold, terminated or exercised; when the hedged item matures, is sold or repaid; or when we determine that the occurrence of the hedged forecasted transaction is not probable. When we discontinue hedge accounting but continue to hold the derivative, we begin to apply mark-to-market accounting at that time.

NPNS

elect NPNS classification for a given contract, we do not subsequently change the election and treat the contract as a derivative using mark-to-market or hedge accounting. However, if we were to determine that a transaction designated as NPNS no longer qualified for the NPNS election, we would have to record the fair value of that contract on the balance sheet at that time and immediately recognize that amount in earnings.

Fair Value

We record mark-to-market and hedge derivatives at fair value, which represents an exit price for the asset or liability from the perspective of a market participant. An exit price is the price at which a market participant could sell an asset or transfer a liability to an unrelated party. While some of our derivatives relate to commodities or instruments for which quoted market prices are available from external sources, many other commodities and related contracts are not actively traded. Additionally, some contracts include quantities and other factors that vary over time. As a result, often we must use modeling techniques to estimate expected future market prices, contract quantities, or both in order to determine fair value.

The prices, quantities, and other factors we use to determine fair value reflect management's best estimates of inputs a market participant would consider. We record valuation adjustments to reflect uncertainties associated with estimates inherent in the determination of fair value that are not incorporated in market price information or other market-based estimates we use to determine fair value. To the extent possible, we utilize market-based data together with quantitative methods for both measuring the uncertainties for which we record valuation adjustments and determining the level of such adjustments and changes in those levels.

The valuation adjustments we record include the following:

•: Close-out adjustment—the estimated cost to close out or sell to a third party open mark-to-market positions. This valuation adjustment has the effect of valuing purchase contracts at the bid price and sale contracts at the offer price.
•: Unobservable input valuation adjustment—necessary when we determine fair value for derivative positions using internally developed models that use unobservable inputs due to the absence of observable market information.
•: Credit spread adjustment—necessary to reflect the credit-worthiness of each customer (counterparty).

We discuss derivatives and hedging activities as well as how we determine fair value in detail in Note 13.

Balance Sheet Netting

We often transact with counterparties under master agreements and other arrangements that provide us with a right of setoff of amounts due to us and from us in the event of bankruptcy or default by the counterparty. We report these transactions on a net basis in our Consolidated Balance Sheets.

We apply balance sheet netting separately for current and noncurrent derivatives. Current derivatives represent the portion of derivative contract cash flows expected to occur within 12 months, and noncurrent derivatives represent the portion of those cash flows expected to occur beyond 12 months. Within each of these categories, we net all amounts due to and from each counterparty under master agreements into a single net asset or liability. We include fair value cash collateral amounts received and posted in determining this net asset and liability amount.

Unamortized Energy Assets and Liabilities

Unamortized energy contract assets and liabilities represent the remaining unamortized balance of non-derivative energy contracts that we acquired, certain contracts which no longer qualify as derivatives due to the absence of a liquid market, or derivatives designated as NPNS that we had previously recorded as "Derivative assets or liabilities." The initial amount recorded represents the fair value of the contract at the time of acquisition or designation, and the balance is amortized over the life of the contract in relation to the present value of the underlying cash flows. The amortization of these values is discussed in the Revenues and Fuel and Purchased Energy Expenses sections of this Note.

Credit Risk

Credit risk is the loss that may result from counterparty non-performance. We are exposed to credit risk, primarily through our NewEnergy business. We use credit policies to manage our credit risk, including utilizing an established credit approval process, daily monitoring of counterparty limits, employing credit mitigation measures such as margin, collateral (cash or letters of credit) or prepayment arrangements, and using master netting agreements. We measure credit risk as the replacement cost for open energy commodity and derivative positions (both mark-to-market and accrual) plus amounts owed from counterparties for settled transactions. The replacement cost of open positions represents unrealized gains, less any unrealized losses where we have a legally enforceable right of setoff.

Electric and gas utilities, municipalities, cooperatives, generation owners, coal producers, and energy marketers comprise the majority of counterparties underlying our assets from our wholesale marketing and risk management activities. We held cash collateral from these counterparties totaling $95.2 million as of December 31, 2009 and $258.3 million as of December 31, 2008. These amounts are included in "Customer deposits and collateral" in our Consolidated Balance Sheets.

We consider a significant concentration of credit risk to be any single obligor or counterparty whose concentration exceeds 10% of our total credit exposure. As of December 31, 2009, we only had one significant counterparty concentration, CENG, which comprised 25% of our total credit exposure. This exposure is primarily related to the power purchase agreement that we executed with CENG which has a value of $0.8 billion, which is recorded on our balance sheet in "Unamortized energy contract assets." However, no collection of counterparties based in a single country other than the United States comprised more than 10% of the total exposure of our total credit exposure.

Equity Investment Earnings

We include equity in earnings from our investments in qualifying facilities and power projects, joint ventures, and Constellation Energy Partners LLC (CEP) in "Equity Investment (Losses) Earnings" in our Consolidated Statements of Income (Loss) in the period they are earned. "Equity Investment (Losses) Earnings" also includes any adjustments to amortize the difference, if any, except for goodwill, between our cost in an equity method investment and our underlying equity in net assets of the investee at the date of investment.

We consider our investments in generation-related qualifying facilities, power projects, and joint ventures to be integral to our operations.

Taxes

We summarize our income taxes in Note 10. BGE and our other subsidiaries record their allocated share of our consolidated federal income tax liability using the percentage complementary method specified in U.S. income tax regulations. As you read this section, it may be helpful to refer to Note 10.

Income Tax Expense

We have two categories of income tax expense—current and deferred. We describe each of these below:

•: current income tax expense consists solely of regular tax less applicable tax credits, and
•: deferred income tax expense is equal to the changes in the net deferred income tax liability, excluding amounts charged or credited to accumulated other comprehensive income. Our deferred income tax expense is increased or reduced for changes to the "Income taxes recoverable through future rates (net)" regulatory asset (described below) during the year.

Tax Credits

We defer the investment tax credits associated with our regulated business, assets previously held by our regulated business, and any investment tax credits that are convertible to cash grants in our Consolidated Balance Sheets. The investment tax credits are amortized evenly to income over the life of each property. We reduce current income tax expense in our Consolidated Statements of Income (Loss) for the investment tax credits that are not convertible to cash grants and other tax credits associated with our nonregulated businesses.

Through December 31, 2007, we held certain investments in facilities that manufactured solid synthetic fuel produced from coal as defined under the Internal Revenue Code for which we claimed tax credits on our Federal income tax return. Because the federal tax credit for synthetic fuel produced from coal expired on December 31, 2007, these facilities ceased fuel production on that date. We recognized the tax benefit of these credits in our Consolidated Statements of Income (Loss) when we believed it was highly probable that the credits will be sustained.

Deferred Income Tax Assets and Liabilities

We must report some of our revenues and expenses differently for our financial statements than for income tax return purposes. The tax effects of the temporary differences in these items are reported as deferred income tax assets or liabilities in our Consolidated Balance Sheets. We measure the deferred income tax assets and liabilities using income tax rates that are currently in effect.

A portion of our total deferred income tax liability relates to our regulated business, but has not been reflected in the rates we charge our customers. We refer to this portion of the liability as "Income taxes recoverable through future rates (net)." We have recorded that portion of the net liability as a regulatory asset in our Consolidated Balance Sheets. We discuss this further in Note 6.

State and Local Taxes

State and local income taxes are included in "Income taxes" in our Consolidated Statements of Income (Loss).

Taxes Other Than Income Taxes

Taxes other than income taxes primarily include property and gross receipts taxes along with franchise taxes and other non-income taxes, surcharges, and fees.

BGE and our NewEnergy business collect certain taxes from customers such as sales and gross receipts taxes, along with other taxes, surcharges, and fees that are levied by state or local governments on the sale or distribution of gas and electricity. Some of these taxes are imposed on the customer and others are imposed on BGE and our NewEnergy business. Where these taxes, such as sales taxes, are imposed on the customer, we account for these taxes on a net basis with no impact to our Consolidated Statements of Income (Loss). However, where these taxes, such as gross receipts taxes or other surcharges or fees, are imposed on BGE or our NewEnergy business, we account for these taxes on a gross basis. Accordingly, we recognize revenues for these taxes collected from customers along with an offsetting tax expense, which are both included in our Consolidated Statements of Income (Loss). The taxes, surcharges, or fees that are included in revenues were as follows:

Year Ended December 31,	2009		2008		2007


	(In millions)
Constellation Energy (including BGE)	$	106.8	$	111.7	$	113.4
BGE		76.8		73.2		77.0

Unrecognized Tax Benefits

We adopted guidance related to the accounting for uncertainty in income taxes on January 1, 2007.

We recognize in our financial statements the effects of uncertain tax positions if these positions meet a "more-likely-than-not" threshold. For those uncertain tax positions that we have recognized in our financial statements, we establish liabilities to reflect the portion of those positions we cannot conclude are "more-likely-than-not" to be realized upon ultimate settlement. These are referred to as liabilities for unrecognized tax benefits. We recognize interest and penalties related to unrecognized tax benefits in "Income tax expense" in our Consolidated Statements of Income (Loss).

We discuss our unrecognized tax benefits in more detail in Note 10.

Earnings Per Share

Basic earnings per common share (EPS) is computed by dividing net income (loss) attributable to common stock by the weighted-average number of common shares outstanding for the year. 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 primarily 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 as follows:

Year Ended December 31,	2009


	(In millions)
Non-dilutive stock options		5.1	2.6	—
Dilutive common stock equivalent shares		1.0	5.5	2.3

As a result of the Company incurring a loss for the year ended December 31, 2008, diluted common stock equivalent shares were not included in calculating diluted EPS.

We issued to MidAmerican Energy Holdings Company (MidAmerican) 19,897,322 shares of Constellation Energy's common stock upon the conversion of the Series A Preferred Stock, which occurred upon the termination of the merger agreement with MidAmerican on December 17, 2008. These additional shares impacted our earnings per share for 2009.

Stock-Based Compensation

Under our long-term incentive plans, we have granted stock options, performance-based units, service-based units, performance and service-based restricted stock, and equity to officers, key employees, and members of the Board of Directors. We discuss these awards in more detail in Note 14.

We recognize compensation expense for all equity-based compensation awards issued to employees that are expected to vest. Equity-based compensation awards include stock options, restricted stock, and any other share-based payments. We recognize compensation cost ratably or in tranches (depending if the award has cliff or graded vesting) over the period during which an employee is required to provide service in exchange for the award, which is typically a one to five-year period. We use a forfeiture assumption based on historical experience to estimate the number of awards that are expected to vest during the service period, and ultimately true-up the estimated expense to the actual expense associated with vested awards. We estimate the fair value of stock option awards on the date of grant using the Black-Scholes option-pricing model and we remeasure the fair value of liability awards each reporting period. We do not capitalize any portion of our stock-based compensation.

Cash and Cash Equivalents

All highly liquid investments with original maturities of three months or less are considered cash equivalents.

Accounts Receivable and Allowance for Uncollectibles

Accounts receivable, which includes cash collateral posted in our margin account with third party brokers, are stated at the historical carrying amount net of write-offs and allowance for uncollectibles. We establish an allowance for uncollectibles based on our expected exposure to the credit risk of customers based on a variety of factors.

Materials, Supplies, and Fuel Stocks

We record our fuel stocks, emissions credits, renewable energy credits, coal held for resale, and materials and supplies at the lower of cost or market. We determine cost using the average cost method for our entire inventory.

Restricted Cash

At December 31, 2009, our restricted cash primarily includes cash at one of our consolidated variable interest entities, proceeds from financing for the acquisition, construction, installation and equipping of certain sewage and solid waste disposal facilities at our Brandon Shores coal-fired generating plant in Maryland and BGE's funds restricted for the repayment of the rate stabilization bonds. At December 31, 2008, restricted cash also included the proceeds that we received on December 17, 2008 from issuance of the Series B Preferred Stock to EDF. These proceeds were restricted for payment of the 14% Senior Note that was held by MidAmerican. We used these proceeds to repay the 14% Senior Note in January 2009.

As of December 31, 2009 and 2008, BGE's restricted cash primarily represented funds restricted for the repayment of the rate stabilization bonds. We discuss the rate stabilization bonds in more detail in Note 9.

Financial Investments

In Note 4, we summarize the financial investments that are in our Consolidated Balance Sheets.

We report our debt and equity securities at fair value, and we use either specific identification or average cost to determine their cost for computing realized gains or losses.

Available-for-Sale Securities

We classify our investments in trust assets securing certain executive benefits that are classified as available-for-sale securities.

We include any unrealized gains (losses) on our available-for-sale securities in "Accumulated other comprehensive loss" in our Consolidated Statements of Common Shareholders' Equity and Comprehensive Income.

Evaluation of Assets for Impairment and Other Than Temporary Decline in Value

Long-Lived Assets

We evaluate certain assets that have long lives (for example, generating property and equipment and real estate) to determine if they are impaired when certain conditions exist. We test our long-lived assets and proved gas properties for recoverability

whenever events or changes in circumstances indicate that their carrying amount may not be recoverable.

We determine if long-lived assets and proved gas properties are impaired by comparing their undiscounted expected future cash flows to their carrying amount in our accounting records. We record an impairment loss if the undiscounted expected future cash flows are less than the carrying amount of the asset. Cash flows for long-lived assets are determined at the lowest level for which identifiable cash flows are largely independent of the cash flows of other assets and liabilities. Proven gas properties' cash flows are determined at the field level. Undiscounted expected future cash flows include risk-adjusted probable and possible reserves. We are also required to evaluate our equity-method and cost-method investments (for example, CENG and partnerships that own power projects) for impairment. The standard for determining whether an impairment must be recorded is whether the investment has experienced a loss in value that is considered an "other than a temporary" decline.

We evaluate unproved gas producing properties at least annually to determine if they are impaired. Impairment for unproved property occurs if there are no firm plans to continue drilling, lease expiration is at risk, or historical experience necessitates a valuation allowance.

We use our best estimates in making these evaluations and consider various factors, including forward price curves for energy, fuel costs, legislative initiatives, and operating costs. However, actual future market prices and project costs could vary from those used in our impairment evaluations, and the impact of such variations could be material.

Investments

We evaluate our equity-method and cost-method investments (for example, CENG, UniStar Nuclear Energy, LLC (UNE), CEP and partnerships that own power projects) to determine whether or not they are impaired. The standard for determining whether an impairment must be recorded is whether the investment has experienced an "other than a temporary" decline in value.

Additionally, if the projects in which we hold these investments recognize an impairment, we would record our proportionate share of that impairment loss and would evaluate our investment for an other than temporary decline in value.

We continuously monitor issues that potentially could impact future profitability of our equity-method investments that own geothermal, coal, hydroelectric, fuel processing projects, as well as our equity investments in our nuclear joint ventures and CEP. These issues include environmental and legislative initiatives as well as events that will impact the viability of new nuclear development.

Debt and Equity Securities

We determine whether a decline in fair value of a debt or equity investment below book value is other than temporary. If we determine that the decline in fair value is other than temporary, we write-down the cost basis of the investment to fair value as a new cost basis.

Goodwill and Intangible Assets

Goodwill is the excess of the purchase price of an acquired business over the fair value of the net assets acquired. We do not amortize goodwill. We evaluate goodwill for impairment at least annually or more frequently if events and circumstances indicate the business might be impaired. Goodwill is impaired if the carrying value of the business exceeds fair value. Annually, we estimate the fair value of the businesses we have acquired using techniques similar to those used to estimate future cash flows for long-lived assets as previously discussed. If the estimated fair value of the business is less than its carrying value, an impairment loss is required to be recognized to the extent that the carrying value of goodwill is greater than its fair value. We amortize intangible assets with finite lives. We discuss the changes in our goodwill and intangible assets in more detail in Note 5.

Property, Plant and Equipment, Depreciation, Depletion, Amortization, and Accretion of Asset Retirement Obligations

We report our property, plant and equipment at its original cost, unless impaired.

Original cost includes:

•: material and labor,
•: contractor costs, and
•: construction overhead costs, financing costs, and costs for asset retirement obligations (where applicable).

We own an undivided interest in the Keystone and Conemaugh electric generating plants in Western Pennsylvania, as well as in the Conemaugh substation and transmission line that transports the plants' output to the joint owners' service territories. Our ownership interests in these plants are 20.99% in Keystone and 10.56% in Conemaugh. These ownership interests represented a net investment of $339.6 million at December 31, 2009 and $285.1 million at December 31, 2008. Each owner is responsible for financing its proportionate share of the plants' working funds. Working funds are used for operating expenses and capital expenditures. Operating expenses related to these plants are included in "Operating expenses" in our Consolidated Statements of Income (Loss). Capital costs related to these plants are included in "Nonregulated property, plant and equipment" in our Consolidated Balance Sheets.

The "Nonregulated property, plant and equipment" in our Consolidated Balance Sheets includes nonregulated generation construction work in progress of $685.1 million at December 31, 2009 and $1,230.8 million at December 31, 2008.

When we retire or dispose of property, plant and equipment, we remove the asset's cost from our Consolidated Balance Sheets. We charge this cost to accumulated depreciation for assets that were depreciated under the group, straight-line method. This includes regulated property, plant and equipment and nonregulated generating assets. For all other assets, we remove the accumulated depreciation and amortization amounts from our Consolidated Balance Sheets and record any gain or loss in our Consolidated Statements of Income (Loss).

The costs of maintenance and certain replacements are charged to "Operating expenses" in our Consolidated Statements of Income (Loss) as incurred.

Our oil and gas exploration and production activities consist of working interests in gas producing fields. We account for these activities under the successful efforts method of accounting. Acquisition, development, and exploration costs are capitalized. Costs of drilling exploratory wells are initially capitalized and later charged to expense if reserves are not discovered or deemed not to be commercially viable. Other exploratory costs are charged to expense when incurred.

Depreciation and Depletion Expense

We compute depreciation for our generating, electric transmission and distribution, and gas distribution facilities. We compute depletion for our oil and gas exploitation and production activities. Depreciation and depletion are determined using the following methods:

•: the group straight-line method using rates averaging approximately 2.3% per year for our generating assets,
•: the group straight-line method, approved by the Maryland PSC, applied to the average investment, adjusted for anticipated costs of removal less salvage, in classes of depreciable property based on an average rate of approximately 3.2% per year for our regulated business, or
•: the units-of-production method over the remaining life of the estimated proved reserves at the field level for acquisition costs and over the remaining life of proved developed reserves at the field level for development costs. The estimates for gas reserves are based on internal calculations.

Other assets are depreciated primarily using the straight-line method and the following estimated useful lives:

Asset		Estimated Useful Lives


Building and improvements		5 - 50 years
Office equipment and furniture		3 - 20 years
Transportation equipment		5 - 15 years
Computer software		3 - 10 years

Amortization Expense

Amortization is an accounting process of reducing an asset amount in our Consolidated Balance Sheets over a period of time that approximates the useful life of the related item. When we reduce amounts in our Consolidated Balance Sheets, we increase amortization expense in our Consolidated Statements of Income (Loss). We discuss the types of assets that we amortize and the periods over which we amortize them in more detail in Note 5.

Accretion Expense

We recognize an estimated liability for legal obligations and legal obligations conditional upon a future event associated with the retirement of tangible long-lived assets. Our conditional asset retirement obligations relate primarily to asbestos removal at certain of our generating facilities.

Prior to November 6, 2009, substantially all of our total asset retirement obligation was associated with the decommissioning of our nuclear power plants—Calvert Cliffs Nuclear Power Plant (Calvert Cliffs), Nine Mile Point Nuclear Station (Nine Mile Point) and R. E. Ginna Nuclear Power Plant (Ginna). Upon the close of the transaction with EDF on November 6, 2009, we deconsolidated CENG and removed the asset retirement obligations associated with these nuclear power plants from our Consolidated Balance Sheets. Our remaining asset retirement obligations are associated with our other generating facilities and certain other long-lived assets.

From time to time, we will perform studies to update our asset retirement obligations. We record a liability when we are able to reasonably estimate the fair value of any future legal obligations associated with retirement that have been incurred and capitalize a corresponding amount as part of the book value of the related long-lived assets.

The increase in the capitalized cost is included in determining depreciation expense over the estimated useful lives of these assets. Since the fair value of the asset retirement obligations is determined using a present value approach, accretion of the liability due to the passage of time is recognized each period to "Accretion of asset retirement obligations" in our Consolidated Statements of Income (Loss) until the settlement of the liability. We record a gain or loss when the liability is settled after retirement for any difference between the accrued liability and actual costs. The change in our "Asset retirement obligations" liability during 2009 was as follows:



	(In millions)
Liability at January 1, 2009	$	987.3
Accretion expense		62.3
Liabilities incurred		0.2
Liabilities settled		(1.0	)
Revisions to cash flows		5.8
Deconsolidation of CENG		(1,025.2	)
Other		(0.1	)

Liability at December 31, 2009	$	29.3

Nuclear Fuel

Through November 6, 2009, we amortized the cost of nuclear fuel, including the quarterly fees we pay to the Department of Energy (DOE) for the future disposal of spent nuclear fuel, based on the energy produced over the life of the fuel. These fees were based on the kilowatt-hours of electricity sold. We report the amortization expense for nuclear fuel in "Fuel and purchased energy expenses" in our Consolidated Statements of Income (Loss).

Capitalized Interest and Allowance for Funds Used During Construction

Capitalized Interest

Our nonregulated businesses capitalize interest costs for costs incurred to finance our power plant construction projects, real estate developed for internal use, and other capital projects.

Allowance for Funds Used During Construction (AFC)

BGE finances its construction projects with borrowed funds and equity funds. BGE is allowed by the Maryland PSC and the FERC to record the costs of these funds as part of the cost of construction projects in its Consolidated Balance Sheets. BGE does this through the AFC, which it calculates using rates authorized by the Maryland PSC and the FERC. BGE bills its customers for the AFC plus a return after the utility property is placed in service.

The AFC rates are 9.4% for electric distribution plant, 8.8% for electric transmission plant, 8.5% for gas plant, and 9.1% for common plant. BGE compounds AFC annually.

Long-Term Debt and Credit Facilities

We defer all costs related to the issuance of long-term debt and credit facilities. These costs include underwriters' commissions, discounts or premiums, other costs such as external legal, accounting, and regulatory fees, and printing costs. We amortize costs related to long-term debt into interest expense over the life of the debt. We amortize costs related to credit facilities to other income (expense) over the terms of the facilities.

In addition to the fees that are paid upfront for credit facilities, we also incur ongoing fees related to these facilities. We record the ongoing fees in other income (expense), and we record interest incurred on cash draws in interest expense.

When BGE incurs gains or losses on debt that it retires prior to maturity, it amortizes those gains or losses over the remaining original life of the debt in accordance with regulatory requirements.

Accounting Standards Issued

Accounting for Variable Interest Entities

In June 2009, the FASB amended the accounting, presentation, and disclosure guidance related to variable interest entities, effective for interim and annual reporting periods beginning after November 15, 2009. The amended standard includes the following significant provisions:

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

We are completing our evaluation of this standard. Based on our evaluation to date, we believe the primary impact will be increased VIE disclosures, and we do not believe the implementation of this standard will have a material impact on our, or BGE's, financial results.

Accounting Standards Adopted

Noncontrolling Interests in Consolidated Financial Statements

In December 2007, the FASB issued amended guidance related to the accounting and reporting of noncontrolling interests in consolidated financial statements. A noncontrolling interest in a subsidiary is now considered an ownership interest in the consolidated entity that should be reported as equity in the consolidated financial statements. This presentation views the consolidated business as a single economic entity and considers minority ownership interests in consolidated subsidiaries as equity in the consolidated entity.

Under the amended guidance, companies are required to:

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

Effective January 1, 2009, we presented and disclosed noncontrolling interests in our Consolidated Financial Statements in accordance with the amended guidance, and we accounted for the sale of a 49.99% membership interest in CENG to EDF by deconsolidating CENG, measuring our retained interest at fair value, and recognizing a gain at closing. We discuss this transaction in more detail in Note 2.

Disclosures about Derivative Instruments and Hedging Activities

In March 2008, the FASB issued amended guidance requiring significantly expanded disclosures about derivative instruments and hedging activities, but did not change the accounting for derivatives. We adopted the new disclosure requirements on January 1, 2009 and provide these additional disclosures in Note 13.

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

In April 2009, the FASB issued accounting guidance for determining fair value when the volume and level of activity for the asset or liability have significantly decreased and for identifying transactions that are not orderly. The guidance provides for estimating fair value when the volume and level of activity for the asset or liability have decreased and assists in identifying circumstances that indicate a transaction is not orderly. Finally, the guidance expands the disclosure requirements for fair value measurements to include further disaggregation in the tabular disclosures. We adopted this guidance as of April 1, 2009 with no effect on our, or BGE's, financial results and provided the required disclosures about fair value measurements in Note 13. The adoption of this standard only impacted our disclosures.

2 Other Events

2009 Events

	Pre-Tax			After-Tax


	(In millions)
Gain on sale of 49.99% membership interest in our nuclear generation and operation business (CENG) to EDF	$	7,445.6		$	4,456.1
Amortization of basis difference in CENG		(29.6	)		(17.8	)
Net loss on divestitures		(468.8	)		(293.2	)
Impairment losses and other costs (1)		(124.7	)		(96.2	)
Impairment of nuclear decommissioning trust assets through November 6, 2009		(62.6	)		(46.8	)
Loss on redemption of Zero Coupon Senior Notes		(16.0	)		(10.0	)
Maryland PSC order—BGE residential customer credits		(112.4	)		(67.1	)
Merger termination and strategic alternatives costs		(145.8	)		(13.8	)
Workforce reduction costs		(12.6	)		(9.3	)

Total other items	$	6,473.1		$	3,901.9

(1): After-tax amount net of noncontrolling interest.

Gain on Sale of 49.99% Membership Interest in CENG to EDF

On December 17, 2008, we entered into an Investment Agreement with EDF under which EDF would purchase from us a 49.99% membership interest in CENG for $4.5 billion (subject to certain adjustments).

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

•: Constellation Energy is to fund a one-time per customer distribution rate credit for BGE residential customers, before the end of March 2010, totaling $110.5 million, or approximately $100 per customer, for which we recorded a liability in November 2009. In December 2009, BGE filed a tariff with the Maryland PSC stating we would give residential customers a rate credit of exactly $100 per customer. As a result, we accrued an additional $1.9 million for a total fourth quarter 2009 accrual of $112.4 million. Constellation made a $66 million equity contribution to BGE in December 2009 to fund the after-tax amount of the rate credit as ordered by the Maryland PSC.
•: Constellation Energy is required to make a $250 million cash capital contribution to BGE by no later than June 30, 2010. We made this contribution in December 2009.
•: BGE will not pay common dividends to Constellation Energy if (a) after the dividend payment, BGE's equity ratio would be below 48% as calculated pursuant to the Maryland PSC's ratemaking precedents or (b) BGE's senior unsecured credit rating is rated by two of the three major credit rating agencies below investment grade.
•: BGE may file an electric distribution rate case at any time beginning in January 2010 and may not file a subsequent electric distribution rate case until January 2011. Any rate increase in the first electric distribution rate case will be capped at 5% as agreed to by Constellation Energy in its 2008 settlement with the State of Maryland and the Maryland PSC. The timing of any gas distribution rate filing will also occur no earlier than the electric case.
•: Constellation Energy will be limited to allocating no more than 31% of its holding company costs to BGE until the Maryland PSC reviews such cost allocations in the context of BGE's next rate case.
•: Constellation Energy and BGE are required to implement "ring fencing" measures designed to provide bankruptcy protection and credit rating separation of BGE from Constellation Energy. Such measures include the formation of a new special purpose subsidiary by Constellation Energy (RF HoldCo) to hold all of the common equity interests in BGE. We completed the implementation of these measures in February 2010.

With the receipt of the Maryland PSC's order, Constellation Energy and EDF closed the transaction on November 6, 2009. Upon closing of the transaction, we sold a 49.99% membership interest in CENG to EDF for total consideration of approximately $4.7 billion (includes $3.5 billion in cash at close, the non-cash redemption of the $1.0 billion Series B Preferred Stock held by EDF, and certain expense reimbursements). As a result, we ceased to have a controlling financial interest in CENG and deconsolidated CENG in the fourth quarter of 2009.

We recorded this transaction as follows:

•: We received cash consideration of approximately $3.5 billion, plus certain adjustments, and redeemed the $1.0 billion Series B Preferred Stock held by EDF as additional purchase price resulting in net proceeds of approximately $4.7 billion.
•: We removed the individual assets and liabilities of CENG from our balance sheet with a net asset value of approximately $2.4 billion.
•: We recorded our retained investment in CENG at estimated fair value of approximately $5.1 billion.

•: We recognized a pre-tax gain on sale of approximately $7.4 billion, calculated as follows:

	(In billions)


Fair value of the consideration received from EDF	$	4.7
Estimated fair value of our retained interest in CENG		5.1
Carrying amount of CENG's assets and liabilities prior to deconsolidation		(2.4	)

Pre-tax gain	$	7.4

On November 6, 2009, we began to account for our retained investment in CENG using the equity method and report our share of its earnings in our Generation business segment. As a result, we no longer record the individual income statement line items, but instead record our share of the investment's earnings in a single line in our Consolidated Statements of Income (Loss).

We estimated the fair value of CENG for purposes of recording our retained interest upon closing of the sale. Our estimate considered the replacement cost, discounted future cash flows, and comparable market transactions valuation approaches. After correlating the valuations under these three approaches, the ultimate fair value estimate reflects the discounted future expected cash flows of the business using various inputs that we believe are reflective of a market participant's perspective. The most significant inputs include our expectations of nuclear plant performance, future power prices, nuclear fuel and operating costs, forecasted capital expenditures, existing power sales commitments, and a discounting factor reflective of an investor's required risk-adjusted return.

The fair value of our investment in CENG exceeded our share of CENG's equity because CENG's assets and liabilities retained their historical carrying value. This basis difference totaled approximately $3.9 billion, and we assigned it to the noncurrent assets of CENG based on fair value. We will amortize this difference as a reduction in our equity investment earnings in CENG as follows:

Difference		Amortization Period


Property, plant and equipment		Depreciable life
Power purchase agreements and revenue sharing agreements		Term of the agreement

Land and intangibles with indefinite lives		Upon sale by CENG

For the period November 6, 2009 through December 31, 2009, we recorded $29.6 million of basis difference amortization as a reduction to our equity investment earnings in CENG. We discuss the components of our equity investment earnings in Note 4.

Also, if we were to sell an additional portion of our investment, we would recognize a proportionate amount of the basis difference.

Divestitures

In 2009, we completed many of the strategic initiatives we identified in 2008 to improve liquidity and reduce our business risk.

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

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

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

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

We record the cash proceeds we pay or receive at the inception of energy purchase and sale contracts based upon whether the contracts are in-the-money or out-of-the-money as follows:



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

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

International Commodities Operation

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

•: a pre-tax loss of approximately $334.5 million representing net consideration paid to the buyer, the book value of net assets sold, and transaction costs,
•: a reclassification of $165.7 million in losses on previously designated cash-flow hedge contracts, for which the forecasted transactions are now deemed probable of not occurring, from "Accumulated Other Comprehensive Loss" to "Nonregulated revenues" in the Consolidated Statements of Income (Loss),
•: workforce reduction costs of $10.9 million, recorded as part of "Workforce reduction costs" in the Consolidated Statements of Income (Loss), and
•: other costs of $17.6 million related to leasehold improvements, furniture and computer hardware and software, recorded as part of "Impairment losses and other costs" in the Consolidated Statements of Income (Loss).

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

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

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

Year Ended December 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	)

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

Houston-Based Gas and Other Trading Operations

On February 3, 2009, we entered into a definitive agreement to sell our Houston-based gas trading operation. We transferred control of this operation on April 1, 2009. In addition, in the second quarter of 2009 we also sold certain other trading operations. In total, we received proceeds of approximately $61 million, and recorded a $102.5 million net loss on these sales in 2009. The net loss on sale primarily relates to nonderivative accrual contracts, which were not recorded on our Consolidated Balance Sheet, the cost associated with disposing of an entire portfolio and not merely individual contracts, and the cost of capital, including contingent capital, to support the operation.

The matching derivative and nonderivative transactions under the TRS discussed above were executed at prices that differed from market prices at closing. As a result, we record the ongoing cash flows related to the out-of-the-money derivative contracts that were liabilities at inception as financing cash flows. This resulted in cash outflows related to financing activities of $858.5 million in our Consolidated Statements of Cash Flows for the year ended December 31, 2009 associated with derivative liabilities that were out-of-the-money.

The net cash receipt from the buyers upon completion of the TRS was $91.9 million in the second quarter of 2009. We have reflected these contracts on a gross basis in cash flows from investing and financing activities in our Consolidated Statements of Cash Flows as follows:

Year Ended December 31, 2009


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

Net cash flows from contract and portfolio acquisitions	$	91.9

In addition, we incurred other costs of $7.0 million for 2009 related to leasehold improvements, furniture, computer hardware and software costs, which are recorded as part of "Impairment losses and other costs" on our Consolidated Statements of Income (Loss).

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

Shipping Joint Venture

We completed the sale of our equity investment in a shipping joint venture during the third quarter of 2009. No gain or loss was recognized on the sale. We discuss the sale of the shipping joint venture below.

Other Nonregulated Divestiture

During the fourth quarter of 2009, one of our nonregulated subsidiaries sold an energy project and recorded a net loss of $4.6 million.

Impairment Losses and Other Costs

Available for Sale Securities

We evaluated certain of our investments in equity securities during 2009. The investments we evaluated included our nuclear decommissioning trust fund assets (through November 6, 2009) 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."

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

The fair values of certain of the securities held in our nuclear decommissioning trust fund held through November 6, 2009 and other marketable securities declined below book value. As a result, we recorded a $62.6 million pre-tax impairment charge for the year ended December 31, 2009 for our nuclear decommissioning trust fund assets in the "Other income (expense)" line in our Consolidated Statements of Income (Loss). We also recorded an impairment charge of $0.5 million for other marketable securities not included in our nuclear decommissioning trust funds for the year ended December 31, 2009.

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

Equity Method Investments

Shipping Joint Venture

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

As a result of the events that occurred during the second quarter of 2009, we concluded that the fair value of our investment had declined to a level below the carrying value at June 30, 2009 and that this decline was other than temporary. As such, we recorded a pre-tax impairment charge of $59.0 million associated with our equity investment in our shipping joint venture within the "Impairment losses and other costs" line in our Consolidated Statements of Income (Loss), and reported the charge in our NewEnergy business segment results for 2009.

Constellation Energy Partners LLC

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

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

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

As a result of evaluating these factors, we determined that the decline in the value of our investment 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). We did not record an impairment charge for the remainder of 2009.

District Chilled Water

During 2009, BGE entered into an agreement to sell its interest in a nonregulated subsidiary that owns a district chilled water facility to a third party. We completed this sale in January 2010. We have no further involvement in the activities of this entity.

As a result of these events, we concluded that the fair value of our investment in this subsidiary had declined to a level below carrying value at December 31, 2009 and that this decline was other than temporary. As such, we recorded a pre-tax impairment charge of $12.0 million, net of the noncontrolling interest impact of $8.0 million. The gross impairment charge of $20.0 million is recorded within the "Impairment losses and other costs" line in both our and BGE's Consolidated Statements of Income (Loss). The noncontrolling interest portion of $8.0 million is recorded within the "Net Income Attributable to Noncontrolling Interests and BGE Preference Stock Dividends" line in our Consolidated Statements of Income (Loss) and within the "Net Income Attributable to Noncontrolling Interests" line in BGE's Consolidated Statements of Income.

Other Costs

During 2009, we recorded $31.2 million pre-tax charges in the "Impairment losses and other costs" line in our Consolidated Statements of Income (Loss) primarily related to:

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

Loss on Redemption of Zero Coupon Senior Notes

In November 2009, we redeemed the Zero Coupon Senior Notes early and recognized a pre-tax loss on redemption of $16.0 million within "Interest Expense" on our Consolidated Statements of Income (Loss).

Merger Termination and Strategic Alternatives Costs

We incurred additional costs during 2009 related to the terminated merger agreement with MidAmerican, the transactions related to EDF, and other strategic alternatives costs. These costs totaled $145.8 million pre-tax for the year ended December 31, 2009, and primarily relate to fees incurred to complete the transactions with EDF and the first quarter of 2009 write-off of the unamortized debt discount associated with the 14% Senior Notes (Senior Notes) that were repaid in full to MidAmerican in January 2009. Upon the closing of the transaction with EDF on November 6, 2009, certain of the costs incurred in 2008 and 2009 became tax deductible. We reflected this impact in 2009.

Workforce Reduction Costs

We incurred workforce reduction costs during the fourth quarter of 2008, primarily related to workforce reduction efforts across all of our operations (Q4 2008 Program), and during the first quarter of 2009, primarily related to the divestiture of a majority of our international commodities operation as well as some smaller restructurings elsewhere in our organization (Q1 2009 Program). For the Q1 2009 Program, we recognized a $12.6 million pre-tax charge during 2009 related to the elimination of approximately 180 positions. We expect both of these restructurings will be completed by the end of the first quarter of 2010.

The following table summarizes the status of the involuntary severance liabilities at December 31, 2009:

	Q1 2009 Program			Q4 2008 Program


	(In millions)
Initial severance liability balance	$	10.8		$	19.7
Additional expenses recorded in 2009		1.8			—
Amounts recorded as pension and postretirement liabilities		—			(3.0	)

Net cash severance liability		12.6			16.7
Cash severance payments		(12.0	)		(15.8	)

Severance liability balance at December 31, 2009	$	0.6		$	0.9

2008 Events

	Pre-Tax			After-Tax


	(In millions)
Merger termination and strategic alternatives costs	$	(1,204.4	)	$	(1,204.4	)
Impairment losses and other costs		(741.8	)		(470.7	)
Workforce reduction costs		(22.2	)		(13.4	)
Emissions allowances write-down		(46.7	)		(28.7	)
Net gain on divestitures		25.5			16.0
Gain on sale of dry bulk vessel		29.0			18.9
Maryland settlement credit (after-tax amount reflects the effective tax rate impact on BGE)		(189.1	)		(110.5	)
Impairment of nuclear decommissioning trust assets		(165.0	)		(82.0	)

Total other items	$	(2,314.7	)	$	(1,874.8	)

Merger Termination and Strategic Alternatives Costs

We incurred costs during 2008 related to the terminated merger agreement with MidAmerican, the conversion of Series A Preferred Stock, the execution of the Investment Agreement and related agreements with EDF, and our pursuit of other strategic alternatives. These costs totaled $1.2 billion pre-tax. We did not record a tax benefit for any of these costs in our Consolidated Statement of Income (Loss) in 2008.

A significant portion of these costs was incurred pursuant to the termination of the merger agreement with MidAmerican and the conversion of the Series A Preferred Stock. Specifically, Constellation Energy incurred the following charges:

•: $175 million merger termination fee,
•: approximately $945 million for settling the conversion of the Series A Preferred Stock, which included a cash payment of $418 million and issuance of approximately 19.9 million shares of our common stock,
•: approximately $15 million for the remaining unamortized portion of the premium paid as part of executing an agreement with MidAmerican in November 2008 that provided us the option to sell certain generating plants to MidAmerican for aggregate proceeds of $350 million. This agreement was terminated as part of the termination of our merger agreement with MidAmerican, and
•: approximately $70 million in other costs associated with the MidAmerican transaction and other strategic alternatives explored consisting primarily of external legal, accounting and consulting fees.

The above amounts do not include $150 million of cash received from EDF in conjunction with the Investment Agreement entered into on December 17, 2008. We recorded this $150 million as additional purchase price at closing.

BGE recorded $16 million as its allocable portion of these costs through November 30, 2008 when the merger with MidAmerican was still pending. However, in light of the EDF transaction involving an investment in our nonregulated nuclear generation and operation business rather than a merger with Constellation Energy, BGE was not allocated any further costs

effective in December 2008 and all of the previously allocated costs recorded by BGE were allocated to the Generation and NewEnergy segments.

Impairment Losses and Other Costs

Impairment Evaluations

We discuss our evaluation of assets for impairment and other than temporary declines in value in Note 1. We perform impairment evaluations for our long-lived assets, equity method investments, and goodwill when triggering events occur that would indicate that the potential for an impairment exists. We perform an impairment evaluation for our nuclear decommissioning trust fund assets quarterly.

In addition, we evaluate goodwill for impairment on an annual basis regardless of whether any triggering events have occurred. Our accounting policy is to perform an annual goodwill impairment review in the third quarter of each year.

During the third quarter of 2008, the following triggering events resulted in the need for us to perform impairment analyses:

•: we announced a strategic initiative to sell our upstream gas assets subject to market conditions,
•: there was a significant decline in the availability of credit in the markets,
•: there was a significant decline in the overall stock market and, in particular, our stock price,
•: we signed a definitive merger agreement with MidAmerican, which was subsequently terminated, and
•: commodity prices declined substantially.

As a result of these evaluations, we recorded impairments of our upstream gas properties, goodwill, and certain investments in debt and equity securities. Additionally, in the fourth quarter of 2008, there were continued declines in commodity prices and the overall stock market. This led to further impairment of our upstream gas properties, and certain investments in debt and equity securities. We describe the impairment evaluations we performed in the following sections.

Long-Lived Assets

We evaluate potential impairment of long-lived assets classified as held for use and recognize an impairment loss if the carrying amount of such assets is not recoverable. The carrying amount of an asset held for use is not recoverable if it exceeds the total undiscounted future cash flows expected to result from the use and eventual disposition of the asset.

This evaluation requires us to estimate uncertain future cash flows. In order to estimate future cash flows, we consider historical cash flows and changes in the market environment and other factors that may affect future cash flows. The assumptions we use are consistent with forecasts that we make for other purposes (for example, in preparing our other earnings forecasts) or have been adjusted to reflect relevant subsequent changes. If we are considering alternative courses of action (such as the potential sale of an asset), we probability- weight the alternative courses of action to estimate the expected cash flows.

We use our best estimates in making these evaluations and consider various factors, including forward price curves for energy, fuel costs, and operating costs. However, actual future market prices and project costs could vary from the assumptions used in our estimates, and the impact of such variations could be material.

Upstream Gas Properties

During 2008, we performed impairment analyses for our upstream gas properties as a result of the following triggering events:

•: we announced our intent to sell our upstream gas assets, and
•: there were significant decreases in natural gas prices and oil prices in both the third and fourth quarters of 2008.

We evaluated both proved and unproved property for impairments. Unproved property is impaired if there are no firm plans to continue drilling, lease expiration is at risk, or historical experience necessitates a valuation allowance. To the extent that unproved property is part of an asset that contains proved property, we applied the accounting guidance for proved property for evaluating impairment.

During the third quarter of 2008, we began the process necessary to sell our upstream gas properties, and, while we sold some of these properties by December 31, 2008, we had not yet obtained the formal approval of our Board of Directors for the sale of our other remaining properties. This approval was required to commit to a plan for sale. As a result, we continued to classify these properties as held for use as of December 31, 2008. Accordingly, our impairment evaluation consisted of estimating expected undiscounted cash flows under various scenarios as discussed below and comparing those amounts to the carrying value.

We evaluated our upstream gas portfolio for impairment at the individual property level, which is the lowest level of identifiable cash flows, since each property has separate financial statements identifying and capturing the related cash flows. We evaluated a combination of cash flows from operations scenarios for the remaining period for which we expected to hold these properties as well as estimates of proceeds from each property's ultimate disposal. The primary inputs to our estimates of cash flows from operations were reserve estimates and natural gas and oil prices based upon forward curves and modeled data for unobservable periods. The primary inputs to our estimate of proceeds from disposal were a combination of external market bids, internal models and reserve reports, and information from external advisors assisting in the sale of these assets. We maximized the use of market information to the extent it was available. We evaluated several possible courses of action and timing, and we probability-weighted the cash flows associated with each of these scenarios based upon our best estimates of the expected outcome and timing in order to arrive at each property's expected future cash flows.

Our evaluation indicated that estimated cash flows were less than the carrying value of three of our seven upstream gas properties at September 30, 2008. At December 31, 2008, our evaluation indicated that estimated cash flows were less than the carrying value for two additional properties and for one property in which that property's estimated cash flows were less than its

post-impairment carrying value at September 30, 2008 as well. The primary factors leading to the declines in expected cash flows were the decrease in market prices for natural gas and oil during the third and fourth quarters of 2008 combined with our expectation that we would sell these properties rather than hold them for their full useful lives.

As a result, we recorded the following pre-tax impairment charges:

Asset Groups	At September 30, 2008		At December 31, 2008


	(In millions)
Interest in proved and unproved natural gas and crude oil reserves in south Texas	$	62.6	$	—
Interest in proved natural gas reserves in the Rocky Mountains		73.2		—
Interest in proved and unproved natural gas reserves in the Offshore-Gulf of Mexico		7.1		3.8
Interest in proved and unproved crude oil and natural gas reserves in eastern Oklahoma		—		30.0
Interest in proved and unproved natural gas reserves in central Oklahoma		—		153.2

Total impairment charges	$	142.9	$	187.0

We recorded these impairment charges in the "Impairment losses and other costs" line in our Consolidated Statements of Income (Loss), and they are reported in our NewEnergy business segment results.

Generating Plants

We evaluated the impact of the events that occurred in 2008 on the recoverability of our generating plants. Based upon our consideration of these events and the status of the generating plant's activities, we determined that our generating plants were not impaired as of September 30, 2008 and December 31, 2008.

Debt and Equity Securities and Investments

We evaluated certain of our investments in debt and equity securities (both equity-method and cost-method investments) in light of declines in market prices during the third and fourth quarters of 2008. The investments we evaluated included our investment in CEP, other marketable securities, our nuclear decommissioning trust fund assets, and our investment in UNE. We record an impairment 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 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 for these securities is considered other than temporary and we write them down to fair value.

The fair value of our investment in CEP fell below carrying value at the end of August, and continued to decline through the end of 2008. As of September 30, 2008, the fair value of our investment in CEP based upon its closing unit price was $73 million, which was lower than its carrying value of $128 million. As of December 31, 2008, the fair value of our investment in CEP based upon its closing unit price was $17 million, which was lower than its carrying value at December 31, 2008 of $87 million.

While CEP's estimate of net asset value exceeded our carrying value, the decline in fair value of our investment in CEP reflects a number of other factors, including:

•: turmoil and tightening in the financial and credit markets in the United States,
•: substantial 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 at both September 30, 2008 and December 31, 2008, we determined that the declines in the value of our investment at both dates were other than temporary. Therefore, we recorded a $54.7 million pre-tax impairment charge at September 30, 2008 and an additional $69.7 million pre-tax impairment charge at December 31, 2008 to write-down our investment to fair value. We recorded these charges 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 significant declines in the stock market during 2008, 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 impairment charges of $31.0 million and $122.0 million pre-tax at September 30, 2008 and December 31, 2008, respectively, for our nuclear decommissioning trust fund investments in the "Other (expense) income" line in our Consolidated Statements of Income (Loss). We had previously recorded impairment charges for our nuclear decommissioning trust fund at both March 31, 2008 and June 30, 2008, totaling $12.0 million pre-tax. We also recorded an impairment charge of $7.0 million pre-tax for certain of our other marketable securities in the fourth quarter of 2008. In addition, we recorded other changes in the fair value of our nuclear decommissioning trust fund assets that are not impaired in other comprehensive income. We discuss the assets within our nuclear decommissioning trust funds in more detail in Note 4.

We also evaluated the impact of the events that occurred in 2008 on the recoverability of our investment in UNE. Based upon our consideration of these events and the status of UNE's activities, we determined that our investment in UNE was not impaired as of December 31, 2008.

The estimates we utilize in evaluating impairment of our debt and 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.

Goodwill

Goodwill is the excess of the purchase price of an acquired business over the fair value of the net assets acquired. We evaluate goodwill for impairment at least annually or more frequently if events and circumstances indicate the business might be impaired. Goodwill is impaired if the carrying value of the business exceeds fair value. Annually, in the third quarter of each year, we evaluate goodwill for impairment.

The primary judgment affecting our impairment evaluation is the requirement to estimate fair value of the reporting units to which the goodwill relates. We evaluate impairment at the reportable segment level, which is the lowest level in the organization that constitutes a business for which discreet financial information is available.

Prior to September 30, 2008, substantially all of our goodwill related to our merchant energy segment, one of our reportable segments at that time. The lack of observable market prices for the merchant energy segment required us to estimate fair value, which we determined on a preliminary basis using the income valuation approach by computing discounted cash flows, consistent with prior evaluations. Although our estimate of discounted cash flows exceeded the carrying value of the merchant energy segment, because our common stock continued to trade at a price less than carrying value for the entire company throughout the last half of September and all of October, we also estimated fair value for the merchant energy segment using current market price information.

The primary inputs and assumptions to our estimate of fair value based upon market information were as follows:

•: the fair value of Constellation Energy based upon recent market prices of our common stock,
•: the estimated fair value of BGE, and
•: the estimated value of the agreements executed with MidAmerican.

Using this information, we deducted the estimated fair value of non-merchant energy segment businesses from the fair value of Constellation Energy as a whole in order to estimate the fair value of the merchant energy segment as of September 2008. Based upon this estimate, the fair value of the merchant energy segment was substantially less than its carrying value. The primary difference between this estimate and our modeled estimates using the discounted cash flow income approach is that the market price approach incorporated the market's valuation discount associated with our merchant energy segment due to its significant liquidity and collateral requirements. We believe that this was a more appropriate method for estimating fair value than the modeled valuation techniques because it incorporated observable market information to a greater extent, which reflects current market conditions, and because it required fewer and less subjective judgments and estimates than our modeled estimates.

As a final consideration during our September 2008 impairment evaluation, we also evaluated the circumstances surrounding MidAmerican's purchase of Constellation Energy and whether the current market price of our common stock should be considered to represent fair value for accounting purposes. While the transaction price for the purchase of Constellation Energy resulted from negotiations that occurred over an abbreviated period of time during which the Company was experiencing financial difficulty, ongoing trading of the stock at levels approximating the transaction price represented the market's present assessment of fair value in a liquid, active market. This is consistent with guidance issued by the Securities Exchange Commission Office of the Chief Accountant and FASB Staff on the determination of fair value in distressed markets.

Based on our evaluation of these alternative measures of fair value, we determined that the fair value of the merchant energy business segment was less than its carrying value. Therefore, in order to measure the potential impairment of goodwill, we estimated the fair value of the merchant energy segment's assets and liabilities. We determined that the fair value of its assets net of liabilities substantially exceeded the segment's total fair value, indicating that the merchant energy segment's goodwill was impaired as of September 30, 2008. Accordingly, we recorded a pre-tax charge of $266.5 million to write-off the entire balance of our merchant energy segment goodwill substantially all of which was recorded in the third quarter of 2008. This charge is recorded in "Impairment losses and other costs" in our Consolidated Statements of Income (Loss).

Other Costs

In September 2008, we entered into a non-binding agreement to settle a class action complaint that alleged a subsidiary's ash placement operations at a third party site damaged surrounding properties. In December 2008, the settlement was approved by the court. As a result of this agreement, we recorded a $14.0 million pre-tax charge net of an expected insurance recovery.

Workforce Reduction Costs

We incurred costs related to workforce reduction efforts initiated at our nuclear generating facilities in 2006 and 2007. We substantially completed both of these workforce reduction efforts during 2008.

In September 2008, our NewEnergy business approved a restructuring of its workforce. We recognized a $2.5 million pre-tax charge during 2008 related to the elimination of approximately 100 positions associated with this restructuring. We substantially completed this workforce reduction during 2009.

During the fourth quarter of 2008, we approved a restructuring of the workforce across all of our operations. We recognized a $19.7 million pre-tax charge in 2008 related to the elimination of approximately 380 positions.

Emissions Allowances

The Clean Air Interstate Rule (CAIR) required states in the eastern United States to reduce emissions of sulfur dioxide (SO₂) and established a cap-and-trade program for annual nitrogen oxide (NO_x) emission allowances. On July 11, 2008, the United States Court of Appeals for the D.C. Circuit (the "Court") issued an opinion vacating CAIR, subject to petitions for rehearing. The Environmental Protection Agency (EPA) filed a petition for rehearing. On December 23, 2008, the Court reversed its earlier decision to revoke CAIR and will allow CAIR to remain in effect until it is replaced by a revised rule issued by the EPA that would preserve the environmental rules established by CAIR. The Court did not propose a deadline by which the EPA must correct the flaws identified with CAIR but it did state that it will accept petitions if the EPA does not remedy the problems previously identified in its July 11, 2008 opinion.

As a result of the Court's December 2008 decision, the annual NO_x program became effective in 2009 as originally established by CAIR. In addition, since the December 2008 decision, market prices for 2009 NO_x allowances have increased significantly, with lesser increases shown in allowances for subsequent years. There was also an increase in trading volumes for annual NO_x. For the SO₂ program, the EPA will be required to issue a new rule that would replace the allowances issued under Title IV of the Clean Air Act with a new, reduced pool of allowances which would meet or exceed existing CAIR targets. Market prices for SO₂ allowances have also risen since the Court's decision.

We account for our emission allowance inventory at the lower of cost or market, which includes consideration of our expected requirements related to the future generation of electricity. The weighted-average cost of our 2008 SO₂ allowance inventory in excess of amounts needed to satisfy these requirements was greater than market value at June 30, 2008 and market prices decreased further for both SO₂ and annual NO_x emission allowances through September 30, 2008. After giving consideration to the Court's July 11, 2008 decision and the subsequent decline in the market price of these allowances, we recorded a write-down of our SO₂ allowance inventory totaling $22.1 million pre-tax to reflect the June 30, 2008 market prices. At September 30, 2008, we recorded an additional write-down of our SO₂ emission allowance inventory and recorded a write-down of our annual NO_x allowance inventory totaling $58.9 million to reflect the September 30, 2008 prices. These write-downs were recorded in the "Nonregulated revenues" line in our Consolidated Statements of Income (Loss). The third quarter 2008 write-down was partially offset by mark-to-market gains totaling $22.2 million pre-tax on derivative contracts for the forward sale of emission allowances. This gain reflects the impact of lower market prices on the value of those derivative contracts.

Due to the increases in SO₂ and NO_x emission allowance prices stemming from the December 23, 2008 Court ruling, we evaluated the value of our emissions allowances and determined that a partial reversal of prior interim period write-downs was appropriate. At December 31, 2008, we reversed $11.4 million of the second and third quarter of 2008 write-downs. The prices at December 31, 2008 create a new cost basis for SO₂ and annual NO_x emission allowances and cannot be further written-up in future periods. Our mark-to-market gains on derivative contracts for the forward sale of emission allowances were $0.7 million for the quarter ended December 31, 2008. We cannot predict the outcome of any further judicial, regulatory or legislative developments or their impact on the emission allowance markets.

Net Gain on Divestitures

On March 31, 2008, we sold our working interest in oil and natural gas producing properties in Oklahoma to CEP, a related party, and recognized a gain of $14.3 million, net of the minority interest gain of $0.7 million. We discuss this transaction in more detail in Note 16.

In addition, on June 30, 2008, our NewEnergy business sold a portion of its working interests in proved natural gas reserves and unproved properties in Arkansas to an unrelated party for total proceeds of $145.4 million, which is subject to certain purchase price adjustments. Our NewEnergy business recognized a $77.7 million pre-tax gain on this sale.

In December 2008, our NewEnergy business sold working interests in proved natural gas reserves in Wyoming, and our equity investment in certain entities that own interests in proved natural gas reserves and unproved properties in Texas and Montana to unrelated parties for total proceeds of $55.7 million, subject to certain purchase price adjustments. Our NewEnergy business recognized a $67.2 million pre-tax loss on these sales.

The net gain is included in "Net (Loss) Gains on Divestitures" line in our Consolidated Statements of Income (Loss).

Gain on Sale of Dry Bulk Vessel

On July 10, 2008, a shipping joint venture, in which our NewEnergy business has a 50% ownership interest, sold one of the six dry bulk vessels it owns. Our NewEnergy business recognized a $29.0 million pre-tax gain on this sale. The gain is included in "Nonregulated revenues" line in our Consolidated Statements of Income (Loss).

Maryland Settlement Agreement—Customer Rate Credit

In March 2008, Constellation Energy, BGE and a Constellation Energy affiliate entered into a settlement agreement with the State of Maryland, the Maryland PSC and certain State of Maryland officials to resolve pending litigation and to settle other prior legal, regulatory and legislative issues. On April 24, 2008, the Governor of Maryland signed enabling legislation, which became effective on June 1, 2008. Pursuant to the terms of the settlement agreement:

•: Each party acknowledged that the agreements adopted in 1999 relating to Maryland's electric restructuring law are final and binding and the Maryland PSC will close ongoing proceedings relating to the 1999 settlement.
•: BGE provided its residential electric customers $189.1 million in the form of a one-time $170 per customer rate credit. We recorded a reduction to "Electric revenues" on our and BGE's Consolidated

Statements of Income (Loss) during the second quarter of 2008 and reduced customers' bills by the amount of the credit between September and December 2008.

•: BGE customers are relieved of the potential future liability for decommissioning Calvert Cliffs Unit 1 and Unit 2, scheduled to occur no earlier than 2034 and 2036, respectively, and are no longer obligated to pay a total of $520 million, in 1993 dollars adjusted for inflation, pursuant to the 1999 Maryland PSC order regarding the deregulation of electric generation. BGE will continue to collect the $18.7 million annual nuclear decommissioning charge from all electric customers through 2016 and continue to rebate this amount to residential electric customers, as previously required by Senate Bill 1, which had been enacted in June 2006.
•: BGE resumed collection of the residential return portion of the SOS administrative charge, which had been eliminated under Senate Bill 1, on June 1, 2008 and will continue collection through May 31, 2010 without having to rebate it to all residential electric customers. This will total approximately $40 million over this period. This charge will be suspended from June 1, 2010 through December 31, 2016.
•: Any electric distribution base rate case filed by BGE will not result in increased distribution rates prior to October 2009, and any increase in electric distribution revenue awarded will be capped at 5% with certain exceptions. Any subsequent electric distribution base rate case may not be filed prior to August 1, 2010. The agreement does not govern or affect BGE's ability to recover costs associated with gas rates, federally approved transmission rates and charges, electric riders, tax increases or increases associated with standard offer service power supply auctions.
•: Effective June 1, 2008, BGE implemented revised depreciation rates for regulatory and financial reporting purposes. The revised rates reduced depreciation expense approximately $14 million in 2008 without impacting rates charged to customers.
•: Effective June 1, 2008, Maryland laws governing investments in companies that own and operate regulated gas and electric utilities were amended to make them less restrictive with respect to certain capital stock acquisition transactions.
•: Constellation Energy elected two independent directors to the Board of Directors of BGE within the required six months from the execution of the settlement agreement.

2007 Events

		Pre-Tax			After-Tax


		(In millions)
Impairment losses and other costs		$	(20.2	)	$	(12.2	)
Workforce reduction costs			(2.3	)		(1.4	)
Gain on sales of equity of CEP			63.3			39.2
Loss from discontinued operations
	High Desert		(2.4	)		(0.3	)
	Puna		—			(0.6	)

Total loss from discontinued operations			(2.4	)		(0.9	)

Total other items		$	38.4		$	24.7

Impairment Losses and Other Costs

In connection with the termination of the merger agreement with FPL Group, Inc. (FPL Group) in October 2006, we acquired certain rights relating to a wind development project in Western Maryland. In the second quarter of 2007, we elected not to make the additional investment that was required at that time to retain our rights in the project; therefore, we recorded a charge of $20.2 million pre-tax to write-off our investment in these development rights.

Workforce Reduction Costs

In June 2007, we approved a restructuring of the workforce at the Nine Mile Point nuclear facility related to the elimination of 23 positions. We recognized costs of $2.3 million pre-tax related to recording a liability for severance and other benefits under our existing benefit programs. We completed this workforce reduction in 2008.

Gain on Sales of Equity of CEP

In November 2006, CEP, a limited liability company formed by Constellation Energy completed an initial public offering of 5.2 million common units at $21 per unit. In April 2007, CEP acquired 100% ownership of certain coalbed methane properties located in the Cherokee Basin in Kansas and Oklahoma. This acquisition was funded through CEP's sale of equity in which we did not participate.

As a result of the April 2007 equity issuance by CEP, our ownership percentage in CEP fell below 50 percent. Therefore, during the second quarter of 2007, we deconsolidated CEP and began accounting for our investment using the equity method. We discuss the equity method of accounting in more detail in Note 1.

In July and September 2007, CEP issued additional equity. In connection with our equity ownership in CEP, we recognize gains on CEP's equity issuances in the period that the equity is sold as common units or when converted to common units. The

details of the 2007 CEP equity issuances, as well as the gains recognized by us, are summarized below:

	Units Issued		Price/ Unit		Proceeds to CEP		Pre-tax gain


	(In millions, except price/unit)
April 2007 Sale
Common units		2.2	$	26.12	$	58	$	12.5
Class E units		0.1		25.84		2		0.4
July 2007 Sale
Common units		2.7		35.25		94		20.0
Class F units		2.6		35.25		92		11.2
September 2007 Sale
Common units		2.5		42.50		105		19.2

Discontinued operations

In the fourth quarter of 2006, we completed the sale of six natural gas-fired plants, including the High Desert facility, which was classified as discontinued operations. We recognized an after-tax loss of $0.3 million as a component of "Income (loss) from discontinued operations" for 2007 due to post-closing working capital and income tax adjustments. In addition, during 2007, we recognized an after-tax loss of $0.6 million relating to income tax adjustments arising from the June 2004 sale of a geothermal generating facility in Hawaii that was also previously classified as discontinued operations.

3 Information by Operating Segment

Our reportable operating segments are Generation, NewEnergy, Regulated Electric, and Regulated Gas:

•

Our Generation business includes:

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

•

Our NewEnergy business includes:

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

•

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

•

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

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

	Reportable Segments

	Reportable Segments											Holding Company and Other
	Generation			NewEnergy			Regulated Electric			Regulated Gas		Holding Company and Other			Eliminations			Consolidated

	(In millions)
2009
Unaffiliated revenues	$	664.2		$	11,345.8		$	2,820.7		$	753.8	$	14.3		$	—		$	15,598.8
Intersegment revenues		2,110.0			163.4			—			4.5		0.1			(2,278.0	)		—

Total revenues		2,774.2			11,509.2			2,820.7			758.3		14.4			(2,278.0	)		15,598.8
Depreciation, depletion, and amortization		176.8			82.5			218.1			44.0		67.7			—			589.1
Fixed charges		166.5			39.7			113.3			26.0		2.4			2.2			350.1
Income tax expense (benefit)		3,107.1			(179.1	)		50.9			17.1		(9.2	)		—			2,986.8
Net income (loss) (1)		4,766.7			(348.2	)		79.1			25.5		(19.7	)		—			4,503.4
Net income (loss) attributable to common stock		4,766.7			(402.3	)		68.9			22.5		(12.4	)		—			4,443.4
Segment assets		12,402.1			4,167.5			4,994.6			1,413.4		4,573.7			(4,006.9	)		23,544.4
Capital expenditures		1,039.2			116.8			373.0			66.0		—			—			1,595.0
2008
Unaffiliated revenues	$	856.2			15,185.4		$	2,679.5		$	1,004.8	$	16.0		$	—		$	19,741.9
Intersegment revenues		2,102.3			666.3			0.2			19.2		0.1			(2,788.1	)		—

Total revenues		2,958.5			15,851.7			2,679.7			1,024.0		16.1			(2,788.1	)		19,741.9
Depreciation, depletion, and amortization		174.3			118.7			184.2			43.7		62.3			—			583.2
Fixed charges		140.7			50.6			113.5			26.3		2.3			15.7			349.1
Income tax expense (benefit)		121.3			(226.0	)		(4.9	)		25.5		5.8			—			(78.3	)
Net (loss) income (2)		(357.7	)		(1,011.4	)		11.1			40.4		(0.8	)		—			(1,318.4	)
Net (loss) income attributable to common stock		(357.7	)		(994.2	)		1.1			37.2		(0.8	)		—			(1,314.4	)
Segment assets (3)		11,205.9			7,063.5			4,583.1			1,392.4		3,431.6			(5,392.4	)		22,284.1
Capital expenditures		1,445.2			315.8			388.0			74.0		—			—			2,223.0
2007
Unaffiliated revenues	$	773.8			16,986.9		$	2,455.6		$	943.0	$	25.8		$	—		$	21,185.1
Intersegment revenues		1,704.0			1,087.2			0.1			19.8		0.1			(2,811.2	)		—

Total revenues		2,477.8			18,074.1			2,455.7			962.8		25.9			(2,811.2	)		21,185.1
Depreciation, depletion, and amortization		169.8			105.0			187.4			46.8		48.8			—			557.8
Fixed charges		94.7			(3.5	)		97.6			27.7		4.3			71.6			292.4
Income tax expense (benefit)		198.7			145.4			64.6			22.8		(3.2	)		—			428.3
Income from discontinued operations		(0.9	)		—			—			—		—			—			(0.9	)
Net income (4)		302.6			380.0			107.9			32.0		11.0			—			833.5
Net (loss) income attributable to common stock		302.6			381.3			97.9			28.8		10.9			—			821.5
Segment assets		10,674.3			7,954.1			4,374.2			1,293.6		1,968.1			(4,522.0	)		21,742.3
Capital expenditures		637.5			625.5			340.0			62.0		—			—			1,665.0

(1): Our Generation business recognized the following after-tax items: gain on sale of a 49.99% membership interest in CENG to EDF of $4,456.1 million, amortization of basis difference in investment in CENG of ($17.8) million, loss on the early extinguishment of zero coupon senior notes of $10.0 million, merger termination and strategic alternatives costs of $9.7 million, and impairment charges of our nuclear decommissioning trust assets through November 6, 2009 of $46.8 million. Our NewEnergy business recognized the following after-tax items: merger termination and strategic alternatives costs of $4.1 million, losses on divestitures, which include losses on the sales of the international commodities and gas trading operations, the reclassification of losses on previously designated cash-flow hedges from Accumulated Other Comprehensive Loss because the forecasted transactions are probable of not occurring, earnings that are no longer part of our core business, of $371.9 million, impairment losses and other costs of $84.7 million, and workforce reduction costs of $9.3 million. Our regulated electric and gas businesses recognized after-tax charges of $56.7 million and $10.4 million, respectively, for the accrual of a residential customer credit. Our holding company and other businesses recognized after-tax charges of $11.5 million for impairment losses and other costs. We discuss these items in more detail in Note 2.
(2): Our Generation business recognized the following after-tax charges: workforce reduction costs of $3.7 million, merger termination and strategic alternatives costs of $742.3 million, impairment charges and other costs of $8.3 million, and an impairment charge of our nuclear decommissioning trust assets of $82.0 million. Our NewEnergy business recognized the following after-tax charges: impairment losses and other costs of $460.1 million, workforce reduction costs of $5.8 million, merger termination and strategic alternatives costs of $462.1 million, net emission allowance write-down of $28.7 million, a net gain on the sale of upstream gas properties of $16.0 million, and a gain on sale of a dry bulk vessel of $18.9 million. Our regulated electric business recognized after-tax charges related to workforce reduction costs of $2.8 million and the Maryland settlement credit of $110.5 million. Our regulated gas business recognized an after-tax charge related to workforce reduction costs of $1.0 million. Our holding company and other businesses recognized an after-tax charge related to workforce reduction costs of $0.1 million. We discuss these items in more detail in Note 2.
(3): At December 31, 2008, Holding Company and Other Businesses segment assets include approximately $1.6 billion of intercompany receivables, primarily relating to the allocation of merger termination costs of approximately $1.2 billion to these businesses, and $1.0 billion of restricted cash related to the issuance of Series B Preferred Stock to EDF. These funds are held at the holding company and are restricted for payment of the 14% Senior Notes held by MidAmerican. The 14% Senior Notes were repaid in full in January 2009.
(4): Our Generation business recognized an after-tax loss of $12.2 million related to a cancelled wind development project and an after-tax charge of $1.4 million for workforce reduction costs. Our NewEnergy business recognized an after-tax gain of $39.2 million on sales of CEP equity. We discuss these items in more detail in Note 2.

4 Investments

Investments in Joint Ventures, Qualifying Facilities and Power Projects, and CEP

Investments in joint ventures, qualifying facilities, domestic power projects, and CEP consist of the following:

At December 31,		2009		2008


		(In millions)
Joint Ventures:
	CENG	$	5,222.9	$	—
	UNE		122.0		51.0
	Shipping JV		—		59.9
Qualifying facilities and domestic power projects:
	Coal		119.7		119.5
	Hydroelectric		55.2		55.6
	Geothermal		40.0		37.0
	Biomass		56.2		58.2
	Fuel Processing		24.3		15.0
	Solar		6.9		6.9
CEP			—		17.7
Other			—		0.2

Total		$	5,647.2	$	421.0

Investments in joint ventures, qualifying facilities, domestic power projects, and CEP were accounted for under the following methods:

At December 31,	2009		2008


	(In millions)
Equity method	$	5,640.3	$	414.1
Cost method		6.9		6.9

Total	$	5,647.2	$	421.0

We are actively involved in our nuclear joint ventures, qualifying facilities and power projects. Our percentage voting interests in these investments accounted for under the equity method range from 20% to 50.01%. Equity in earnings of these investments is as follows:

Year ended December 31,	2009			2008			2007


	(In millions)
CENG	$	33.9		$	—		$	—
Amortization of basis difference in CENG (see Note 2 for more detail)		(29.6	)		—			—

Total equity investment earnings—CENG		4.3			—			—
UNE		(24.7	)		(5.9	)		1.9
Shipping JV		(1.8	)		37.4			(0.6	)
CEP		(4.6	)		7.7			6.1
Qualifying facilities and domestic power projects		20.7			37.2			0.7

Total equity investment earnings	$	(6.1	)	$	76.4		$	8.1

We describe each of these investments below.

Joint Ventures

CENG

On November 6, 2009, we completed the sale of a 49.99% membership interest in CENG, our nuclear generation and operation business, to EDF. As a result of this transaction, we deconsolidated CENG and began to record our 50.01% investment in CENG under the equity method of accounting. Because the transaction occurred on November 6, 2009, we recorded $4.3 million of equity investment earnings in CENG, which represents our share of earnings from CENG from November 6, 2009 through December 31, 2009, net of the amortization of the basis difference in CENG. The basis difference is the difference between the fair value of our investment in CENG at closing and our share of the underlying equity in CENG, because the underlying assets and liabilities of CENG were retained at their carrying value. See Note 2 for a more detailed discussion.

Summarized balance sheet information for CENG is as follows:

At December 31, 2009


	(In millions)
Current assets	$	513.0
Noncurrent assets		4,404.2
Current liabilities		556.9
Noncurrent liabilities		1,716.1

Summarized income statement information for CENG is as follows:

For the period from November 6, 2009 through December 31, 2009


	(In millions)
Revenues	$	217.6
Fuel and purchased energy expenses		29.8
Income from operations		64.6
Net income		68.5

In future periods, we may be eligible for distributions from CENG in excess of our 50.01% ownership interest based on tax sharing provisions contained in the operating agreement for CENG. We would record these distributions, if realized, in earnings in the period received.

UNE

In August 2007, we formed a joint venture, UNE with EDF. We have a 50% ownership interest in this joint venture to develop, own, and operate new nuclear projects in the United States and Canada. The agreement with EDF includes a phased-in investment of $625 million by EDF in UNE. We and EDF have contributed assets to UNE with the following carrying values:

	Investment by

Year ended December 31,	Constellation Energy		EDF

	(In millions)
2009 (1)	$	91.6	$	91.6
2008		1.7		175.0
2007		48.7		350.0

(1): Amounts contributed to fund UNE's capital requirements. EDF's contribution does not count toward its $625 million obligation.

EDF will contribute up to an additional $100 million to UNE, for a total of $625 million, upon reaching additional licensing milestones.

As of December 31, 2009, UNE's capitalized construction work in progress was approximately $510 million. Such amounts are being capitalized based on UNE's assessment that construction of new nuclear projects is probable. Should that expectation change, previously capitalized costs would be written-off by UNE and we would be required to recognize our proportionate share of such charges. In the event that our portion of any losses incurred by UNE exceed our investment, we will continue to record those losses in earnings unless it is determined that UNE will cease operations and subsequently be dissolved.

We also believe that UNE's construction of new nuclear projects is probable. Should that assessment change, we would be required to evaluate our investment in UNE for potential impairment.

Shipping JV

In December 2006, we formed a shipping joint venture in which our NewEnergy business had a 50% ownership interest. We sold our interest in this joint venture during 2009 for negligible proceeds.

Qualifying Facilities and Power Projects

Our Generation business holds up to a 50% voting interest in 18 operating domestic energy projects that consist of electric generation, fuel processing, or fuel handling facilities. Of these 18 projects, 16 are "qualifying facilities" that receive certain exemptions and pricing under the Public Utility Regulatory Policies Act of 1978 based on the facilities' energy source or the use of a cogeneration process.

CEP

In November 2006, CEP, a limited liability company formed by our NewEnergy business, completed an initial public offering. As of December 31, 2006, we owned approximately 54% of CEP and consolidated CEP. During the second quarter of 2007, CEP issued additional equity to the public and our ownership percentage fell below 50%. Therefore, we deconsolidated CEP and began accounting for our investment using the equity method. As of December 31, 2009, we hold a 28.5% voting interest in CEP.

Investments Classified as Available-for-Sale

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

•: nuclear decommissioning trust funds (through November 6, 2009), and
•: trust assets securing certain executive benefits.

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

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

At December 31, 2009	Adjusted Cost		Unrealized Gains		Unrealized Losses		Fair Value


	(In millions)
Money market funds	$	0.1	$	—	$	—	$	0.1
Mutual funds		16.1		2.8		—		18.9

Totals	$	16.2	$	2.8	$	—	$	19.0

At December 31, 2008	Adjusted Cost		Unrealized Gains		Unrealized Losses			Fair Value


	(In millions)
Money market funds	$	17.6	$	—	$	—		$	17.6
Marketable equity securities		700.9		41.5		(2.1	)		740.3
Corporate debt and U.S Treasuries		224.8		6.8		—			231.6
State municipal bonds		46.2		1.3		—			47.5

Totals	$	989.5	$	49.6	$	(2.1	)	$	1,037.0

On November 6, 2009, we removed the nuclear decommissioning trust fund assets from our Consolidated Balance Sheets as part of the deconsolidation of CENG described in Note 2. Prior to November 6, 2009, the investments in our nuclear decommissioning trust funds were managed by third parties who have independent discretion over the purchases and sales of securities. We recognized impairments for any of these investments for which the fair value declines below our book value. We recognized $62.6 million and $165.0 million in pre-tax impairment losses on our nuclear decommissioning trust investments during 2009 and 2008, respectively. There were immaterial impairments in 2007. These impairments are included as part of gross realized losses in the following table.

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

Year ended December 31,	2009			2008			2007


	(In millions)
Gross realized gains	$	29.8		$	49.6		$	33.5
Gross realized losses		(86.9	)		(210.4	)		(30.9	)

Net realized (losses) gains	$	(57.1	)	$	(160.8	)	$	2.6

Investments in Variable Interest Entities

As of December 31, 2009, we consolidated three variable interest entities (VIE) in which we were the primary beneficiary, and we had significant interests in six VIEs for which we did not have controlling financial interests and, accordingly, were not the primary beneficiary. See Note 1 for estimated impacts of new accounting requirements for VIEs in 2010.

Consolidated Variable Interest Entities

In 2007, BGE formed RSB BondCo LLC (BondCo), a special purpose bankruptcy- remote limited liability company, to acquire and hold rate stabilization property and to issue and service bonds secured by the rate stabilization property. In June 2007, BondCo purchased rate stabilization property from BGE, including the right to assess, collect, and receive non-bypassable rate stabilization charges payable by all residential electric customers of BGE. These charges are being assessed in order to recover previously incurred power purchase costs that BGE deferred pursuant to Senate Bill 1.

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

The BondCo assets are restricted and can only be used to settle the obligations of BondCo. Further, BGE is required to remit all payments it receives from customers for rate stabilization charges to BondCo. During 2009, 2008, and 2007, BGE remitted $85.8 million, $87.2 million, and $38.4 million, respectively, to BondCo.

BGE did not provide any additional financial support to BondCo during 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. The BondCo creditors do not have any recourse to the general credit of BGE in the event the rate stabilization charges are not sufficient to cover the bond principal and interest payments of BondCo.

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

The gas supply arrangement is collateralized as follows:

•: The assets of the retail gas entity group must be used to settle obligations under the third party gas supply agreement before it can make any distributions to us,
•: The third party gas supplier has a collateral interest in all of the assets and equity of the retail gas entity group, and
•: We provided a $100 million parental guarantee and a $65 million letter of credit to the third party gas supplier in support of the retail gas entity group.

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

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

The carrying amounts and classification of the above consolidated VIEs' assets and liabilities included in our consolidated financial statements at December 31, 2009 are as follows:

	(In millions)


Current assets	$	608.9
Noncurrent assets		67.7

Total Assets	$	676.6

Current liabilities	$	509.9
Noncurrent liabilities		420.3

Total Liabilities	$	930.2

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

During 2010, as part of the 2009 order from the Maryland PSC approving our transaction with EDF, we created RF HoldCo, a bankruptcy-remote special purpose subsidiary to hold all of the common equity interests in BGE. This subsidiary is not a VIE. However, due to our ownership structure, we will consolidate this subsidiary as a voting interest entity.

BGE and RF HoldCo are separate legal entities and are not liable for the debts of Constellation Energy. Accordingly, creditors of Constellation Energy may not satisfy their debts from the assets of BGE and RF HoldCo except as required by applicable law or regulation. Similarly, Constellation Energy is not liable for the debts of BGE or RF HoldCo. Accordingly, creditors of BGE and RF HoldCo may not satisfy their debts from the assets of Constellation Energy except as required by applicable law or regulation.

Unconsolidated Variable Interest Entities

As of December 31, 2009, we had significant interests in six VIEs for which we were not the primary beneficiary. We have not provided any material financial or other support to these entities during 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	$34.7 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

For purposes of aggregating the various VIEs for disclosure, we evaluated the risk and reward characteristics for, and the significance of, each VIE. We discuss in greater detail the nature of our involvement with the power contract monetization VIEs in the Power Contract Monetization VIEs section below.

The following is summary information available as of December 31, 2009 about these entities:

		Power Contract Monetization VIEs		All Other VIEs		Total


		(In millions)
Total assets		$	568.3	$	338.6	$	906.9
Total liabilities			460.4		77.9		538.3
Our ownership interest			—		62.6		62.6
Other ownership interests			107.9		198.1		306.0
Our maximum exposure to loss			34.7		64.6		99.3
Carrying amount and location of variable interest on balance sheet:
	—Other investments		—		62.6		62.6

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 December 31, 2009 consists of the following:

•: outstanding receivables, loans, and letters of credit totaling $34.7 million,
•: the carrying amount of our investment totaling $62.6 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.

Power Contract Monetization VIEs

In March 2005, our NewEnergy business closed a transaction in which we assumed from a counterparty two power sales contracts with previously existing VIEs. The VIEs previously were created by the counterparty to issue debt in order to monetize the value of the original contracts to purchase and sell power. Under the power sales contracts, we sell power to the VIEs which, in turn, sell that power to an electric distribution utility through 2013. In connection with this transaction, a third party acquired the equity of the VIEs and we loaned that party a portion of the purchase price. If the electric distribution utility were to default under its obligation to buy power from the VIEs, the equity holder could transfer its equity interests to us in lieu of repaying the loan. In this event, we would have the right to seek recovery of our losses from the electric distribution utility.

5 Intangible Assets

Goodwill

Goodwill is the excess of the cost of an acquisition over the fair value of the net assets acquired. As of December 31, 2009, our goodwill balance was primarily related to our NewEnergy business. Prior to September 30, 2008, our goodwill balance was primarily related to our merchant energy business, one of our reportable segments at that time. Goodwill is not amortized; rather, it is evaluated for impairment at least annually. We evaluated our goodwill in 2008 and recorded a $266.5 million impairment charge in 2008, which related solely to our merchant energy business. We discuss this impairment charge in more detail in Note 2.

The changes in the gross amount of goodwill and the accumulated impairment losses for the years ended December 31, 2009 and 2008 are as follows:

At December 31,		2009			2008


		(In millions)
Balance as of January 1,:
	Gross goodwill	$	271.1		$	261.3
	Accumulated impairment losses		(266.5	)		—

Net goodwill			4.6			261.3
Goodwill acquired			18.6			9.8
Impairment losses			—			(266.5	)
Other purchase price adjustments			2.3			—

Balance as of December 31,
	Gross goodwill		292.0			271.1
	Accumulated impairment losses		(266.5	)		(266.5	)

Net goodwill		$	25.5		$	4.6

For tax purposes, $18.6 million of our goodwill balance at December 31, 2009 is deductible.

Intangible Assets Subject to Amortization

Intangible assets with finite lives are subject to amortization over their estimated useful lives. The primary assets included in this category are as follows:

	2009

At December 31,								2008

	Gross Carrying Amount		Accumul- ated Amortiz- ation			Net Asset		Gross Carrying Amount		Accumul- ated Amortiz- ation			Net Asset

	(In millions)
Software	$	580.5	$	(347.3	)	$	233.2	$	554.9	$	(291.5	)	$	263.4
Permits and licenses		2.2		(0.8	)		1.4		64.9		(10.0	)		54.9
Operating manuals and procedures		—		—			—		38.6		(8.6	)		30.0
Other		29.0		(13.9	)		15.1		43.9		(22.6	)		21.3

Total	$	611.7	$	(362.0	)	$	249.7	$	702.3	$	(332.7	)	$	369.6

BGE had intangible assets with a gross carrying amount of $242.5 million and accumulated amortization of $148.8 million at December 31, 2009 and $217.0 million and accumulated amortization of $131.4 million at December 31, 2008 that are included in the table above. Substantially all of BGE's intangible assets relate to software.

We recognized amortization expense related to our intangible assets as follows:

Year Ended December 31,	2009		2008		2007


	(In millions)
Nonregulated businesses	$	74.2	$	66.8	$	51.9
BGE		23.6		20.1		20.2

Total Constellation Energy	$	97.8	$	86.9	$	72.1

The following is our, and BGE's, estimated amortization expense related to our intangible assets for 2010 through 2014 for the intangible assets included in our, and BGE's, Consolidated Balance Sheets at December 31, 2009:

Year Ended December 31,	2010		2011		2012		2013		2014


	(In millions)
Estimated amortization expense—Nonregulated businesses	$	56.7	$	45.1	$	25.7	$	9.9	$	4.4
Estimated amortization expense—BGE		24.6		21.9		15.3		11.6		7.4

Total estimated amortization expense—Constellation Energy	$	81.3	$	67.0	$	41.0	$	21.5	$	11.8

Unamortized Energy Contracts

As discussed in Note 1, unamortized energy contract assets and liabilities represent the remaining unamortized balance of nonderivative energy contracts acquired, certain contracts which no longer qualify as derivatives due to the absence of a liquid market, or derivatives designated as normal purchases and normal sales, which we previously recorded as derivative assets and liabilities. Unamortized energy contract assets also include the power purchase agreement entered into with CENG with a fair value of approximately $0.8 billion. See Note 16 for more details on this power purchase agreement.

We present separately in our Consolidated Balance Sheets the net unamortized energy contract assets and liabilities for these contracts. The table below presents the gross and net carrying amount and accumulated amortization of the net liability that we have recorded in our Consolidated Balance Sheets:

	2009

At December 31									2008

	Carrying Amount			Accumul- ated Amortiz- ation		Net Liability			Carrying Amount			Accumul- ated Amortiz- ation		Net Liability

	(In millions)
Unamortized energy contracts, net	$	(1,587.1	)	$	1,584.5	$	(2.6	)	$	(2,332.3	)	$	1,286.8	$	(1,045.5	)

We recognized amortization expense of $353.1 million, $390.4 million, and $423.7 million related to these energy contract assets for the years ended December 31, 2009, 2008, and 2007 for our nonregulated businesses.

The table below presents the estimated amortization for these assets and liabilities over the next five-years:

Year Ended December 31,	2010		2011		2012			2013			2014


	(In millions)
Estimated amortization	$	45.6	$	295.1	$	(89.8	)	$	(92.3	)	$	(72.1	)

6 Regulatory Assets (net)

As discussed in Note 1, the Maryland PSC and the FERC provide the final determination of the rates we charge our customers for our regulated businesses. Generally, we use the same accounting policies and practices used by nonregulated companies for financial reporting under accounting principles generally accepted in the United States of America. However, sometimes the Maryland PSC or FERC orders an accounting treatment different from that used by nonregulated companies to determine the rates we charge our customers. When this happens, we must defer certain regulated expenses and income in our Consolidated Balance Sheets as regulatory assets and liabilities. We then record them in our Consolidated Statements of Income (Loss) (using amortization) when we include them in the rates we charge our customers.

We summarize regulatory assets and liabilities in the following table, and we discuss each of them separately below.

At December 31,		2009			2008


		(In millions)
Deferred fuel costs
	Rate stabilization deferral	$	477.5		$	536.3
	Other		14.3			24.4
Electric generation-related regulatory asset			102.5			118.0
Net cost of removal			(210.1	)		(198.0	)
Income taxes recoverable through future rates (net)			67.6			63.2
Deferred smart energy savers program costs			22.1			15.6
Deferred postretirement and postemployment benefit costs			9.6			12.9
Deferred environmental costs			6.5			7.7
Workforce reduction costs			1.5			—
Other (net)			(4.6	)		(5.7	)

Total regulatory assets (net)			486.9			574.4
Less: Current portion of regulatory assets (net)			72.5			79.7

Long-term portion of regulatory assets (net)		$	414.4		$	494.7

Deferred Fuel Costs

Rate Stabilization Deferral

In June 2006, Senate Bill 1 was enacted in Maryland and imposed a rate stabilization measure that capped rate increases by BGE for residential electric customers at 15% from July 1, 2006 to May 31, 2007. As a result, BGE recorded a regulatory asset on its Consolidated Balance Sheets equal to the difference between the costs to purchase power and the revenues collected from customers, as well as related carrying charges based on short-term interest rates from July 1, 2006 to May 31, 2007. In addition, as required by Senate Bill 1, the Maryland PSC approved a plan that allowed residential electric customers the option to further defer the transition to market rates from June 1, 2007 to January 1, 2008. During 2007, BGE deferred $306.4 million of electricity purchased for resale expenses and certain applicable carrying charges as a regulatory asset related to the rate stabilization plans. During 2009 and 2008, BGE recovered $51.4 million and $57.1 million, respectively, of electricity purchased for resale expenses and carrying charges related to the rate stabilization plan regulatory asset. BGE began amortizing the regulatory asset associated with the deferral which ended in May 2007 to earnings over a period not to exceed ten years when collection from customers began in June 2007. Customers who participated in the deferral from June 1, 2007 to December 31, 2007 are repaying the deferred charges without interest over a 21-month period which began in April 2008 and ended in December 2009.

Other

As described in Note 1, deferred fuel costs are the difference between our actual costs of purchased energy and our fuel rate revenues collected from customers. We reduce deferred fuel costs as we collect them from our customers.

We exclude deferred fuel costs from rate base because their existence is relatively short-lived. These costs are recovered in the following year through our fuel rates.

Electric Generation-Related Regulatory Asset

As a result of the deregulation of electric generation, BGE ceased to meet the requirements for accounting for a regulated business for the previous electric generation portion of its business. As a result, BGE wrote-off its entire individual, generation-related regulatory assets and liabilities. BGE established a single, generation-related regulatory asset to be collected through its regulated rates, which is being amortized on a basis that approximates the pre-existing individual regulatory asset amortization schedules.

A portion of this regulatory asset represents income taxes recoverable through future rates that do not earn a regulated rate of return. These amounts were $62.8 million as of December 31, 2009 and $72.4 million as of December 31, 2008. We will continue to amortize this amount through 2017.

Net Cost of Removal

As discussed in Note 1, we use the group depreciation method for the regulated business. This method is currently an acceptable method of accounting under accounting principles generally accepted in the United States of America and has been widely used in the energy, transportation, and telecommunication industries.

Historically, under the group depreciation method, the anticipated costs of removing assets upon retirement were provided for over the life of those assets as a component of depreciation expense. However, effective January 1, 2003, the recognition of expected net future costs of removal is shown as a component of depreciation expense or accumulated depreciation.

BGE is required by the Maryland PSC to use the group depreciation method, including cost of removal, under regulatory accounting. For ratemaking purposes, net cost of removal is a

component of depreciation expense and the related accumulated depreciation balance is included as a net reduction to BGE's rate base investment. For financial reporting purposes, BGE continues to accrue for the future cost of removal for its regulated gas and electric assets by increasing a regulatory liability. This liability is relieved when actual removal costs are incurred.

Income Taxes Recoverable Through Future Rates (net)

As described in Note 1, income taxes recoverable through future rates are the portion of our net deferred income tax liability that is applicable to our regulated business, but has not been reflected in the rates we charge our customers. These income taxes represent the tax effect of temporary differences in depreciation and the allowance for equity funds used during construction, offset by differences in deferred tax rates and deferred taxes on deferred investment tax credits. We amortize these amounts as the temporary differences reverse.

Deferred Smart Energy Savers Program Costs

Deferred Smart Energy Savers Program costs are the costs incurred to implement demand response, conservation, and advanced metering programs. These programs are designed to help BGE manage peak demand, improve system reliability, reduce customer consumption, and improve service to customers by giving customers greater control over their energy use. Actual costs incurred in the demand response program, which began in January 2008, are being amortized over a 5-year period from the date incurred pursuant to an order by the Maryland PSC. Actual costs incurred in the conservation program, which began in February 2009, are being amortized as incurred pursuant to an order by the Maryland PSC.

Deferred Postretirement and Postemployment Benefit Costs

We record a regulatory asset for the deferred postretirement and postemployment benefit costs in excess of the costs we included in the rates we charged our customers through 1997. We began amortizing these costs over a 15-year period in 1998.

Deferred Environmental Costs

Deferred environmental costs are the estimated costs of investigating and cleaning up contaminated sites we own. We discuss this further in Note 12. We amortized $21.6 million of these costs (the amount we had incurred through October 1995) and are amortizing $6.4 million of these costs (the amount we incurred from November 1995 through June 2000) over 10-year periods in accordance with the Maryland PSC's orders. We applied for and received rate relief for an additional $5.4 million of clean-up costs incurred during the period from July 2000 through November 2005. These costs are being amortized over a 10-year period that began in January 2006.

Workforce Reduction Costs

The portion of the costs associated with our 2008 workforce reduction program that relate to BGE's gas business were deferred in 2009 as a regulatory asset in accordance with the Maryland PSC's orders in prior rate cases and are being amortized over a 5-year period that began in January 2009.

Other (Net)

Other regulatory assets are comprised of a variety of current assets and liabilities that do not earn a regulatory rate of return due to their short-term nature.

7 Pension, Postretirement, Other Postemployment, and Employee Savings Plan Benefits

We offer pension, postretirement, other postemployment, and employee savings plan benefits. BGE employees participate in the benefit plans that we offer. We describe each of our plans separately below. Nine Mile Point, owned by CENG, offers its own pension, postretirement, other postemployment, and employee savings plan benefits to its employees. In connection with the deconsolidation of CENG as a result of the investment in CENG by EDF on November 6, 2009, the Nine Mile Point plan is no longer included in our consolidated results. In addition, benefit plan assets and obligations relating to CENG employees that previously participated in our plans were transferred into new CENG plans that are no longer included in our consolidated results. Therefore, the tables below include the benefits for the CENG plans, including Nine Mile Point, only through November 6, 2009.

We use a December 31 measurement date for our pension, postretirement, other postemployment, and employee savings plans. The following table summarizes our defined benefit liabilities and their classification in our Consolidated Balance Sheets:

At December 31,	2009		2008


	(In millions)
Pension benefits	$	411.7	$	936.7
Postretirement benefits		322.3		415.4
Postemployment benefits		50.6		59.9

Total defined benefit obligations		784.6		1,412.0
Less: Amount recorded in other current liabilities		40.7		57.7

Total noncurrent defined benefit obligations*	$	743.9	$	1,354.3

Pension Benefits

We sponsor several defined benefit pension plans for our employees. These include basic qualified plans that most employees participate in and several non-qualified plans that are available only to certain employees. A defined benefit plan specifies the amount of benefits a plan participant is to receive using information about the participant. Employees do not contribute to these plans. Generally, we calculate the benefits under these plans based on age, years of service, and pay.

Sometimes we amend the plans retroactively. These retroactive plan amendments require us to recalculate benefits related to participants' past service. We amortize the change in the benefit costs from these plan amendments on a straight-line basis over the average remaining service period of active employees.

We fund the qualified plans by contributing at least the minimum amount required under IRS regulations. We calculate the amount of funding using an actuarial method called the projected unit credit cost method. The assets in all of the plans at December 31, 2009 and 2008 were mostly marketable equity and fixed income securities.

Postretirement Benefits

We sponsor defined benefit postretirement health care and life insurance plans that cover the majority of our employees. Generally, we calculate the benefits under these plans based on age, years of service, and pension benefit levels or final base pay. We do not fund these plans. For nearly all of the health care plans, retirees make contributions to cover a portion of the plan costs. For the life insurance plan, retirees do not make contributions to cover a portion of the plan costs.

Effective in 2002, we amended our postretirement medical plans for all subsidiaries other than Nine Mile Point. Our contributions for retiree medical coverage for future retirees who were under the age of 55 on January 1, 2002 are capped at the 2002 level. We also amended our plans to increase the Medicare eligible retirees' share of medical costs.

In 2003, the President signed into law the Medicare Prescription Drug Improvement and Modernization Act of 2003 (the Act). This legislation provides a prescription drug benefit for Medicare beneficiaries, a benefit that we provide to our Medicare eligible retirees. Our actuaries concluded that prescription drug benefits available under our postretirement medical plan are "actuarially equivalent" to Medicare Part D and thus qualify for the subsidy under the Act. This subsidy reduced our 2009 Accumulated Postretirement Benefit Obligation by $28.4 million and our 2009 postretirement medical payments by $2.8 million.

Liability Adjustments

At December 31, 2009 and 2008, our pension obligations were greater than the fair value of our plan assets for our qualified and our nonqualified pension plans as follows:

	Qualified Plans

At December 31, 2008	Nine Mile		Other		Non-Qualified Plans		Total

	(In millions)
Accumulated benefit obligation	$	—	$	1,277.5	$	84.1	$	1,361.6
Fair value of assets		—		1,058.1		—		1,058.1

Unfunded obligation	$	—	$	219.4	$	84.1	$	303.5

	Qualified Plans

	Qualified Plans				Non-Qualified Plans
At December 31, 2008	Nine Mile		Other		Non-Qualified Plans		Total

	(In millions)
Accumulated benefit obligation	$	123.7	$	1,417.3	$	99.8	$	1,640.8
Fair value of assets		63.3		804.3		—		867.6

Unfunded obligation	$	60.4	$	613.0	$	99.8	$	773.2

We are required to reflect the funded status of our pension plans in terms of the projected benefit obligation, which is higher than the accumulated benefit obligation because it includes the impact of expected future compensation increases on the pension obligation. We reflect the funded status of our postretirement benefits in terms of the accumulated postretirement benefit obligation.

The following table summarizes the impacts of funded status adjustments recorded during 2009 and 2008:

							Accumulated Other Comprehensive Income (Loss)

				Postretirement Benefit Liability
	Pension Liability
	Pension Liability						Pre-tax			After-tax

	(In millions)
December 31, 2009	$	(49.3	)	$	1.0		$	48.3		$	25.4

November 6, 2009 (1)	$	(211.7	)	$	(20.9	)	$	232.6		$	138.0

December 31, 2008	$	590.7		$	(9.5	)	$	(581.2	)	$	(347.1	)

(1): We performed a remeasurement of our pension and postretirement obligations at November 6, 2009 in connection with the separation of a portion of those plans upon the deconsolidation of CENG.

Obligations and Assets

As a result of workforce reduction initiatives, pension and postretirement special termination benefits were recorded in 2009, 2008 and 2007. We discuss the workforce reduction initiatives further in Note 2.

We show the change in the benefit obligations and plan assets of the pension and postretirement benefit plans in the following tables. Postretirement benefit plan amounts are presented net of expected reimbursements under Medicare Part D.

	Pension Benefits						Postretirement Benefits

	2009			2008			2009			2008

	(In millions)
Change in benefit obligation (1)
Benefit obligation at January 1	$	1,804.3		$	1,644.2		$	415.4		$	421.5
Service cost		50.8			55.4			6.3			6.1
Interest cost		101.1			100.2			22.6			24.0
Plan amendments		2.4			12.1			—			—
Plan participants' contributions		—			—			10.2			10.8
Actuarial loss (gain)		55.8			102.4			1.0			(9.5	)
Separation of CENG Plan		(410.5	)		—			(98.6	)		—
Settlements		(19.0	)		—			—			—
Special termination benefits		0.1			2.2			—			0.8
Benefits paid (2)(3)		(115.2	)		(112.2	)		(34.6	)		(38.3	)

Benefit obligation at December 31	$	1,469.8		$	1,804.3		$	322.3		$	415.4

(1): Amounts reflect projected benefit obligation for pension benefits and accumulated postretirement benefit obligation for postretirement benefits.
(2): Pension benefits paid include annuity payments and lump-sum distributions.
(3): Postretirement benefits paid are net of Medicare Part D reimbursements.

	Pension Benefits						Postretirement Benefits

	2009			2008			2009			2008

	(In millions)
Change in plan assets
Fair value of plan assets at January 1	$	867.6		$	1,258.5		$	—		$	—
Actual return on plan assets		217.6			(364.9	)		—			—
Employer contribution (1)		341.5			86.2			24.4			27.5
Plan participants' contributions		—			—			10.2			10.8
Separation of CENG Plan		(234.4	)		—			—			—
Settlements		(19.0	)		—			—			—
Benefits paid (2)(3)		(115.2	)		(112.2	)		(34.6	)		(38.3	)

Fair value of plan assets at December 31	$	1,058.1		$	867.6		$	—		$	—

(1): Includes benefit payments for unfunded plans.
(2): Pension benefits paid include annuity payments and lump-sum distributions.
(3): Postretirement benefits paid are net of Medicare Part D reimbursements.

Net Periodic Benefit Cost and Amounts Recognized in Other Comprehensive Income

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

Year Ended December 31,	2009			2008			2007


	(In millions)
Components of net periodic pension benefit cost
Service cost	$	50.8		$	55.4		$	49.4
Interest cost		101.1			100.2			94.7
Expected return on plan assets		(118.9	)		(111.3	)		(102.6	)
Amortization of unrecognized prior service cost		10.9			10.9			5.2
Recognized net actuarial loss		38.3			24.7			32.7
Amount capitalized as construction cost		(10.2	)		(10.2	)		(11.7	)

Net periodic pension benefit cost (1)	$	72.0		$	69.7		$	67.7

(1): Net periodic pension benefit cost excludes settlement charge of $9.0 million and termination benefits of $0.1 million in 2009, termination benefits of $2.2 million in 2008, and termination benefits of $1.2 million in 2007. BGE's portion of our net periodic pension benefit costs, excluding amount capitalized, was $27.9 million in 2009, $25.5 million in 2008, and $32.1 million in 2007. The vast majority of our retirees are BGE employees.

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

Year Ended December 31,	2009			2008			2007


	(In millions)
Components of net periodic postretirement benefit cost
Service cost	$	6.3		$	6.1		$	6.5
Interest cost		22.6			24.0			24.4
Amortization of transition obligation		2.1			2.1			2.1
Recognized net actuarial loss		2.2			2.0			4.1
Amortization of unrecognized prior service cost		(3.4	)		(3.5	)		(3.5	)
Amount capitalized as construction cost		(6.3	)		(7.6	)		(7.7	)

Net periodic postretirement benefit cost (1)	$	23.5		$	23.1		$	25.9

(1): Net periodic postretirement benefit cost excludes termination benefits of $0.8 million in 2008 and $0.3 million in 2007. BGE's portion of our net periodic postretirement benefit cost, excluding amounts capitalized, was $18.7 million in 2009, $20.4 million in 2008, and $22.7 million in 2007.

In determining net periodic pension benefit cost, we apply our expected return on plan assets to a market-related value of plan assets that recognizes asset gains and losses ratably over a five-year period.

The following is a summary of amounts we have recorded in "Accumulated other comprehensive income" and of expected amortization of those amounts over the next twelve months:

	Pension Benefits				Postretirement Benefits

	Pension Benefits				Postretirement Benefits						Expected Amortiz- ation Next 12 Months
	2009		2008		2009			2008			Expected Amortiz- ation Next 12 Months

	(In millions)
Unrecognized actuarial loss	$	702.2	$	999.8	$	51.5		$	78.7		$	36.3
Unrecognized prior service cost		9.9		22.5		(13.9	)		(22.6	)		1.3
Unrecognized transition obligation		—		—		6.2			8.5			2.1

Total	$	712.1	$	1,022.3	$	43.8		$	64.6		$	39.7

Expected Cash Benefit Payments

The pension and postretirement benefits we expect to pay in each of the next five calendar years and in the aggregate for the subsequent five years are shown in the following table. These estimated benefits are based on the same assumptions used to measure the benefit obligation at December 31, 2009, but include benefits attributable to estimated future employee service.

			Postretirement Benefits

	Pension Benefits		Before Medicare Part D		Subsidy		After Medicare Part D

	(In millions)
2010	$	102.7	$	26.8	$	2.2	$	24.6
2011		94.3		27.1		2.2		24.9
2012		101.3		27.2		2.3		24.9
2013		107.0		27.5		2.4		25.1
2014		111.4		27.8		2.4		25.4
2015-2019		655.5		139.5		11.7		127.8

Assumptions

We made the assumptions below to calculate our pension and postretirement benefit obligations and periodic cost.

	Pension Benefits						Postretirement Benefits

	Pension Benefits						Postretirement Benefits						Assumption Impacts Calculation of
	2009			2008			2009			2008			Assumption Impacts Calculation of

Discount rate		6.00	%		6.00	%		6.00	%		6.00	%	Benefit Obligation and Periodic Cost
Expected return on plan assets		8.50			8.75			N/A			N/A		Periodic Cost
Rate of compensation increase		4.0			4.0			4.0			4.0		Benefit Obligation and Periodic Cost

Our discount rate is based on a bond portfolio analysis of high quality corporate bonds whose maturities match our expected benefit payments. Our 8.50% overall expected long-term rate of return on plan assets reflected our long-term investment strategy in terms of asset mix targets and expected returns for each asset class.

We determine expected return on plan assets by applying expected future asset returns provided by external sources by asset class to our targeted long-term asset allocations. We then review actual historical plan asset returns for comparability and supplement this approach with peer group surveys when available.

Annual health care inflation rate assumptions also impact the calculation of our postretirement benefit obligation and periodic cost. We assumed the following health care inflation rates to produce average claims by year as shown below:

At December 31,


Next year	8.0	%	8.0	%
Following year	7.5	%	7.5	%
Ultimate trend rate	5.0	%	5.0	%
Year ultimate trend rate reached	2016		2015

A one-percentage point increase in the health care inflation rate from the assumed rates would increase the accumulated postretirement benefit obligation by approximately $19.0 million as of December 31, 2009 and would increase the combined

service and interest costs of the postretirement benefit cost by approximately $1.7 million annually.

A one-percentage point decrease in the health care inflation rate from the assumed rates would decrease the accumulated postretirement benefit obligation by approximately $16.6 million as of December 31, 2009 and would decrease the combined service and interest costs of the postretirement benefit cost by approximately $1.4 million annually.

Qualified Pension Plan Assets

Investment Strategy

We invest our qualified pension plan assets using the following investment objectives:

•: ensure availability of funds for payment of plan benefits as they become due,
•: provide for a reasonable amount of long-term growth of capital (both principal and income) without excessive volatility,
•: produce investment results that meet or exceed the assumed long-term rate of return,
•: reduce funded status volatility as funded status improves, and
•: improve the funded status of the plan over time.

To achieve these objectives, Constellation Energy, through a management Investment Committee (the Committee), has adopted an investment strategy that divides its pension investment program into two primary portfolios:

•: return seeking assets—those assets intended to generate returns in excess of pension liability growth, and
•: liability hedging assets—those assets intended to have characteristics similar to pension liabilities.

Currently, the Committee allocates a substantial portion of its plan assets to return seeking assets to help reduce existing deficits in the funded status of the plan. As the funded status of our plans improve, the Committee expects to reduce its exposure to return seeking assets and increase its liability hedging assets to reduce its total risk.

Return Seeking Assets

The purpose of return seeking assets is to provide investment returns in excess of the growth of pension liabilities. This category includes a diversified portfolio of public equities, private equity, real estate, hedge funds, high yield bonds and other instruments. These assets are likely to have lower correlations with the pension liabilities and lead to higher funded status risk over shorter periods of time.

Liability Hedging Assets

The purpose of liability hedging assets, such as bonds, is to hedge against interest rate changes. Exposure to liability hedging assets is intended to reduce the volatility of plan funded status, contributions, and pension expense.

Risk Management

The Committee manages plan asset risk using several approaches. First, the assets are invested in two diverse portfolios, each of which contains investments across a spectrum of asset classes. Second, the Committee considers the long-term investment horizon of the plan, which is greater than ten years. The long-term horizon enables the Committee to tolerate the risk of investment losses in the short-term with the expectation of higher returns in the long-term. Third, the Committee employs a thorough due diligence program prior to selecting an investment, and a rigorous ongoing monitoring program once assets are invested. The Committee evaluates risk on an ongoing basis.

Asset Allocation

Plan assets are diversified across various asset classes and securities based on the investment strategy approved by the Committee. This policy allocation is long-term oriented and consistent with the risk tolerance and funded status. The target asset allocation as well as the actual allocations for 2009 and 2008 is provided below.

				Actual Allocation

	Target Allocation			Actual Allocation
At December 31,	Target Allocation			2009			2008
Global equity securities		48	%*		57	%		57	%
Fixed income securities		30			27			26
Alternative investments		15			7			11
High yield bonds		7			7			6
Cash and cash equivalents		—			2			—

Total		100	%		100	%		100	%

*: 50% passively invested; 50% actively invested

The target asset allocation also allows for investments in financial instruments, including asset-backed securities and collateralized mortgage obligations, which are exposed to risks such as interest rate, market and overall market volatility. These instruments are sensitive to changes in economic conditions. Such changes could materially affect the amounts reported.

The actual portfolio will be rebalanced in early 2010 to reflect the recently approved target allocation. The Committee will then rebalance our portfolio periodically when the actual allocations fall outside of the ranges prescribed in the investment policy. Further, the Committee will rebalance to de-risk the portfolio as funded status improves.

Fair Value Hierarchy

We determine the fair value of the plan assets 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 within this fair value hierarchy based on the lowest level of input that is significant to the fair value measurement of each individual asset taken as a whole.

The following table sets forth by level, within the fair value hierarchy, the investments in the Plans' master trust at fair value as of December 31, 2009:

	Level 1		Level 2		Level 3		Total Fair Value


	(In millions)
Global equity securities	$	215.4	$	383.0	$	—	$	598.4
Fixed income securities		—		289.2		—		289.2
High yield bonds		0.6		75.6		—		76.2
Cash equivalents		—		19.9		—		19.9
Alternative investments		—		—		74.4		74.4

Total	$	216.0	$	767.7	$	74.4	$	1,058.1

The following is a description of the valuation methodologies used for assets measured at fair value:

•: Global equity securities are valued at unadjusted quoted market share prices within active markets (Level 1) or based on external price/spread data of comparable securities (Level 2). Common collective trust funds within this category are valued at fair value based on the unit value of the fund which is observable on a less frequent basis (Level 2). Unit values are determined by the bank sponsoring such funds by dividing the fund's net assets at fair value by its units outstanding at the valuation dates.
•: Fixed income, high yield bonds, and cash and cash equivalents are valued based on external price data of comparable securities (Level 2).
•: Alternative investments primarily consist of hedge funds and financial limited partnerships (private equity funds). These investments do not have readily determinable fair values because they are not listed on national exchanges or over-the-counter markets. We have valued these alternative investments at their respective net asset value per share (or its equivalent such as partner's capital) which has been calculated by each partnership's general partner in a manner consistent with generally accepted accounting principles in the United States of America for investment companies. Among other requirements, the partnerships must value their underlying investments at fair value. While the net asset value per share provides a reasonable approximation of fair value, the fair values of the alternative investments are estimates and, accordingly, such estimated values may differ from the values that would have been used had a ready market for the investments existed, and the differences could be material.

The following table summarizes the changes in the fair value of the Level 3 assets for the year ended December 31, 2009:

Year ended December 31, 2009


		(In millions)
Balance at beginning of period		$	96.3
Actual return on plan assets:
	Assets still held at year end		(2.5	)
	Assets sold during the year		6.4
Purchases, sales, and settlements			(10.8	)
Transfers into and out of Level 3			(15.0	)

Balance at end of period		$	74.4

Contributions and Benefit Payments

We contributed $319.4 million to our qualified pension plans in 2009, even though there was no IRS required minimum contribution in 2009. We expect to contribute $37 million to our qualified pension plans in 2010. Our non-qualified pension plans and our postretirement benefit programs are not funded. We estimate that we will incur approximately $10 million in pension benefits for our non-qualified pension plans and approximately $25 million for retiree health and life insurance costs net of Medicare Part D during 2010.

Other Postemployment Benefits

We provide the following postemployment benefits:

•: health and life insurance benefits to eligible employees determined to be disabled under our Disability Insurance Plan, and
•: income replacement payments for employees determined to be disabled before November 1995 (payments for employees determined to be disabled after that date are paid by an insurance company, and the cost is paid by employees).

We recognized expense associated with our other postemployment benefits of $5.3 million in 2009, $1.9 million in 2008, and $16.7 million in 2007. BGE's portion of expense associated with other postemployment benefits was $4.4 million in 2009, $2.2 million in 2008, and $10.2 million in 2007.

We assumed the discount rate for other postemployment benefits to be 4.75% in 2009 and 5.00% in 2008. This assumption impacts the calculation of our other postemployment benefit obligation and periodic cost.

Employee Savings Plan Benefits

We sponsored two defined contribution plans until November 6, 2009, when upon the close of the sale of a 49.99% interest in CENG to EDF, we deconsolidated CENG and the defined contribution plan related to Nine Mile Point was removed from our books. To all remaining eligible employees of Constellation Energy, we continue to sponsor a defined contribution savings plan. The savings plan is a qualified 401(k) plan under the Internal Revenue Code. In a defined contribution plan, the benefits a participant is to receive result from regular contributions to a participant account. Matching contributions to participant accounts are made under these plans. Matching contributions were as follows:

Year Ended December 31,	2009		2008		2007


	(In millions)
Nonregulated businesses	$	14.8	$	17.6	$	16.1
BGE		5.7		5.8		5.8

Total Constellation Energy	$	20.5	$	23.4	$	21.9

8 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. We enter into these facilities to ensure adequate liquidity to support our operations.

Constellation Energy

Our liquidity requirements are funded with credit facilities and cash. We fund our short-term working capital needs with existing cash and with our credit facilities, 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 NewEnergy business.

Constellation Energy had bank lines of credit under committed credit facilities totaling $4.0 billion at December 31, 2009 for short-term financial needs as follows:

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


Syndicated Revolver (1)		$	2.32	July 2012	Letters of credit and cash
Commodity-linked			0.50	August 2014	Letter of credit
Bilateral			0.55	September 2014	Letters of credit
Bilateral			0.25	December 2014	Letters of credit and cash
Bilateral			0.25	June 2014	Letters of credit and cash
Bilateral			0.15	September 2013	Letters of credit

	Total	$	4.02

(1): Facility size was reduced from $3.85 billion to $2.32 billion as a result of the completion of the transaction with EDF.

Collectively, these facilities currently support the issuance of letters of credit and/or cash borrowings up to $4.0 billion. At December 31, 2009, we had approximately $1.7 billion in letters of credit issued and no commercial paper outstanding under these facilities.

The commodity-linked credit facility currently allows for the issuance of letters of credit up to a maximum capacity of $0.5 billion. This commodity-linked facility is designed to help manage our contingent collateral requirements associated with the hedging of our NewEnergy business because its capacity increases as natural gas price levels decrease compared to a reference price that is adjusted periodically. As of December 31, 2009, there were no letters of credit outstanding under this facility.

BGE

BGE has a $575.0 million 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. The size of the facility may be increased up to $600 million with additional commitments by lenders. At December 31, 2009, BGE had $46.0 million in commercial paper outstanding with a weighted average effective interest rate of 0.39%. There were immaterial letters of credit outstanding at December 31, 2009.

Net Available Liquidity

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

	As of December 31, 2009

	Constellation Energy			BGE		Total Consolidated

	(In billions)
Credit facilities (1)	$	3.5		$	0.6	$	4.1
Less: Letters of credit issued		(1.7	)		—		(1.7	)
Less: Cash drawn on credit facilities		—			—		—

Undrawn facilities		1.8			0.6		2.4
Less: Commercial paper outstanding		—			—		—

Net available facilities		1.8			0.6		2.4
Add: Cash		3.4			—		3.4
Less: Reserved cash (2)		(1.3	)		—		(1.3	)

Cash and facility liquidity		3.9			0.6		4.5
Add: EDF put arrangement		1.1			—		1.1

Net available liquidity	$	5.0		$	0.6	$	5.6

(1): Excludes commodity-linked credit facility due to its contingent nature.
(2): Represents management's expectation of payments to be made for income taxes and bond repurchases in the first quarter of 2010.

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 to sell certain non-nuclear generation assets, at pre-agreed prices, to EDF for aggregate proceeds of no more than $2 billion pre-tax, or approximately $1.4 billion after-tax. The amount of after-tax proceeds will be impacted by the assets actually sold and the related tax impacts at that time.

Exercise of the put arrangement is conditioned upon the receipt of regulatory approvals and third party 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 December 31, 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 second quarter of 2010, which will increase the net after-tax liquidity from the put arrangement to approximately $1.4 billion.

We believe that the actions that we have taken and our current net available liquidity will be sufficient to support our ongoing liquidity requirements. Our liquidity projections include assumptions for commodity price changes, which are subject to significant volatility, and we are exposed to certain operational risks that could have a significant impact on our liquidity.

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 December 31, 2009, the debt to capitalization ratio as defined in the credit agreements was 34%.

Under our $2.32 billion credit facility, we granted a lien on certain of our generating facilities and pledged our ownership interests in our nuclear business to the lenders upon the completion of the transaction with EDF.

The credit agreement of BGE contains a provision requiring BGE to maintain a ratio of debt to capitalization equal to or less than 65%. At December 31, 2009, the debt to capitalization ratio for BGE as defined in this credit agreement was 45%.

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

9 Capitalization

We detail in the table below our total capitalization, which includes long-term debt, common stock, noncontrolling interests, and preference stock, as of December 31, 2009 and 2008.

At December 31,				2009			2008


				(In millions)
Long-Term Debt
	Long-term debt of Constellation Energy
		Zero Coupon Senior Notes, due June 19, 2023		$	—		$	256.7
		8.625% Series A Junior Subordinated Debentures, due June 15, 2063			450.0			450.0
		8% Series B Mandatorily Redeemable Preferred Stock			—			1,000.0
		14% Senior Notes, due December 31, 2009			—			1,000.0
		6.125% Fixed-Rate Notes, due September 1, 2009			—			500.0
		7.00% Fixed-Rate Notes, due April 1, 2012			700.0			700.0
		4.55% Fixed-Rate Notes, due June 15, 2015			550.0			550.0
		7.60% Fixed-Rate Notes, due April 1, 2032			700.0			700.0
		Fair Value of Interest Rate Swaps			38.6			55.9

		Total long-term debt of Constellation Energy			2,438.6			5,212.6

	Long-term debt of nonregulated businesses
		Tax-exempt debt transferred from BGE effective July 1, 2000
			Port facilities loan, due June 1, 2013		—			10.0
			4.10% Pollution control loan, due July 1, 2014		20.0			20.0
			Floating-rate pollution control loan, due June 1, 2027		—			8.8
		Tax-exempt variable rate notes, due April 1, 2024			75.0			75.0
		Tax-exempt variable rate notes, due December 1, 2025			47.0			47.0
		Tax-exempt variable rate notes, due December 1, 2037			65.0			65.0
		District Cooling facilities loan, due December 1, 2031			—			25.0
		5.00% Mortgage note, due June 15, 2010			0.4			1.6
		4.25% Mortgage note, due March 15, 2009			—			0.2
		7.3% Fixed Rate Note, due June 1, 2012			1.7			1.8
		Asset-based lending agreement due July 16, 2012			27.1			—

		Total long-term debt of nonregulated businesses			236.2			254.4

	Other long-term debt of BGE
		6.125% Notes, due July 1, 2013			400.0			400.0
		5.90% Notes, due October 1, 2016			300.0			300.0
		5.20% Notes, due June 15, 2033			200.0			200.0
		6.35% Notes, due October 1, 2036			400.0			400.0
		Medium-term notes, Series E			131.5			143.0

		Total other long-term debt of BGE			1,431.5			1,443.0

	6.20% deferrable interest subordinated debentures due October 15, 2043 to BGE wholly owned BGE Capital Trust II relating to trust preferred securities				257.7			257.7
	Rate stabilization bonds				510.9			564.4
	Unamortized discount and premium				(4.0	)		(41.9	)
	Current portion of long-term debt				(56.9	)		(2,591.5	)

	Total long-term debt			$	4,814.0		$	5,098.7

At December 31,		2009			2008


		(In millions)
Equity:
Noncontrolling Interests		$	75.3		$	20.1
BGE Preference Stock
	Cumulative preference stock not subject to mandatory redemption, 6,500,000 shares authorized 7.125%, 1993 Series, 400,000 shares outstanding, callable at $101.42 per share until June 30, 2010, and at lesser amounts thereafter		40.0			40.0
	6.97%, 1993 Series, 500,000 shares outstanding, callable at $101.39 per share until September 30, 2010, and at lesser amounts thereafter		50.0			50.0
	6.70%, 1993 Series, 400,000 shares outstanding, callable at $101.68 per share until December 31, 2010, and at lesser amounts thereafter		40.0			40.0
	6.99%, 1995 Series, 600,000 shares outstanding, callable at $102.10 per share until September 30, 2010, and at lesser amounts thereafter		60.0			60.0

	Total BGE preference stock not subject to mandatory redemption		190.0			190.0

Common Shareholders' Equity
	Common stock without par value, 600,000,000 shares authorized; 200,985,414 and 199,128,908 shares issued and outstanding at December 31, 2009 and 2008, respectively. (At December 31, 2009, 5,790,545 shares were reserved for the long-term incentive plans, 7,041,111 shares were reserved for the shareholder investment plan, and 527,959 shares were reserved for the employee savings plan.)		3,229.6			3,164.5
	Retained earnings		6,461.0			2,228.7
	Accumulated other comprehensive loss		(993.5	)		(2,211.8	)

	Total common shareholders' equity		8,697.1			3,181.4

Total Equity			8,962.4			3,391.5

Total Capitalization		$	13,776.4		$	8,490.2

Long-term Debt

Long-term debt matures in one year or more from the date of issuance. The long-term debt of Constellation Energy and BGE do not contain material adverse change clauses. We detail our long-term debt in the table above.

Constellation Energy

Mandatorily Redeemable Series B Preferred Stock

On December 17, 2008, Constellation Energy entered into an Investment Agreement with EDF. Simultaneously with the execution of the Investment Agreement, Constellation Energy issued 10,000 shares of 8% Series B Preferred Stock (Series B Preferred Stock) to EDF for $1 billion, which was restricted for the repayment of our 14% Senior Notes. On November 6, 2009, the date EDF completed the purchase of the 49.99% interest in CENG pursuant to the Investment Agreement, EDF surrendered to Constellation Energy all of the shares of the Series B Preferred Stock as partial payment for the purchase of the interest in CENG.

Upstream Gas Property Asset-Based Lending Agreement

In July 2009, we entered into a three year asset-based lending agreement associated with certain upstream gas properties that we own. At December 31, 2009, the borrowing base committed under the facility was $100 million, of which $27.1 million has been utilized and reflected in "Long-term debt" in our Consolidated Balance Sheets. The size of the facility may be increased up to $200 million with additional commitments by the lenders. Any debt issued under this facility is secured by the upstream gas properties, and the lenders do not have recourse against Constellation Energy in the event of a default. Interest is payable quarterly in March, June, September, and December.

This asset-based lending agreement contains a provision that requires certain of our entities that own our upstream gas properties to maintain a current ratio of one-to-one. As of December 31, 2009, these entities were in compliance with this provision.

Voluntary Debt Retirements

The repurchase of the following notes is part of our previously announced commitment to repay $1 billion of debt following the close of our transaction with EDF in November 2009.

Zero Coupon Senior Notes

In November 2009, we redeemed an aggregate principal amount of $267.6 million for the Zero Coupon Senior Notes early and recognized a pre-tax loss on redemption of $16.0 million. We recorded the loss within "Interest expense" in the Consolidated Statements of Income (Loss).

Cash Tender Offer for Outstanding 7.00% Notes due April 1, 2012

In February 2010, we retired an aggregate principal amount of $486.5 million of our 7.00% Notes due April 1, 2012 pursuant to a cash tender offer, at a premium of approximately 11%.

Tax-Exempt Notes

During 2009, we retired approximately $150 million of variable rate tax exempt notes prior to maturity. On February 15, 2010, we issued a notice to call our outstanding $47 million and $65 million variable rate tax-exempt notes. These notes are expected to be repurchased on March 10, 2010. Since these notes are variable rate instruments, we do not expect to record any gain or loss upon repurchase.

BGE

Secured Indenture

BGE entered into a secured indenture in July 2009. The secured indenture creates a first priority lien on substantially all of BGE's electric utility distribution equipment and fixtures and on BGE's franchises, permits, and licenses that are transferable and necessary for the operation of the equipment and fixtures. As of December 31, 2009, BGE has not issued any secured bonds under this indenture.

BGE's Rate Stabilization Bonds

In June 2007, BondCo, a subsidiary of BGE, issued an aggregate principal amount of $623.2 million of rate stabilization bonds to recover deferred power purchase costs. We discuss BondCo in more detail in Note 4. Below are the details of the rate stabilization bonds at December 31, 2009:

Principal			Scheduled Maturity Date


$171.7	5.47	%	October 2012
220.0	5.72		April 2016
119.2	5.82		April 2017

The bonds are secured primarily by a usage-based, non-bypassable charge payable by all of BGE's residential electric customers over a ten year period. The charges will be adjusted semi-annually to ensure that the aggregate charges collected are sufficient to pay principal and interest on the bonds, as well as certain on-going costs of administering and servicing the bonds. BondCo cannot use the charges collected to satisfy any other obligations. BondCo's assets are not assets of any affiliate and are not available to pay creditors of any affiliate of BondCo. If BondCo is unable to make principal and interest payments on the bonds, neither Constellation Energy, nor BGE, are required to make the payments on behalf of BondCo.

BGE's Other Long-Term Debt

On July 1, 2000, BGE transferred $278.0 million of tax-exempt debt to our Generation business related to the transferred generating assets. At December 31, 2009, BGE remains contingently liable for the $20 million outstanding balance of this debt.

BGE's fixed-rate medium-term note, series E, outstanding at December 31, 2009 has a weighted average interest rate of 6.71%, maturing between 2011 and 2012.

BGE Deferrable Interest Subordinated Debentures

On November 21, 2003, BGE Capital Trust II (BGE Trust II), a Delaware statutory trust established by BGE, issued 10,000,000 Trust Preferred Securities for $250 million ($25 liquidation amount per preferred security) with a distribution rate of 6.20%.

BGE Trust II used the net proceeds from the issuance of common securities to BGE and the Trust Preferred Securities to purchase a series of 6.20% Deferrable Interest Subordinated Debentures due October 15, 2043 (6.20% debentures) from BGE in the aggregate principal amount of $257.7 million with the same terms as the Trust Preferred Securities. BGE Trust II must redeem the Trust Preferred Securities at $25 per preferred security plus accrued but unpaid distributions when the 6.20% debentures are paid at maturity or upon any earlier redemption. BGE has the option to redeem the 6.20% debentures at any time on or after November 21, 2008 or at any time when certain tax or other events occur.

BGE Trust II will use the interest paid on the 6.20% debentures to make distributions on the Trust Preferred Securities. The 6.20% debentures are the only assets of BGE Trust II.

BGE fully and unconditionally guarantees the Trust Preferred Securities based on its various obligations relating to the trust agreement, indentures, 6.20% debentures, and the preferred security guarantee agreement.

For the payment of dividends and in the event of liquidation of BGE, the 6.20% debentures are ranked prior to preference stock and common stock.

Loan Agreement

On December 18, 2001, BGE's subsidiary, District Chilled Water Partnership (ComfortLink) entered into a $25.0 million loan agreement with the Maryland Energy Financing Administration (MEFA). The terms of the loan exactly match the terms of variable rate, tax exempt bonds due December 1, 2031 issued by MEFA for ComfortLink to finance the cost of building a chilled water distribution system.

These bonds were repurchased in June 2009.

Maturities of Long-Term Debt

As of December 31, 2009, our long-term borrowings mature on the following schedule:

Year	Constellation Energy (1)		Nonregulated Businesses		BGE		Total


	(In millions)
2010	$	—	$	0.4	$	56.5	$	56.9
2011		—		0.1		81.7		81.8
2012		722.6		28.7		172.5		923.8
2013		—		—		466.6		466.6
2014		—		20.0		70.4		90.4
Thereafter		1,716.0		187.0		1,352.4		3,255.4

Total	$	2,438.6	$	236.2	$	2,200.1	$	4,874.9

(1): A portion of Constellation Energy's bonds will be retired in 2010 as discussed in the Voluntary Debt Retirements section.

100

Weighted-Average Interest Rates for Variable Rate Debt

Our weighted-average interest rates for variable rate debt outstanding were:

At December 31,


Nonregulated Businesses (including Constellation Energy)
	Loans under credit agreements	4.50	%	2.61	%
	Tax-exempt debt	1.22	%	3.17	%
	Fixed-rate debt converted to floating *	2.30	%	4.88	%

*: As discussed in Note 13, as of December 31, 2009, we have interest rate swaps relating to $400.0 million of our fixed-rate debt.

Preference Stock

Each series of BGE preference stock has no voting power, except for the following:

•: the preference stock has one vote per share on any charter amendment which would create or authorize any shares of stock ranking prior to or on a parity with the preference stock as to either dividends or distribution of assets, or which would substantially adversely affect the contract rights, as expressly set forth in BGE's charter, of the preference stock, each of which requires the affirmative vote of two-thirds of all the shares of preference stock outstanding; and
•: whenever BGE fails to pay full dividends on the preference stock and such failure continues for one year, the preference stock shall have one vote per share on all matters, until and unless such dividends shall have been paid in full. Upon liquidation, the holders of the preference stock of each series outstanding are entitled to receive the par amount of their shares and an amount equal to the unpaid accrued dividends.

Dividend Restrictions

Constellation Energy

Constellation Energy pays dividends on its common stock after its Board of Directors declares them. There are no contractual limitations on Constellation Energy paying common stock dividends, except certain of our credit facilities prohibit us from increasing our common stock dividend without the consent of the lenders.

BGE

BGE pays dividends on its common stock after its Board of Directors declares them. However, pursuant to the order issued by the Maryland PSC on October 30, 2009 in connection with its approval of the transaction with EDF, BGE cannot pay dividends to Constellation Energy if (a) after the dividend payment, BGE's equity ratio would be below 48% as calculated pursuant to the Maryland PSC's ratemaking precedents or (b) BGE's senior unsecured credit rating is rated by two of the three major credit rating agencies below investment grade.

101

10 Taxes

The components of income tax expense are as follows:

Year Ended December 31,			2009			2008			2007


			(Dollar amounts in millions)
Income Taxes
	Current
		Federal	$	891.5		$	2.8		$	168.2
		State		260.4			48.1			40.6

	Current taxes charged to expense			1,151.9			50.9			208.8
	Deferred
		Federal		1,474.5			(101.6	)		184.7
		State		372.5			(21.2	)		41.5

	Deferred taxes charged (credited) to expense			1,847.0			(122.8	)		226.2
	Investment tax credit adjustments			(12.1	)		(6.4	)		(6.7	)

	Income taxes per Consolidated Statements of Income (Loss)		$	2,986.8		$	(78.3	)	$	428.3

Total income taxes are different from the amount that would be computed by applying the statutory Federal income tax rate of 35% to book income before income taxes as follows:


Reconciliation of Income Taxes Computed at Statutory Federal Rate to Total Income Taxes
	(Loss) Income from continuing operations before income taxes			$	7,490.2		$	(1,396.7	)	$	1,262.7
		Statutory federal income tax rate			35	%		35	%		35	%

		Income taxes computed at statutory federal rate			2,621.6			(488.8	)		441.9
		Increases (decreases) in income taxes due to
			State income taxes, net of federal income tax benefit		411.0			17.3			53.4
			Merger-related transaction costs		(79.3	)		416.2			—
			Interest expense on mandatorily redeemable preferred stock		23.7			7.8			—
			Qualified decommissioning impairment loss		3.1			(28.5	)		—
			Amortization of deferred investment tax credits		(12.1	)		(6.4	)		(6.7	)
			Synthetic fuel tax credits flowed through to income		—			(4.5	)		(166.2	)
			Estimated synthetic fuel tax credit phase-out		—			—			110.3
			Nondeductible international losses		19.2			—			—
			Other		(0.4	)		8.6			(4.4	)

		Total income taxes		$	2,986.8		$	(78.3	)	$	428.3

	Effective income tax rate				39.9	%		5.6	%		33.9	%

BGE's effective tax rate was 41.3% in 2009, 28.7% in 2008, and 40.7% in 2007. In general, the primary difference between BGE's effective tax rate and the 35% statutory federal income tax rate for all years relates to Maryland corporate income taxes, net of the related federal income tax benefit. The increase in BGE's effective tax rate in 2009 is primarily due to higher taxable income. For 2008, BGE had lower taxable income related to the 2008 Maryland settlement agreement, which increased the relative impact of favorable permanent tax adjustments on BGE's 2008 effective tax rate.

102

The major components of our net deferred income tax liability are as follows:

			Constellation Energy						BGE

At December 31,			2009			2008			2009			2008

			(In millions)
Deferred Income Taxes
	Deferred tax liabilities
		Net property, plant and equipment	$	1,474.6		$	1,432.5		$	920.1		$	604.4
		Qualified nuclear decommissioning trust funds		—			310.9			—			—
		Regulatory assets, net		263.0			295.5			263.0			295.5
		Derivative assets and liabilities, net		329.6			310.6			—			—
		Investment in CENG		1,802.7			—			—			—
		Other		33.1			126.6			(55.1	)		32.5

		Total deferred tax liabilities		3,903.0			2,476.1			1,128.0			932.4
	Deferred tax assets
		Asset retirement obligation		7.9			391.6			—			—
		Defined benefit obligations		311.7			552.0			(23.7	)		30.8
		Financial investments and hedging instruments		337.0			949.7			—			—
		Deferred investment tax credits		13.0			17.8			3.8			4.3
		Other		155.8			156.0			71.5			13.8

		Total deferred tax assets		825.4			2,067.1			51.6			48.9

	Total deferred tax liability, net			3,077.6			409.0			1,076.4			883.5
	Less: Current portion of deferred tax (asset)/liability			(127.9	)		(268.0	)		(11.2	)		40.2

Long-term portion of deferred tax liability, net			$	3,205.5		$	677.0		$	1,087.6		$	843.3

Income Tax Audits

We file income tax returns in the United States and foreign jurisdictions. With few exceptions, we are no longer subject to U.S. federal, state and local, or non-U.S. income tax examinations by tax authorities for the years before 2005. In 2009, the IRS expanded its current audit of our consolidated federal income tax returns for the tax years 2005 through 2007 to include the 2008 tax year. Although the final outcome of the 2005-2008 IRS audit and future tax audits is uncertain, we believe that adequate provisions for income taxes have been made for potential liabilities resulting from such matters.

Unrecognized Tax Benefits

The following table summarizes the change in unrecognized tax benefits during 2009 and 2008 and our total unrecognized tax benefits at December 31, 2009 and 2008:

	2009			2008


	(In millions)
Total unrecognized tax benefits, January 1	$	189.7		$	114.5
Increases in tax positions related to the current year		101.5			112.2
Increases in tax positions related to prior years		148.4			—
Reductions in tax positions related to prior years		(126.3	)		(15.5	)
Reductions in tax positions related to audit settlements		—			(21.5	)
Reductions in tax positions as a result of a lapse of the applicable statute of limitations		(0.8	)		—

Total unrecognized tax benefits, December 31 (1)	$	312.5		$	189.7

(1): BGE's portion of our total unrecognized tax benefits at December 31, 2009 and 2008 was $111.8 million and $4.8 million, respectively.

Increases in tax positions related to the current year are primarily due to unrecognized tax benefits related to state income tax accruals associated with the transaction to sell a 49.99% membership interest in CENG to EDF. Increases in tax positions related to prior years are primarily due to unrecognized tax benefits for BGE repair and depreciation deductions including a change of accounting method for tax return purposes for the 2008 tax year for which IRS consent was received in 2009 and which is currently subject to IRS examination. Reductions in prior year tax positions are primarily due to increased certainty in the deductibility of certain costs associated with the termination of our merger with MidAmerican as a result of the structure and sale of a 49.99% membership interest in CENG.

Total unrecognized tax benefits as of December 31, 2009 of $312.5 million include outstanding claims of approximately $65.8 million, including $52.2 million in state tax credits, for which no tax benefit was recorded on our Consolidated Balance Sheet because refunds were not received and the claims do not meet the "more-likely-than-not" threshold.

If the total amount of unrecognized tax benefits of $312.5 million were ultimately realized, our income tax expense would decrease by approximately $177 million. However, the $177 million includes state tax refund claims of approximately $52 million that have been disallowed by tax authorities and are subject to appeals. These state refund claims may be resolved by December 31, 2010. For this reason, we believe it is reasonably possible that reductions to our total unrecognized tax benefits of approximately $50 million may occur by December 31, 2010, although these reductions are not expected to materially impact income tax expense.

103

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

	For the Year Ended December 31,

	2009		2008			2007

	(In millions)
Interest and penalties recorded as tax expense (benefit)	$	12.8	$	(0.4	)	$	4.7

BGE's portion of interest and penalties was immaterial for all years.

Accrued interest and penalties recognized in our Consolidated Balance Sheets were $23.1 million, of which BGE's portion was $1.6 million at December 31, 2009, and $10.3 million, of which BGE's portion was $0.7 million, at December 31, 2008.

104

11 Leases

There are two types of leases—operating and capital. Capital leases qualify as sales or purchases of property and are reported in our Consolidated Balance Sheets. Our capital leases are not material in amount. All other leases are operating leases and are reported in our Consolidated Statements of Income (Loss). We expense all lease payments associated with our regulated business. Lease expense and future minimum payments for long-term, noncancelable, operating leases are not material to BGE's financial results. We present information about our operating leases below.

Outgoing Lease Payments

We, as lessee, lease certain facilities and equipment. The lease agreements expire on various dates and have various renewal options. We also enter into certain power purchase agreements which are accounted for as operating leases. Under these agreements, we are required to make fixed capacity payments, as well as variable payments based on actual output of the plants. We record these payments as "Fuel and purchased energy expenses" in our Consolidated Statements of Income (Loss). We exclude from our future minimum lease payments table the variable payments related to the output of the plant due to the contingency associated with these payments.

Through June 2009, we also entered into time charter purchase agreements which entitled us to the use of dry bulk freight vessels in the management of our global coal and logistics services. Certain of these contracts must be accounted for as leases. During 2009 and 2008, we entered into time charter leases with terms ranging in duration from 1 to 60 months. These arrangements do not include provisions for material rent increases and do not have provisions for rent holidays, contingent rentals or other incentives. In 2009 and 2008, we recognized aggregate lease expense of approximately $145 million and $477 million, respectively, related to 31 and 49 dry bulk freight vessels, respectively, hired under time charter arrangements. The average term of these arrangements is approximately 3 months. We record the payments as "Fuel and purchased energy expenses" in our Consolidated Statements of Income (Loss).

We recognized expense related to our operating leases as follows:

	Fuel and purchased energy expenses		Operating expenses		Total


	(In millions)
2009	$	385.6	$	37.2	$	422.8
2008		664.8		38.0		702.8
2007		758.7		40.1		798.8

At December 31, 2009, we owed future minimum payments for long-term, noncancelable, operating leases as follows:

Year	Power Purchase Agreements		Other		Total


	(In millions)
2010	$	194.5	$	31.5	$	226.0
2011		202.1		28.8		230.9
2012		178.5		25.7		204.2
2013		166.3		24.5		190.8
2014		161.5		22.7		184.2
Thereafter		333.8		62.6		396.4

Total future minimum lease payments	$	1,236.7	$	195.8	$	1,432.5

Sub-Lease Arrangements

We provide time charters of dry bulk freight vessels as part of the logistical services provided to our global customers that qualify as sub-leases of our time charter purchase contracts. In 2009 and 2008, we recorded sub-lease income of approximately $114 million and $289 million, respectively, related to our time charter sub-leases. We record sub-lease income as part of "Nonregulated revenues" in our Consolidated Statements of Income (Loss). As of December 31, 2009, the future minimum rentals to be received for these time charters are shown below:

Year	Time Charter Sub-Leases


	(In millions)
2010	$	56.5
2011		56.6
2012		45.5
2013		32.0
2014		24.3
Thereafter		114.8

Total future minimum lease rentals	$	329.7

105

12 Commitments, Guarantees, and Contingencies

Commitments

We have made substantial commitments in connection with our Generation, NewEnergy, and regulated 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 Generation and NewEnergy businesses enter into various long-term contracts for the procurement and delivery of fuels to supply our generating plant requirements. In most cases, our contracts contain provisions for price escalations, minimum purchase levels, and other financial commitments. These contracts expire in various years between 2010 and 2018. In addition, our Generation and NewEnergy businesses enter 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 2010 and 2030.

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

Our regulated electric business enters into various long-term contracts for the procurement of electricity. As of December 31, 2009, these contracts expire between 2010 and 2012 and represent BGE's estimated requirements as follows:

Contract Duration


From January 1, 2010 to September 2010	100	%
From October 2010 to May 2011	75
From June 2011 to September 2011	50
From October 2011 to May 2012	25

The cost of power under these contracts is 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, and storage of gas. Our regulated gas business has gas procurement contracts that expire between 2010 and 2011, and transportation and storage contracts that expire between 2012 and 2027. The cost of gas under these contracts is recoverable under BGE's gas cost adjustment clause discussed in Note 1, and therefore are excluded from the table later in this Note.

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

At December 31, 2009, we estimate our future obligations to be as follows:

		Payments

		2010		2011- 2012		2013- 2014		Thereafter		Total

		(In millions)
Competitive Businesses:
	Purchased capacity and energy	$	160.9	$	303.5	$	107.7	$	208.7	$	780.8
	Purchased energy from CENG (1)		534.7		1,513.3		2,249.8		—		4,297.8
	Fuel and transportation		540.5		437.5		94.3		217.9		1,290.2
	Long-term service agreements, capital, and other		47.8		7.8		4.9		6.7		67.2

Total competitive businesses			1,283.9		2,262.1		2,456.7		433.3		6,436.0
Corporate and Other:
	Long-term service agreements, capital, and other		14.7		11.3		1.7		—		27.7
Regulated:
	Purchase obligations and other		15.4		20.2		—		—		35.6

Total future obligations		$	1,314.0	$	2,293.6	$	2,458.4	$	433.3	$	6,499.3

(1): Represents the nominal amounts of payments made to CENG under our power purchase agreement. The total fair value at closing of $0.8 billion was recorded on our balance sheet in "Unamortized energy contract assets."

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 our power plants extend for terms into 2016 and provide for the sale of all or a portion of the actual output of certain of our power plants. Substantially all long-term contracts were executed at pricing that approximated market rates, including profit margin, at the time of execution.

Guarantees

Our guarantees do not represent incremental Constellation Energy obligations; rather they primarily represent parental guarantees of subsidiary obligations. The following table

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summarizes the maximum exposure by guarantor based on the stated limit of our outstanding guarantees:

At December 31, 2009	Stated Limit


	(In billions)
Constellation Energy guarantees	$	10.1
BGE guarantees		0.3

Total guarantees	$	10.4

At December 31, 2009, Constellation Energy had a total of $10.4 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 $10.1 billion as follows:

•: $9.4 billion on behalf of our NewEnergy business to allow it the flexibility needed to conduct business with counterparties without having to post other forms of collateral. Our estimated net exposure for obligations under commercial transactions covered by these guarantees was approximately $2 billion at December 31, 2009, which represents the total amount the parent company could be required to fund based on December 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.
•: $0.5 billion primarily on behalf of CENG's nuclear generating facilities for nuclear insurance and credit support to ensure these plants have funds to meet expenses and obligations to safely operate and maintain the plants. We recorded the fair value of $12.3 million for these guarantees on our Consolidated Balance Sheets.
•: $0.2 billion to its other nonregulated businesses.

•

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

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 flawed, and that unreasonable deal protection devices were agreed to in order to ward off competing bids. The federal lawsuits also assert that the conversion of the Preferred Stock issued to MidAmerican into debt is not permitted under Maryland law.

The termination of the MidAmerican merger renders moot the claims attempting to enjoin the merger with MidAmerican. One of the federal merger cases was voluntarily dismissed on December 31, 2008, and the other federal merger cases were dismissed as moot on May 27, 2009. Plaintiffs' counsel in six of the seven state merger cases have filed dismissals without prejudice of their MidAmerican merger claims. In addition, on October 27, 2009 certain counsel in the state merger cases jointly moved for approval of a settlement regarding claims for attorneys' fees, which the court approved on November 16, 2009. We believe there are meritorious defenses to any claims or requests for relief that might possibly remain regarding this matter.

Securities Class Action

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

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

ERISA Actions

In the fall of 2008, multiple class action lawsuits were filed in the United States District Courts for the District of Maryland and the Southern District of New York against Constellation

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

Mercury

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

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

Asbestos

Since 1993, BGE and certain Constellation Energy subsidiaries have been involved in several actions concerning asbestos. The actions are based upon the theory of "premises liability," alleging that BGE and Constellation Energy knew of and exposed individuals to an asbestos hazard. In addition to BGE and Constellation Energy, numerous other parties are defendants in these cases.

Approximately 494 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 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 indemnified by a wholly owned subsidiary of Constellation Energy for most of the costs related to this settlement and clean-up of the site. The clean-up costs will not be known until the investigation is closer to completion, which is expected by mid-2010. The completed investigation will provide a range of remediation alternatives to the EPA, and the EPA is expected to select one of the alternatives by the end of the first quarter of 2011. The clean-up costs we incur could have a material effect on our financial results.

Air Quality

In May 2007, a subsidiary of Constellation Energy entered into a consent decree with the Maryland Department of the

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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 $8.4 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 $4.8 million of these costs as of December 31, 2009, resulting in a remaining liability at December 31, 2009 of $3.6 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.

Investment in CENG

On November 6, 2009, we completed the sale of a 49.99% membership interest in CENG to EDF. As a result of the sale, we now hold a 50.01% interest in CENG. As a 50.01% owner in CENG, we are subject to certain capital contribution requirements, which may be greater than the amount planned and, therefore, could have an adverse impact on our financial results.

In addition, if the fair value of our investment in CENG declines to a level below our carrying value and the decline is considered other-than-temporary, we may write down the investment to fair value, which would adversely affect our financial results.

We are also exposed to the same risks to which CENG is exposed. CENG owns and operates three nuclear generating facilities and is exposed to risks associated with operating these facilities and the risks of a nuclear accident.

Operating Risks

The operation of nuclear generating facilities involve routine risks, including,

•: mechanical or structural problems,
•: inadequacy or lapses in maintenance protocols,
•: cost of storage, handling and disposal of nuclear materials, including the availability or unavailability of a permanent repository for spent nuclear fuel,
•: regulatory actions, including shut down of units because of public safety concerns,
•: limitations on the amounts and types of insurance coverage commercially available,
•: uncertainties regarding both technological and financial aspects of decommissioning nuclear generating facilities,
•: terrorist attacks, and
•: environmental risks.

Nuclear Accidents

CENG is required to insure itself against public liability claims resulting from nuclear incidents to the full limit of public liability. This limit of liability consists of the maximum available commercial insurance of $375 million and mandatory participation in an industry-wide retrospective premium assessment program. The retrospective premium assessment is $117.5 million per reactor, per incident, increasing the total amount of insurance for public liability to approximately $12.6 billion. Under the retrospective assessment program, CENG can be assessed up to $587.5 million per incident at any commercial reactor in the country, payable at no more than $87.5 million per incident per year. In the event of a nuclear accident, the cost of property damage and other expenses incurred may exceed CENG's insurance coverage. As a result, uninsured losses or the payment of retrospective insurance premiums could each have a significant adverse impact to CENG's, and therefore, our financial results as a 50.01% owner in CENG. Each of Constellation Energy and EDF has guaranteed the obligations of CENG under these insurance programs in proportion to their respective membership interests.

Non-Nuclear Property Insurance

Our conventional property insurance provides coverage of $1.0 billion per occurrence for Certified acts of terrorism as defined under the Terrorism Risk Insurance Extension Act of 2005 and the Terrorism Risk Insurance Program Reauthorization Act of 2007. Our conventional property insurance program also provides coverage for non-certified acts of terrorism up to an annual aggregate limit of $1.0 billion. If a terrorist act occurs at any of our facilities, it could have a significant adverse impact on our financial results.

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13 Derivatives and Fair Value Measurements

Use of Derivative Instruments

Nature of Our Business and Associated Risks

Our business activities include our Generation, NewEnergy, regulated electric and gas businesses. Our Generation and NewEnergy businesses include:

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

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

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

•: the risks of unfavorable changes in power prices in the wholesale forward and spot markets in which we sell a portion of the power from our power generation facilities and purchase power to meet our load-serving requirements,
•: the risk of unfavorable fuel price changes for the purchase of a portion of the fuel for our generation facilities under short-term contracts or on the spot market. Fuel prices can be volatile, and the price that can be obtained for power produced from such fuel may not change at the same rate 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 for:

•: optimizing the margin on surplus electricity generation and load positions and surplus fuel supply and demand positions,
•: price discovery and verification, and
•: deploying limited risk capital in an effort to generate returns.

Accounting for Derivative Instruments

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

Accounting Designation

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

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

We discuss our accounting policies for derivatives and hedging activities and their impacts on our financial statements in Note 1.

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.

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Cash Flow Hedging

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

Commodity Cash Flow Hedges

We have designated fixed-price forward contracts as cash-flow hedges of forecasted sales of energy and forecasted purchases of fuel and energy for the years 2010 through 2016. We had net unrealized pre-tax losses on these cash-flow hedges recorded in "Accumulated other comprehensive loss" of $951.3 million at December 31, 2009 and $2,624.0 million at December 31, 2008.

We expect to reclassify $631.5 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 December 31, 2009. However, the actual amount reclassified into earnings could vary from the amounts recorded at December 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:

Year ended December 31,	2009			2008			2007


	(In millions)
Pre-tax losses	$	(241.0	)	$	(31.7	)	$	(24.4	)

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

Interest Rate Swaps Designated as Cash Flow Hedges

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

Accumulated other comprehensive loss includes net unrealized pre-tax gains on interest rate cash-flow hedges of prior debt issuances totaling $11.3 million at December 31, 2009 and $12.0 million at December 31, 2008. We expect to reclassify $2.3 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. We did not have any fair value hedges related to the value of our natural gas in storage during the last nine months of 2009.

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. On July 15, 2009, we terminated an interest rate swap relating to $50 million of the $450 million of our fixed-rate debt and received approximately $4.5 million in cash. The fair value of these hedges was an unrealized gain of $35.8 million at December 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:

Year ended December 31,	2009		2008			2007


	(In millions)
Cash-flow hedges	$	11.3	$	(121.0	)	$	(31.4	)
Fair value hedges		23.9		20.6			24.4

Total	$	35.2	$	(100.4	)	$	(7.0	)

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We did not recognize any gain or loss during 2009 and 2008 relating to changes in value for the portion of our fair value hedges excluded from our hedge effectiveness assessment.

Mark-to-Market

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

•: our competitive 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.

Origination Gains

We may record origination gains associated with commodity derivatives subject to mark-to-market accounting. Origination gains represent the initial fair value of certain structured transactions that our wholesale marketing, risk management, and trading operation executes to meet the risk management needs of our customers. Historically, transactions that result in origination gains have been unique and resulted in individually significant gains from a single transaction. We generally recognize origination gains when we are able to obtain observable market data to validate that the initial fair value of the contract differs from the contract price. Origination gains recognized in the past three years include:

•: none in 2009,
•: $73.8 million pre-tax in 2008 resulting from 6 transactions, and
•: $41.9 million pre-tax in 2007 resulting from 1 transaction.

Termination or Restructuring of Commodity Derivative Contracts

We may terminate or restructure in-the-money contracts in exchange for upfront cash payments and a reduction or cancellation of future performance obligations. The termination or restructuring of contracts allows us to lower our exposure to performance risk under these contracts. Such transactions resulted in the realization of the following amounts of pre-tax earnings that otherwise would have been recognized over the life of these contracts:

•: none in 2009,
•: $73.1 million pre-tax in 2008 resulting from 7 transactions, and
•: $17.8 million pre-tax in 2007 resulting from 1 transaction.

Quantitative Information About Derivatives and Hedging Activities

Background

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

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

Balance Sheet Tables

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

The following table provides information about the types of market risks we manage using derivatives. 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 Generation and NewEnergy businesses.

As discussed more fully following the table, we present this information by disaggregating our net derivative assets and liabilities into gross components on a contract-by-contract basis before giving effect to the risk-reducing benefits of master netting arrangements and collateral. As a result, we must present each individual contract as an "asset value" if it is in the money or a "liability value" if it is out of the money, regardless of whether the individual contracts offset market or credit risks of other contracts in full or in part. Therefore, the gross amounts in this table 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.

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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 total return swaps entered into to effect the sale of the international commodities and Houston-based gas trading operations, and risk management and trading activities which we have substantially curtailed as part of our effort to reduce risk in our business. We use the end of period accounting designation to determine the classification for each derivative position.

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


Contract type		Asset Values (3)		Liability Values (4)			Asset Values (3)		Liability Values (4)			Asset Values (3)			Liability Values (4)

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

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

	Netting arrangements (5)												(19,261.0	)		19,261.0
	Cash collateral												(92.6	)		125.6

Net fair values												$	924.3		$	(1,306.7	)

Net fair value by balance sheet line item:
Accounts receivable (2)												$	(348.7	)
Derivative assets—current													639.1
Derivative assets—noncurrent													633.9
Derivative liabilities—current																(632.6	)
Derivative liabilities—noncurrent																(674.1	)

Total Derivatives												$	924.3		$	(1,306.7	)

(1): Other commodity contracts include oil, freight, emission allowances, and weather contracts.
(2): Represents the unrealized fair value of exchange traded derivatives, exclusive of cash margin posted.
(3): Represents in-the-money contracts without regard to potentially offsetting out-of-the-money contracts under master netting agreements.
(4): Represents out-of-the-money contracts without regard to potentially offsetting in-the-money contracts under master netting agreements.
(5): Represents the effect of legally enforceable master netting agreements.

The magnitude of and changes in the gross derivatives components in this table 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 separate presentation is required for contracts that are in the money from those that are out of the money. As a result, the gross amounts of even fully hedged positions could increase if prices change. Additionally, if the number of contracts increases, the gross amounts also could increase. Thus, the execution of new contracts to reduce economic risk could actually increase the gross amounts in the table because of the requirement to present the gross value of each individual contract separately.

The primary purpose of this table is to disaggregate the risks being managed using derivatives. In order to achieve this objective, we 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

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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,
•: 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 and NewEnergy businesses, other than fair value hedges, for which we separately show the gain or loss on the hedged asset or liability. As a result, for mark-to-market and cash-flow hedge derivatives, these tables only reflect the impact of derivatives themselves and therefore do not necessarily include all of the income statement impacts of the transactions for which derivatives are used to manage risk. For a more complete discussion of how derivatives affect our financial performance, see our accounting policy for Revenues, Fuel and Purchased Energy Expenses, and Derivatives and Hedging Activities in Note 1.

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						Year Ended December 31, 2009


		Gain (Loss) Recorded in AOCI
		Gain (Loss) Recorded in AOCI				Gain (Loss) Reclassified from AOCI into Earnings			Ineffectiveness Gain (Loss) Recorded in Earnings
Contract type:		Year Ended December 31, 2009			Statement of Income (Loss) Line Item	Gain (Loss) Reclassified from AOCI into Earnings			Ineffectiveness Gain (Loss) Recorded in Earnings

					(In millions)
Hedges of forecasted sales:					Nonregulated revenues
	Power contracts	$	362.5			$	(180.6	)	$	77.5
	Gas contracts		(65.1	)			(67.3	)		6.3
	Coal contracts		10.0				(229.9	)		—
	Other commodity contracts (1)		6.8				(0.4	)		(6.2	)
Interest rate contracts			(0.3	)			(0.3	)		—
Foreign exchange contracts			2.5				(1.1	)		—

Total gains (losses)		$	316.4		Total included in nonregulated revenues	$	(479.6	)	$	77.6

Hedges of forecasted purchases:					Fuel and purchased energy expense
	Power contracts	$	(1,056.0	)		$	(1,905.3	)	$	(42.2	)
	Gas contracts		103.7				165.8			(15.2	)
	Coal contracts		(77.7	)			(187.6	)		(8.9	)
	Other commodity contracts (2)		(12.3	)			8.2			—
Foreign exchange contracts			—				—			—

Total losses		$	(1,042.3	)	Total included in fuel and purchased energy expense	$	(1,918.9	)	$	(66.3	)

Hedges of interest rates:					Interest expense
	Interest rate contracts		—				0.6			—

Total gains		$	—		Total included in interest expense	$	0.6		$	—

Grand total (losses) gains		$	(725.9	)		$	(2,397.9	)	$	11.3

(1): Other commodity sale contracts include oil and freight contracts.
(2): Other commodity purchase contracts include freight and emission allowances.

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The following table presents gains and losses on derivatives designated as fair value hedges and, separately, the gains and losses on the hedged item. As discussed earlier, we record the unrealized gains and losses on fair value hedges as well as changes in the fair value of the hedged asset or liability in earnings as they occur. The difference between these amounts represents hedge ineffectiveness. Due to the sale of our Houston-based gas trading operation, we do not have any activity under fair value hedges related to gas contracts since the second quarter of 2009.

Fair Value Hedges			Year Ended December 31, 2009


Contract type:		Statement of Income (Loss) Line Item	Gain (Loss) Recognized in Income on Derivative			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		(0.1	)		0.7

Total gains (losses)			$	40.5		$	(16.0	)

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, 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		Year Ended December 31, 2009


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

			(In millions)
Commodity contracts:
	Power contracts	Nonregulated revenues	$	250.9
	Gas contracts	Nonregulated revenues		(360.0	)
	Coal contracts	Nonregulated revenues		14.0
	Other commodity contracts (1)	Nonregulated revenues		(11.7	)
	Coal contracts	Fuel and purchased energy expense		(109.8	)
Interest rate contracts		Nonregulated revenues		(27.2	)
Foreign exchange contracts		Nonregulated revenues		7.6

Total gains (losses)			$	(236.2	)

(1): Other commodity contracts include oil, freight, emission allowances, weather, and uranium.

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

Volume of Derivative Activity

The volume of our derivatives activity is directly related to the fundamental nature and scope of our business and the risks we manage. We own or control electric generating facilities, which exposes us to both power and fuel price risk; we serve electric and gas wholesale and retail customers within our NewEnergy business, which exposes us to electricity and natural gas price risk; and we provide risk management services and engage in trading activities, which can expose us to a variety of commodity price risks. We conduct our business activities throughout the United States and internationally. In order to manage the risks associated with these activities, we are required to be an active participant in the energy markets, and we routinely employ derivative instruments to conduct our business.

Derivative instruments provide an efficient and effective way to conduct our business and to manage the associated risks. We manage our generating

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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. 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 positions within commodities for each year. This provides an indication of the level of derivatives activity, but it does not indicate either the direction of our position (long or short), or the overall size of our position. We believe this presentation gives an appropriate indication of the level of derivatives activity without unnecessarily revealing the size and direction of our derivatives positions.

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

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

Quantities (1) Under Derivative Contracts									As of December 31, 2009


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

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

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(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 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 $0.2 billion as of December 31, 2009, which represents the additional collateral that we could be required to post with counterparties, including both cash collateral and letters of credit, in the event of a credit downgrade to below investment grade. These amounts are associated with net derivative liabilities totaling $1.0 billion after reflecting legally binding master netting agreements and collateral already posted.

We present the gross fair value of derivatives in a net liability position that have credit-risk-related contingent features in the first column in the table 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.

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


Gross Fair Value of Derivative Contracts Containing This Feature (1)	Offsetting Fair Value of In-the-Money Contracts Under Master Netting Agreements (2)			Net Fair Value of Derivative Contracts Containing This Feature (3)		Amount of Posted Collateral (4)		Contingent Collateral Obligation (5)

				(In billions)
$8.6	$	(7.6	)	$	1.0	$	0.7	$	0.2

(1): Amount represents the gross fair value of out-of-the-money derivative contracts containing credit-risk-related contingent features that are not fully collateralized by posted cash collateral on an individual, contract-by-contract basis ignoring the effects of master netting agreements.
(2): Amount represents the offsetting fair value of in-the-money derivative contracts under legally-enforceable master netting agreements with the same counterparty, which reduces the amount of any liability for which we potentially could be required to post collateral.
(3): Amount represents the net fair value of out-of-the-money derivative contracts containing credit-risk related contingent features after considering the mitigating effects of offsetting positions under master netting arrangements and reflects the actual net liability upon which any potential contingent collateral obligations would be based.
(4): Amount includes cash collateral posted of $125.6 million and letters of credit of $585.2 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.

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Concentrations of Derivative-Related Credit Risk

We discuss our concentrations of credit risk, including derivative-related positions, in Note 1 to the Consolidated Financial Statements.

Fair Value Measurements

Effective January 1, 2008, we adopted guidance related to fair value measurements. This guidance defines fair value, establishes a framework for measuring fair value, and requires certain disclosures about fair value measurements. We discuss our fair value measurements below.

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 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 Note 8.

Recurring Measurements

Our assets and liabilities measured at fair value on a recurring basis consist of the following (BGE's assets and liabilities measured at fair value on a recurring basis are immaterial):

			As of December 31, 2009

			Assets			Liabilities

			(In millions)
Cash equivalents			$	3,065.4		$	—
Equity securities				46.2			—
Derivative instruments:
	Classified as derivative assets and liabilities:
		Current		639.1			(632.6	)
		Noncurrent		633.9			(674.1	)

		Total classified as derivative assets and liabilities		1,273.0			(1,306.7	)
	Classified as accounts receivable*			(348.7	)		—

	Total derivative instruments			924.3			(1,306.7	)

Total recurring fair value measurements			$	4,035.9		$	(1,306.7	)

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

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Cash equivalents represent exchange-traded money market funds which are included in "Cash and cash equivalents" in the Consolidated Balance Sheets. Equity securities primarily represent mutual fund investments which are included in "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. Each individual asset or liability that is remeasured at fair value on a recurring basis is required to be presented in this table and classified, in its entirety, within the appropriate level in the 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.

The tables below set 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 December 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 December 31, 2009		Level 1			Level 2			Level 3			Netting and Cash Collateral*			Total Net Fair Value


		(In millions)
Cash equivalents		$	3,065.4		$	—		$	—		$	—		$	3,065.4
Equity securities—mutual funds			46.2			—			—			—			46.2
Derivative assets			80.7			19,393.9			803.3			(19,353.6	)		924.3
Derivative liabilities			(79.0	)		(19,519.5	)		(1,094.8	)		19,386.6			(1,306.7	)

	Net derivative position		1.7			(125.6	)		(291.5	)		33.0			(382.4	)

Total		$	3,113.3		$	(125.6	)	$	(291.5	)	$	33.0		$	2,729.2

*: 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 December 31, 2009, we included $92.6 million of cash collateral held and $125.6 million of cash collateral posted (excluding margin posted on exchange traded derivatives) in netting amounts in the above table.

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The factors that cause changes in the gross components of the derivative amounts in the tables above are unrelated to the existence or level of actual market or credit risk from our operations. We describe the primary factors that change the gross components below.

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

Increases and decreases in the gross components presented in each of the levels in this table also do not indicate changes in the level of derivative activities. Rather, the primary factors affecting the gross amounts are commodity prices and the total number of contracts. If commodity prices change, the gross amounts could increase, even if the level of contracts stays the same, because separate presentation is required for contracts that are in the money from those that are out of the money. As a result, even 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 consist of exchange-traded money market funds, which are valued based upon unadjusted quoted prices in active markets and are classified within Level 1.

Equity securities consist of mutual funds, which are valued based upon unadjusted quoted prices in active markets and are classified within Level 1.

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 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, 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.

In order to determine fair value, we utilize various inputs and factors including market data and assumptions that market participants would use in pricing assets or liabilities as well as assumptions about the risks inherent in the inputs to the valuation technique. The inputs and factors include:

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

We also record valuation adjustments to reflect uncertainties associated with certain estimates inherent in the determination of the fair value of derivative assets and liabilities. The effect of these uncertainties is not incorporated in market price information or other market-based estimates used to determine fair value of our mark-to-market energy contracts. To the extent possible, we utilize market-based data together with quantitative methods for both measuring the uncertainties for which we record valuation adjustments and determining the level of such adjustments and changes in those levels.

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We describe below the main types of valuation adjustments we record and the process for establishing each. Generally, increases in valuation adjustments reduce our earnings, and decreases in valuation adjustments increase our earnings. However, all or a portion of the effect on earnings of changes in valuation adjustments may be offset by changes in the value of the underlying positions.

•: Close-out adjustment—represents the estimated cost to close out or sell to a third party open mark-to-market positions. This valuation adjustment has the effect of valuing "long" positions (the purchase of a commodity) at the bid price and "short" positions (the sale of a commodity) at the offer price. We compute this adjustment using a market-based estimate of the bid/offer spread for each commodity and option price and the absolute quantity of our net open positions for each year. The level of total close-out valuation adjustments increases as we have larger unhedged positions, bid-offer spreads increase, or market information is not available, and it decreases as we reduce our unhedged positions, bid-offer spreads decrease, or market information becomes available.
•: Unobservable input valuation adjustment—this adjustment is necessary when we determine fair value for derivative positions using internally developed models that use unobservable inputs due to the absence of observable market information. Unobservable inputs to fair value may arise due to a number of factors, including but not limited to, the term of the transaction, contract optionality, delivery location, or product type. In the absence of observable market information that supports the model inputs, there is a presumption that the transaction price is equal to the market value of the contract when we transact in our principal market and thus we recalibrate our estimate of fair value to equal the transaction price. Therefore we do not recognize a gain or loss at contract inception on these transactions. We will recognize such gains or losses in earnings as we realize cash flows under the contract or when observable market data becomes available.
•: Credit-spread adjustment—for risk management purposes, we compute the value of our derivative assets and liabilities using a risk-free discount rate. In order to compute fair value for financial reporting purposes, we adjust the value of our derivative assets to reflect the credit-worthiness of each counterparty based upon either published credit ratings, or equivalent internal credit ratings and associated default probability percentages. We compute this adjustment by applying a default probability percentage to our outstanding credit exposure, net of collateral, for each counterparty. The level of this adjustment increases as our credit exposure to counterparties increases, the maturity terms of our transactions increase, or the credit ratings of our counterparties deteriorate, and it decreases when our credit exposure to counterparties decreases, the maturity terms of our transactions decrease, or the credit ratings of our counterparties improve. As part of our evaluation, we assess whether the counterparties' published credit ratings are reflective of current market conditions. We review available observable data including bond prices and yields and credit default swaps to the extent it is available. We also consider the credit risk measurement implied by that data in determining our default probability percentages, and we evaluate its reliability based upon market liquidity, comparability, and other factors. We also use a credit-spread adjustment in order to reflect our own credit risk in determining the fair value of our derivative liabilities.

We regularly evaluate and validate the inputs we use to estimate fair value by a number of methods, consisting of various market price verification procedures, including the use of pricing services and multiple broker quotes to support the market price of the various commodities in which we transact, as well as review and verification of models and changes to those models. These activities are undertaken by individuals that are independent of those responsible for estimating fair value.

The Company's assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the classification of assets and liabilities within the fair value hierarchy. Because of the long-term nature of certain assets and liabilities measured at fair value as well as differences in the availability of market prices and market liquidity over their terms, inputs for some assets and liabilities may fall into any one of the three levels in the fair value hierarchy or some combination thereof. Thus, even though we are required to classify these assets and liabilities in the lowest level in the hierarchy for which inputs are significant to the fair value measurement, a portion of that measurement may be determined using inputs from a higher level in the hierarchy.

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

		Year Ended December 31,

		2009			2008

		(In millions)
Balance at beginning of period		$	37.0		$	(147.1	)
Realized and unrealized (losses) gains:
	Recorded in income		(486.9	)		471.2
	Recorded in other comprehensive income		201.6			(511.9	)
Purchases, sales, issuances, and settlements			49.1			37.6
Transfers into and out of Level 3			(92.3	)		187.2

Balance at end of year		$	(291.5	)	$	37.0

Change in unrealized gains recorded in income relating to derivatives still held at end of year		$	(27.8	)	$	800.1

Realized and unrealized gains (losses) are included primarily in "Nonregulated revenues" for our derivative contracts that are marked-to-market in our Consolidated Statements of Income (Loss) and are included in "Accumulated other comprehensive loss" for our derivative contracts designated as cash-flow hedges in our Consolidated Balance Sheets. We discuss the income statement classification for realized gains and losses related to cash-flow hedges for our various hedging relationships in Note 1.

Realized and unrealized gains (losses) include the realization of derivative contracts through maturity. This includes the fair value, as of the beginning of each quarterly reporting period, of contracts that matured during each quarterly reporting period. Purchases, sales, issuances, and settlements represent cash paid or received for option premiums, and the acquisition or termination of derivative contracts prior to maturity. Transfers into Level 3 represent existing assets or liabilities that were previously categorized at a higher level for which the inputs to the model became unobservable. Transfers out of Level 3 represent assets and liabilities that were previously classified as Level 3 for which the inputs became observable based on the criteria discussed previously for classification in either Level 1 or Level 2. Because the depth and liquidity of the power markets varies substantially between regions and time periods, the availability of observable inputs for substantially the full term and value of our bilateral derivative contracts changes frequently. As a result, we also expect derivatives balances to transfer into and out of Level 3 frequently based on changes in the observable data available as of the end of the period.

Nonrecurring Measurements

As of December 31, 2009, there were no assets or liabilities measured at fair value on a nonrecurring basis. The table below set forth by level within the fair value hierarchy our financial assets and liabilities that were measured at fair value on a nonrecurring basis as of December 31, 2008:

	Fair Value at December 31, 2008		Level 1		Level 2		Level 3		Losses for the year ended December 31, 2008


	(In millions)
Equity method investment	$	17.7	$	17.7	$	—	$	—	$	124.4

As described more fully in Note 2, during the third and fourth quarters of 2008 we recorded other-than-temporary impairment charges of $54.7 million and $69.7 million, respectively, on our equity method investment in 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 the fair value is a quoted price in an active market.

Fair Value of Financial Instruments

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

At December 31,		2009				2008


		Carrying Amount		Fair Value		Carrying Amount		Fair Value

		(In millions)
Investments and other assets—Constellation Energy		$	167.6	$	166.0	$	2,264.5	$	2,264.5
Fixed-rate long-term debt:
	Constellation Energy (including BGE)		4,225.0		4,433.1		6,995.4		6,290.3
	BGE		2,200.1		2,280.5		2,265.1		1,990.2
Variable-rate long-term debt:
	Constellation Energy (including BGE)		649.9		649.9		736.7		736.7
	BGE		—		—		—		—

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

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

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14 Stock-Based Compensation

Under our long-term incentive plans, we grant stock options, performance and service-based restricted stock, performance- and service-based units, and equity to officers, key employees, and members of the Board of Directors. In May 2007, shareholders approved Constellation Energy's 2007 Long-Term Incentive Plan, under which we can grant up to a total of 9,000,000 shares. Any shares covered by an outstanding award under any of our long-term incentive plans that are forfeited or cancelled, expire or are settled in cash will become available for issuance under the 2007 Long-Term Incentive Plan. At December 31, 2009, there were 5,790,545 shares available for issuance under the 2007 Long-Term Incentive Plan. At December 31, 2009, we had stock options, restricted stock, performance units and equity grants outstanding as discussed below. We may issue new shares, reuse forfeited shares, or buy shares in the market in order to deliver shares to employees for our equity grants. BGE officers and key employees participate in our stock-based compensation plans. The expense recognized by BGE in 2009, 2008, and 2007 was not material to BGE's financial results.

Non-Qualified Stock Options

Options are granted with an exercise price equal to the market value of the common stock at the date of grant, become vested over a period up to three years (expense recognized in tranches), and expire ten years from the date of grant.

The fair value of our stock-based awards was estimated as of the date of grant using the Black-Scholes option pricing model based on the following weighted- average assumptions:




Risk-free interest rate	1.95	%	2.57	%	4.69	%
Expected life (in years)	4.0		4.0		4.0
Expected market price volatility factor	37.8	%	25.8	%	20.3	%
Expected dividend yield	4.83	%	1.85	%	2.5	%

We use the historical data related to stock option exercises in order to estimate the expected life of our stock options. We also use historical data (measured on a daily basis) for a period equal to the duration of the expected life of option awards, information on the volatility of an identified group of peer companies, and implied volatilities for certain publicly traded options in Constellation Energy common stock in order to estimate the volatility factor. We believe that the use of this data to estimate these factors provides a reasonable basis for our assumptions. The risk-free interest rate for the periods within the expected life of the option is based on the U.S Treasury yield curve in effect and the expected dividend yield is based on our current estimate for dividend payout at the time of grant.

Summarized information for our stock option grants is as follows:

		2009					2008					2007

		Shares			Weighted- Average Exercise Price		Shares			Weighted- Average Exercise Price		Shares			Weighted- Average Exercise Price

		(Shares in thousands)
Outstanding, beginning of year			6,058		$	59.99		6,145		$	55.90		6,051		$	47.23
	Granted with exercise prices at fair market value		3,511			20.14		1,434			93.79		1,759			76.22
	Exercised		(83	)		31.07		(375	)		47.02		(1,411	)		41.91
	Forfeited/expired		(1,340	)		52.41		(1,146	)		84.59		(254	)		67.85

Outstanding, end of year			8,146		$	44.36		6,058		$	59.99		6,145		$	55.90

Exercisable, end of year			4,114		$	55.81		4,665		$	52.13		4,043		$	48.51

	Weighted-average fair value per share of options granted with exercise prices at fair market value				$	4.24				$	18.75				$	13.76

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The following table summarizes additional information about stock options during 2009, 2008 and 2007:

		2009		2008		2007


		(In millions)
Stock Option Expense Recognized		$	14.2	$	11.0	$	15.1
Stock Options Exercised:
	Cash Received for Exercise Price		2.6		20.2		43.4
	Intrinsic Value Realized by Employee		0.2		14.1		67.6
	Realized Tax Benefit		0.1		5.7		26.7
Fair Value of Options that Vested			11.0		98.3		82.7

As of December 31, 2009, we had $4.0 million of unrecognized compensation cost related to the unvested portion of outstanding stock option awards, of which $2.9 million is expected to be recognized during 2010.

The following table summarizes additional information about stock options outstanding at December 31, 2009 (stock options in thousands):

	Outstanding				Exercisable

	Outstanding				Exercisable				Weighted- Average Remaining Contractual Life
Range of Exercise Prices	Stock Options		Aggregate Intrinsic Value		Stock Options		Aggregate Intrinsic Value		Weighted- Average Remaining Contractual Life

			(In millions)				(In millions)		(In years)
$ 0 – $ 20		3,140	$	49.4		—	$	—		9.2
$20 – $ 40		1,141		3.1		996		2.1		4.3
$40 – $ 60		2,306		—		2,306		—		5.6
$60 – $ 80		792		—		543		—		7.2
$80 – $100		767		—		269		—		8.1

		8,146	$	52.5		4,114	$	2.1

Restricted Stock Awards

In addition to stock options, we issue common stock based on meeting certain service goals. This stock vests to participants at various times ranging from one to five years if the service goals are met. We account for our service-based awards as equity awards, whereby we recognize the value of the market price of the underlying stock on the date of grant to compensation expense over the service period either ratably or in tranches (depending if the award has cliff or graded vesting).

We recorded compensation expense related to our restricted stock awards of $16.7 million in 2009, $35.3 million in 2008, and $35.8 million in 2007. The tax benefits received associated with our restricted awards were $6.7 million in 2009, $20.1 million in 2008, and $17.6 million in 2007.

Summarized share information for our restricted stock awards is as follows:

		2009			2008			2007


		(Shares in thousands)
Outstanding, beginning of year			1,033			1,322			1,207
	Granted		866			365			710
	Released to participants		(701	)		(536	)		(552	)
	Canceled		(181	)		(118	)		(43	)

Outstanding, end of year			1,017			1,033			1,322

Weighted-average fair value of restricted stock granted (per share)		$	19.83		$	94.62		$	75.29

Total fair value of shares for which restriction has lapsed (in millions)		$	16.5		$	49.7		$	44.5

As of December 31, 2009, we had $8.6 million of unrecognized compensation cost related to the unvested portion of outstanding restricted stock awards expected to be recognized within a 29-month period. At December 31, 2009, we have recorded in "Common shareholders' equity" approximately $37.4 million and approximately $47.8 million at December 31, 2008 for the unvested portion of service-based restricted stock granted from 2007 until 2009 to officers and other employees that is contingently redeemable in cash upon a change in control.

Performance-Based Units

We recognize compensation expense ratably for our performance-based awards, which are classified as liability awards, for which the fair value of the award is remeasured at each reporting period. Each unit is equivalent to $1 in value and cliff vests at the end of a three-year service and performance period. The level of payout is based on the achievement of certain performance goals at the end of the three-year period and will be settled in cash. We reported compensation expense of $1.5 million in 2009, a reduction of expense of $3.2 million in 2008, and compensation expense of $17.6 million in 2007 for these awards. During the 12 months ended December 31, 2009, no performance-based unit awards vested. During the 12 months ended December 31, 2008, our 2005 performance-based unit award vested and we paid $24.2 million in cash to settle the award. During the 12 months ended December 31, 2007, our 2004 performance-based unit award vested and we paid $19.7 million in cash to settle the award. As of December 31, 2009, we had $10.0 million of unrecognized compensation cost related to the unvested portion of outstanding performance-based unit awards expected to be recognized within a 26-month period.

Equity-Based Grants

We recorded compensation expense of $0.9 million in 2009, $0.9 million in 2008, and $0.9 million in 2007 related to equity-based grants to members of the Board of Directors.

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15 Merger and Acquisitions

CLT Efficient Technologies Group

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

We acquired 100% ownership of CLT for $21.9 million, of which $20.8 million was paid in cash at closing.

Our final purchase price allocation related to CLT is as follows:

At July 1, 2009


	(In millions)
Current assets	$	5.7
Goodwill (1)		18.6
Other assets		2.3

Total assets acquired		26.6

Current liabilities		(4.7	)

Net assets acquired	$	21.9

(1): 100% deductible for tax purposes.

The pro-forma impact of the CLT acquisition would not have been material to our results of operations for the years ended December 31, 2009, 2008, and 2007.

Criterion Wind Project

On November 30, 2009, we signed an agreement to acquire the Criterion wind project in Garrett County, Maryland. The completed cost of this project is expected to be approximately $140 million. This 70 MW wind energy project would be developed, constructed, owned, and operated by us. We expect to close this transaction, subject to certain conditions in the first quarter of 2010 and expect commercial operation of the facility in the fall of 2010.

Termination of Merger Agreement with MidAmerican

On December 17, 2008 Constellation Energy and MidAmerican agreed to terminate the Agreement and Plan of Merger the parties entered into on September 19, 2008.

In connection with the termination and conversion of our Series A Preferred Stock, we made certain payments and issued certain securities to MidAmerican. Specifically, we:

•: paid MidAmerican the $175 million merger termination fee,
•: paid MidAmerican approximately $418 million in lieu of the number of shares of our common stock (valued at $26.50 per share) that were due to MidAmerican on the conversion of Series A Preferred Stock but that could not be issued due to regulatory limitations,
•: issued and delivered a total of 19,897,322 shares of our common stock, representing 9.99% of our total outstanding common shares (after giving effect to the issuance, due upon conversion of the Series A Preferred Stock). The fair value of the common stock on the date of issuance was estimated to be $572.6 million based on the stock price at the time of issuance. We also delivered to MidAmerican 14% Senior Notes in the aggregate principal amount of $1.0 billion, also issued upon the conversion of the Series A Preferred Stock.

We discuss the merger termination fee in more detail in Note 2.

Nufcor International Limited

On June 26, 2008, we acquired 100% ownership of Nufcor International Limited (Nufcor), a uranium market participant that provides marketing services to uranium producers, utilities and an investment fund in the North American and European markets, for $102.8 million. We included Nufcor as part of our NewEnergy business segment and had included its results of operations in our consolidated financial statements since the date of acquisition until its sale on June 30, 2009. We discuss this divestiture in more detail in Note 2.

West Valley Power Plant

On June 1, 2008, we acquired the West Valley Power Plant, a 200 MW gas-fired peaking plant located in Utah for approximately $88.6 million (including direct costs). We accounted for this transaction as an asset acquisition and have included this plant's results of operations in the Generation business segment since the date of acquisition. We allocated the purchase price primarily to the equipment with lesser amounts allocated to land and spare parts inventory.

Hillabee Energy Center

On February 14, 2008, we acquired the Hillabee Energy Center, a partially completed 740 MW gas-fired combined cycle power generation facility located in Alabama for $156.9 million (including direct costs), which we accounted for as an asset acquisition. We allocated the purchase price primarily to the equipment with lesser amounts allocated to land and contracts acquired. We plan to complete the construction of this facility and expect it to be ready for commercial operation in the first quarter of 2010.

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16 Related Party Transactions

Constellation Energy

CENG

On November 6, 2009, upon the sale of a membership interest in CENG, our nuclear generation and operation business, to EDF, we deconsolidated CENG and began accounting for our 50.01% membership interest in CENG as an equity method investment.

In connection with the closing of the transaction with EDF, we entered into a power purchase agreement (PPA) with CENG with a fair value of $0.8 billion where we will purchase between 85-90% of the output of CENG's nuclear plants that is not sold to third parties under pre-existing PPAs over the five year term of the PPA.

For the period from November 6, 2009 through December 31, 2009, we recognized $122.5 million in purchased power costs from CENG.

In addition to the PPA, we entered into a power services agency agreement (PSA) and an administrative service agreement (ASA). The PSA is a five-year agreement under which we will provide scheduling, asset management and billing services to CENG and recognize average annual revenue of approximately $16 million. For the period from November 6, 2009 through December 31, 2009, we recognized $2.7 million in revenue for services rendered under the PSA with CENG.

The ASA is a one year agreement that is renewable annually under which we will provide administrative support services to CENG for a fee of approximately $66 million for 2010. The fees for administrative support services will be subject to change in future years based on the level of services provided. The charges under this agreement are intended to represent the actual cost of the services provided to CENG from us. For the period from November 6, 2009 through December 31, 2009, we recognized $10.0 million for services rendered under the ASA with CENG as an offset to operating expenses.

UNE

We discuss our relationship with UNE in Note 4.

CEP

On March 31, 2008, our NewEnergy business sold its working interest in 83 oil and natural gas producing wells in Oklahoma to CEP, an equity method investment of Constellation Energy, for total proceeds of approximately $53 million. Our NewEnergy business recognized a $14.3 million gain, net of the minority interest gain of $0.7 million on the sale and exclusive of our 28.5% ownership interest in CEP. This gain is recorded in "Gains on Sales of Assets" in our Consolidated Statements of Income (Loss).

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 NewEnergy business will supply a portion of BGE's market-based standard offer service obligation to electric customers through May 31, 2012.

The cost of BGE's purchased energy from nonregulated subsidiaries of Constellation Energy to meet its standard offer service obligation was as follows:

Year Ended December 31,	2009		2008		2007


	(In millions)
Electricity purchased for resale expenses	$	623.5	$	802.0	$	1,139.6

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

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

Year ended December 31,	2009		2008		2007


	(In millions)
Charges to BGE	$	164.7	$	153.6	$	160.8

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 $314.7 million at December 31, 2009 and $148.8 million at December 31, 2008.

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

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

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17 Quarterly Financial Data (Unaudited)

Our quarterly financial information has not been audited but, in management's opinion, includes all adjustments necessary for a fair statement. Our business is seasonal in nature with the peak sales periods generally occurring during the summer and winter months. Accordingly, comparisons among quarters of a year may not represent overall trends and changes in operations.

2009 Quarterly Data—Constellation Energy																								2009 Quarterly Data—BGE

		Revenues		Income (Loss) from Operations			Other (Expense) Income *			Total Fixed Charges *		Net Income (Loss)			Net Income Attributable to Common Stock			Earnings (Loss) Per Share from Operations— Diluted			Earnings (Loss) Per Share of Common Stock— Diluted				Revenues		Income (Loss) from Operations			Net Income			Net Income Attributable to Common Stock

		(In millions, except per share amounts)																							(In millions)
Quarter Ended																								Quarter Ended
	March 31	$	4,303.4	$	(212.1	)	$	(56.3	)	$	93.5	$	(119.7	)	$	(123.5	)	$	(0.62	)	$	(0.62	)	March 31	$	1,193.7	$	168.7		$	85.0		$	81.7
	June 30		3,864.1		230.6			(15.0	)		84.5		28.3			8.1			0.04			0.04		June 30		767.4		54.3			16.0			12.7
	September 30		4,027.7		534.3			11.6			80.1		167.4			137.6			0.69			0.69		September 30		866.5		78.7			32.3			28.6
	December 31		3,403.6		7,428.2			(81.0	)		92.0		4,427.4			4,421.2			21.96			21.96		December 31		751.4		(33.3	)		(42.6	)		(38.2	)

Year Ended																								Year Ended
	December 31	$	15,598.8	$	7,981.0		$	(140.7	)	$	350.1	$	4,503.4		$	4,443.4		$	22.19		$	22.19		December 31	$	3,579.0	$	268.4		$	90.7		$	84.8

The sum of the quarterly earnings per share amounts may not equal the total for the year due to the effects of rounding and dilution.

*: In the fourth quarter of 2009, we modified our policy for the classification of credit facility fees and we reclassified amounts for the first three quarters of 2009 to conform with that policy. Amounts prior to 2009 were not material. See Note 1 for a discussion of our policy for the classification of credit facility fees.

First quarter results include:

•: a $184.2 million after-tax loss on the 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,
•: a $5.1 million after-tax charge for the impairment of our investment in CEP LLC,
•: a $23.8 million after-tax charge for the impairment of certain of our nuclear decommissioning trust fund investments,
•: a $6.0 million after-tax charge for certain long-lived assets that ceased to be used in connection with the divestiture of a majority of our international commodities operation and our Houston-based gas trading operation,
•: merger termination and strategic alternatives costs totaling $42.3 million after-tax,
•: workforce reduction costs totaling $4.2 million after-tax, and
•: a $3.7 million after-tax amortization of credit facility amendment fees in connection with the EDF transaction.

Second quarter results include:

•: a $123.8 million after-tax loss on the sale of a majority of our international commodities operation, our Houston-based gas trading operation, certain other trading operations, and a uranium market participant, 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,
•: a $59.0 after-tax charge for the impairment of our shipping joint venture,
•: a $6.1 million after-tax charge for the impairment of certain of our nuclear decommissioning trust fund investments,
•: a $4.9 million after-tax charge for certain long-lived assets that ceased to be used in connections with the divestiture of a majority of our international commodities operation and our Houston-based gas trading operation as well as the write-off of an uncollectible advance to an affiliate,
•: a $1.5 million after-tax charge for the impairment of our investment in CEP LLC,
•: merger termination and strategic alternatives costs totaling $4.0 million after-tax,
•: workforce reduction costs totaling $1.1 million after-tax, and
•: a $5.2 million after-tax amortization of credit facility amendment fees in connection with the EDF transaction.

Third quarter results include:

•: a $62.9 million after-tax loss on the sale of a majority of our international commodities operation, our Houston-based gas trading operation, certain other trading operations, and a uranium market participant, 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,

127

•: a $19.7 million after-tax charge for the impairment of certain of our nuclear decommissioning trust fund investments (primarily due to income tax adjustments),
•: a $9.0 million after-tax charge for certain long-lived assets that ceased to be used in connection with the divestiture of a majority of our international commodities operation and our Houston-based gas trading operation,
•: merger termination and strategic alternatives costs totaling $4.9 million after-tax,
•: workforce reduction costs totaling $1.6 million after-tax, and
•: a $8.2 million after-tax amortization of credit facility amendment fees in connection with the EDF transaction.

Fourth quarter results include:

•: a $4,456.1 million after-tax gain on sale of a 49.99% membership interest in CENG to EDF,
•: a $17.8 million after-tax charge for amortization of the basis difference in CENG,
•: a $1.0 million after-tax loss on the sale of a majority of our international commodities operation, our Houston-based gas trading operation, certain other trading operations, and a uranium market participant, 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,
•: a $3.6 million after-tax charge for certain long-lived assets that ceased to be used in connections with the divestiture of a majority of our international commodities operation and our Houston-based gas trading operation,
•: a $7.1 million after-tax charge for the impairment of BGE's nonregulated subsidiary, District Chilled Water, net of noncontrolling interest,
•: a $2.8 million after-tax benefit for the impairment of certain of our nuclear decommissioning trust fund investments (primarily due to income tax adjustments),
•: a $10.0 million after-tax loss on redemption of our zero coupon senior notes,
•: a $67.1 million after-tax charge for a BGE customer rate credit,
•: merger termination and strategic alternatives costs benefit totaling $37.4 million after-tax due to a true-up for 2008 and 2009 expenses that became tax deductible upon the close of the transaction with EDF on November 6, 2009,
•: workforce reduction costs totaling $2.4 million after-tax, and
•: a $20.6 million after-tax credit facility amendment and termination fees in connection with the EDF transaction.

We discuss these items in Note 2.

2008 Quarterly Data—Constellation Energy																			2008 Quarterly Data—BGE

		Revenues		Income (Loss) from Operations			Net Income (Loss)			Net Income (Loss) Attributable to Common Stock			Earnings (Loss) Per Share from Operations— Diluted			Earnings (Loss) Per Share of Common Stock— Diluted				Revenues		Income (Loss) from Operations			Net Income			Net Income (Loss) Applicable to Common Stock

		(In millions, except per share amounts)																		(In millions)
Quarter Ended																			Quarter Ended
	March 31	$	4,812.2	$	254.3		$	149.4		$	145.7		$	0.81		$	0.81		March 31	$	1,105.8	$	137.7		$	76.2		$	73.0
	June 30		4,756.1		331.7			175.0			171.5			0.95			0.95		June 30		636.8		(131.1	)		(104.2	)		(107.4	)
	September 30		5,323.6		(228.4	)		(222.1	)		(225.7	)		(1.27	)		(1.27	)	September 30		977.9		69.6			23.5			19.9
	December 31		4,850.0		(1,335.7	)		(1,420.7	)		(1,405.9	)		(7.75	)		(7.75	)	December 31		983.2		106.3			56.0			52.8

Year Ended																			Year Ended
	December 31	$	19,741.9	$	(978.1	)	$	(1,318.4	)	$	(1,314.4	)	$	(7.34	)	$	(7.34	)	December 31	$	3,703.7	$	182.5		$	51.5		$	38.3

The sum of the quarterly earnings per share amounts may not equal the total for the year due to the effects of rounding and dilution as a result of issuing common shares during the year.

First quarter results include:

•: a $3.9 million after-tax charge for the impairment of certain of our nuclear decommissioning trust fund investments,
•: a $6.6 million tax benefit related to the anticipated finalization of the Maryland settlement agreement, and
•: a $9.1 million after-tax gain on the sale of certain working interests in an upstream gas property.

Second quarter results include:

•: a $2.4 million after-tax charge for the impairment of certain of our nuclear decommissioning trust fund investments,
•: a $13.4 million after-tax charge related to the write-down of our emission allowance inventory,
•: a $125.3 million after-tax charge related to the one-time $170 residential electric customer credit related to the Maryland settlement agreement,
•: a $2.1 million tax benefit related to the Maryland settlement agreement, and
•: a $46.2 million after-tax gain on the sale of certain working interests in upstream gas properties.

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Third quarter results include:

•: a $169.1 million after-tax charge for the impairment of goodwill,
•: a $86.6 million after-tax charge for the impairments of certain of our upstream gas properties,
•: a $34.2 million after-tax charge for the impairment of our investment in CEP LLC,
•: a $22.8 million after-tax charge related to the write-down of our emission allowance inventory,
•: a $15.3 million after-tax charge for the impairment of certain of our nuclear decommissioning trust fund investments,
•: a $18.9 million after-tax gain on the sale of a dry bulk vessel in our shipping joint venture,
•: merger and strategic alternatives costs totaling $37.3 million after-tax, of which BGE recorded $10.6 million after-tax,
•: estimated settlement costs totaling $8.9 million after-tax related to a class action complaint alleging ash placement at a third party site damaged surrounding properties,
•: workforce reduction costs totaling $1.6 million after-tax related to our NewEnergy business, and
•: a $2.0 million tax benefit related to the Maryland settlement agreement.

Fourth quarter results include:

•: a $119.8 million after-tax charge for the impairments of certain of our upstream gas properties,
•: a $50.6 million loss after-tax for an impairment of our investment in CEP LLC and a marketable security held by our NewEnergy business segment,
•: a $7.5 million after-tax gain related to the recovery in the value of our emission allowance inventory,
•: a $60.4 million after-tax charge for the impairment of certain of our nuclear decommissioning trust fund investments,
•: a $39.3 million after-tax loss on the sale of certain upstream gas properties,
•: merger termination and strategic alternatives costs totaling $1,167.1 million after-tax, of which BGE recorded a cost reduction of $10.6 million after-tax associated with the re-allocation of costs prior to EDF transaction to our Generation and NewEnergy business segments,
•: workforce reduction costs totaling $11.8 million after-tax related to our company-wide reduction in force,
•: a $0.6 after-tax benefit for an adjustment to the estimated settlement costs relating to the class action ash placement complaint,
•: a $2.1 million after-tax charge for an adjustment to the impairment of goodwill,
•: a $1.2 million loss after-tax related to a final true-up of the one-time $170 residential electric customer credit related to the Maryland settlement agreement, and
•: a $5.3 million tax benefit related to the Maryland settlement agreement.

We discuss these items in Note 2.

129

CONSTELLATION ENERGY GROUP, INC. AND SUBSIDIARIES
AND
BALTIMORE GAS AND ELECTRIC COMPANY AND SUBSIDIARIES

SCHEDULE II—VALUATION AND QUALIFYING ACCOUNTS

Column A			Column B			Column C						Column D			Column E

						Additions
Description			Balance at beginning of period			Charged to costs and expenses			Charged to Other Accounts— Describe			(Deductions)— Describe			Balance at end of period
			(In millions)
Reserves deducted in the Balance Sheet from the assets to which they apply:
Constellation Energy
	Accumulated Provision for Uncollectibles
		2009	$	240.6		$	71.2		$	(5.0	)(A)	$	(146.2	)(C)	$	160.6
		2008		44.9			127.1			102.3	(B)		(33.7	)(C)		240.6
		2007		48.9			31.3			—			(35.3	)(C)		44.9
	Valuation Allowance
		Net unrealized (gain) loss on available for sale securities
		2009		2.1			(3.6	)		(1.3	)(D)		—			(2.8	)
		2008		(17.3	)		7.0			0.3	(D)		12.1	(E)		2.1
		2007		(18.5	)		—			1.2	(D)		—			(17.3	)
		Net unrealized (gain) loss on nuclear decommissioning trust funds
		2009		(49.6	)		—			(201.0	)(D)		250.6	(F)		—
		2008		(256.7	)		—			207.1	(D)		—			(49.6	)
		2007		(206.1	)		—			(50.6	)(D)		—			(256.7	)
BGE
	Accumulated Provision for Uncollectibles
		2009		34.2			41.8			—			(28.8	)(C)		47.2
		2008		21.1			34.5			—			(21.4	)(C)		34.2
		2007		16.1			21.0			—			(16.0	)(C)		21.1

(A): Represents amounts recorded as an increase to nonregulated revenues resulting from a settlement with a counterparty that was in default.
(B): Represents amounts recorded as a reduction to nonregulated revenues resulting from liquidated damages claims upon termination of derivatives which were determined to be uncollectible.
(C): Represents principally net amounts charged off as uncollectible.
(D): Represents amounts recorded in or reclassified from accumulated other comprehensive income.
(E): Represents sale of a marketable security.
(F): Represents decrease due to the deconsolidation of CENG.

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Exhibit 99.3

Item 8. Financial Statements and Supplementary Data