Edgar Filing: BALTIMORE GAS & ELECTRIC CO

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TABLE OF CONTENTS

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

FORM 10-Q

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

For The Quarterly Period Ended June 30, 2010


Commission File Number	Exact name of registrant as specified in its charter	IRS Employer Identification No.
1-12869	CONSTELLATION ENERGY GROUP, INC.	52-1964611
100 CONSTELLATION WAY, BALTIMORE, MARYLAND 21202 (Address of principal executive offices) (Zip Code)
410-470-2800 (Registrant's telephone number, including area code)
1-1910	BALTIMORE GAS AND ELECTRIC COMPANY	52-0280210
2 CENTER PLAZA, 110 WEST FAYETTE STREET, BALTIMORE, MARYLAND 21202 (Address of principal executive offices) (Zip Code)
410-234-5000 (Registrant's telephone number, including area code)
MARYLAND (State of Incorporation of both registrants)
NOT APPLICABLE (Former name, former address and former fiscal year, if changed since last report)

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

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

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

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


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

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


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

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

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

Common Stock, without par value 201,961,349 shares outstanding
of Constellation Energy Group, Inc. on July 30, 2010.

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

Table of Contents

TABLE OF CONTENTS

			Page

Part I—Financial Information			2
	Item 1—Financial Statements		2
		Constellation Energy Group, Inc. and Subsidiaries
		Consolidated Statements of Income (Loss)	2
		Consolidated Statements of Comprehensive Income	2
		Consolidated Balance Sheets	3
		Consolidated Statements of Cash Flows	5
		Baltimore Gas and Electric Company and Subsidiaries
		Consolidated Statements of Income	6
		Consolidated Balance Sheets	7
		Consolidated Statements of Cash Flows	9
		Notes to Consolidated Financial Statements	10
	Item 2—Management's Discussion and Analysis of Financial Condition and Results of Operations		39
		Introduction and Overview	39
		Business Environment	39
		Events of 2010	41
		Results of Operations	42
		Financial Condition	58
		Capital Resources	61
	Item 3—Quantitative and Qualitative Disclosures About Market Risk		67
	Items 4 and 4(T)—Controls and Procedures		67
Part II—Other Information			68
	Item 1—Legal Proceedings		68
	Item 2—Issuer Purchases of Equity Securities		68
	Item 5—Other Information		69
	Item 6—Exhibits		70
	Signature		71

Table of Contents

PART 1—FINANCIAL INFORMATION

Item 1—Financial Statements

CONSOLIDATED STATEMENTS OF INCOME (LOSS) (UNAUDITED)

Constellation Energy Group, Inc. and Subsidiaries

		Three Months Ended June 30,						Six Months Ended June 30,

		2010			2009			2010			2009

		(In millions, except per share amounts)
Revenues
	Nonregulated revenues	$	2,559.2		$	3,097.3		$	5,077.4		$	6,209.6
	Regulated electric revenues		651.1			655.7			1,402.4			1,462.5
	Regulated gas revenues		99.6			111.1			416.7			495.4

	Total revenues		3,309.9			3,864.1			6,896.5			8,167.5
Expenses
	Fuel and purchased energy expenses		2,267.7			2,631.6			4,629.8			5,904.8
	Fuel and purchased energy expenses from affiliate		222.1			—			420.6			—
	Operating expenses		413.7			561.2			810.1			1,142.9
	Merger termination and strategic alternatives costs		—			4.0			—			46.3
	Impairment losses and other costs		—			67.2			—			95.8
	Workforce reduction costs		—			0.4			—			11.2
	Depreciation, depletion, and amortization		125.3			148.9			256.7			297.5
	Accretion of asset retirement obligations		0.4			18.2			0.9			36.1
	Taxes other than income taxes		65.6			72.4			132.4			150.3

	Total expenses		3,094.8			3,503.9			6,250.5			7,684.9
Equity Investment Losses			(33.5	)		—			(54.2	)		—
Net Gain (Loss) on Divestitures			0.3			(129.6	)		5.2			(464.1	)

Income from Operations			181.9			230.6			597.0			18.5
Other Expenses			(8.9	)		(15.0	)		(31.2	)		(71.3	)
Fixed Charges
	Interest expense		60.4			106.1			181.9			221.2
	Interest capitalized and allowance for borrowed funds used during construction		(8.7	)		(21.6	)		(24.3	)		(43.2	)

	Total fixed charges		51.7			84.5			157.6			178.0

Income (Loss) from Continuing Operations Before Income Taxes			121.3			131.1			408.2			(230.8	)
Income Tax Expense (Benefit)			37.5			102.8			133.1			(139.4	)

Net Income (Loss)			83.8			28.3			275.1			(91.4	)
Less: Net Income Attributable to Noncontrolling Interests and BGE Preference Stock Dividends			11.2			20.2			11.0			24.0

Net Income (Loss) Attributable to Common Stock		$	72.6		$	8.1		$	264.1		$	(115.4	)

Average Shares of Common Stock Outstanding—Basic			200.8			199.2			200.6			198.9
Average Shares of Common Stock Outstanding—Diluted			202.6			200.0			202.2			198.9

Earnings (Loss) Per Common Share—Basic		$	0.36		$	0.04		$	1.32		$	(0.58	)

Earnings (Loss) Per Common Share—Diluted		$	0.36		$	0.04		$	1.31		$	(0.58	)

Dividends Declared Per Common Share		$	0.24		$	0.24		$	0.48		$	0.48

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)

Constellation Energy Group, Inc. and Subsidiaries

				Three Months Ended June 30,						Six Months Ended June 30,

				2010			2009			2010			2009

				(In millions)
Net Income (Loss)				$	83.8		$	28.3		$	275.1		$	(91.4	)
	Other comprehensive income (OCI)
		Hedging instruments:
			Reclassification of net loss on hedging instruments from OCI to net income (loss), net of taxes		179.4			410.5			287.9			867.7
			Net unrealized gain (loss) on hedging instruments, net of taxes		70.9			(57.3	)		(162.0	)		(396.5	)
		Available-for-sale securities:
			Reclassification of net (gain) loss on sales of securities from OCI to net (loss) income, net of taxes		—			(0.2	)		(0.1	)		29.5
			Net unrealized gain on securities, net of taxes		—			45.6			0.2			18.9
		Defined benefit obligations:
			Amortization of net actuarial loss, prior service cost, and transition obligation included in net periodic benefit cost, net of taxes		4.9			14.2			10.8			22.1
		Net unrealized (loss) gain on foreign currency, net of taxes			(10.7	)		2.5			(9.0	)		4.5
		Other comprehensive (loss) income—equity investment in CENG, net of taxes			(22.1	)		—			(12.2	)		—
		Other comprehensive (loss) income—other equity method investees, net of taxes			(0.3	)		(2.4	)		(0.5	)		3.3

	Comprehensive income				305.9			441.2			390.2			458.1
		Less: Comprehensive income attributable to noncontrolling interests, net of taxes			11.2			20.2			11.0			24.0

Comprehensive Income Attributable to Common Stock				$	294.7		$	421.0		$	379.2		$	434.1

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

Table of Contents

CONSOLIDATED BALANCE SHEETS

Constellation Energy Group, Inc. and Subsidiaries

			*June 30,* 2010*			December 31, 2009


			(In millions)
Assets
	Current Assets
		Cash and cash equivalents	$	1,603.2		$	3,440.0
		Accounts receivable (net of allowance for uncollectibles of $71.4 and $80.4, respectively)		1,933.1			1,778.2
		Accounts receivable—consolidated variable interest entities (net of allowance for uncollectibles of $87.5 and $80.2, respectively)		239.2			359.4
		Fuel stocks		356.6			314.9
		Materials and supplies		101.7			93.3
		Derivative assets		558.2			639.1
		Unamortized energy contract assets (includes $382.0 and $371.3, respectively, related to CENG)		447.7			436.5
		Restricted cash		2.0			2.7
		Restricted cash—consolidated variable interest entities		73.9			24.3
		Deferred income taxes		88.0			127.9
		Other		166.1			244.4

		Total current assets		5,569.7			7,460.7

Investments and Other Noncurrent Assets
		Investment in CENG		5,164.8			5,222.9
		Other investments		399.7			424.3
		Regulatory assets (net)		386.7			414.4
		Goodwill		25.5			25.5
		Derivative assets		550.2			633.9
		Unamortized energy contract assets (includes $210.4 and $400.9, respectively, related to CENG)		372.1			604.7
		Other		254.4			304.2

		Total investments and other noncurrent assets		7,153.4			7,629.9

Property, Plant and Equipment
		Property, plant and equipment		13,193.7			12,534.5
		Accumulated depreciation		(4,207.4	)		(4,080.7	)

		Net property, plant and equipment		8,986.3			8,453.8

	Total Assets		$	21,709.4		$	23,544.4

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

Table of Contents

CONSOLIDATED BALANCE SHEETS

Constellation Energy Group, Inc. and Subsidiaries

				*June 30,* 2010*			December 31, 2009


				(In millions)
Liabilities and Equity
	Current Liabilities
		Short-term borrowings		$	29.0		$	46.0
		Current portion of long-term debt			—			0.4
		Current portion of long-term debt—consolidated variable interest entities			58.1			56.5
		Accounts payable			987.6			916.3
		Accounts payable—consolidated variable interest entities			152.7			234.2
		Derivative liabilities			621.6			632.6
		Unamortized energy contract liabilities			249.9			390.1
		Accrued taxes			55.3			877.3
		Accrued expenses			275.2			409.8
		Other			388.8			477.5

		Total current liabilities			2,818.2			4,040.7

	Deferred Credits and Other Noncurrent Liabilities
		Deferred income taxes			3,185.1			3,205.5
		Asset retirement obligations			30.4			29.3
		Derivative liabilities			633.0			674.1
		Unamortized energy contract liabilities			472.5			653.7
		Defined benefit obligations			734.9			743.9
		Deferred investment tax credits			29.8			32.0
		Other			345.8			388.8

		Total deferred credits and other noncurrent liabilities			5,431.5			5,727.3

	Long-term Debt, Net of Current Portion				3,765.4			4,359.6
	Long-term Debt, Net of Current Portion—consolidated variable interest entities				424.7			454.4
	Equity
		Common shareholders' equity:
			Common stock		3,284.8			3,229.6
			Retained earnings		6,614.5			6,461.0
			Accumulated other comprehensive loss		(878.4	)		(993.5	)

		Total common shareholders' equity			9,020.9			8,697.1
		BGE preference stock not subject to mandatory redemption			190.0			190.0
		Noncontrolling interests			58.7			75.3

		Total equity			9,269.6			8,962.4

	Commitments, Guarantees, and Contingencies (see Notes)
	Total Liabilities and Equity			$	21,709.4		$	23,544.4

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

Table of Contents

CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)

Constellation Energy Group, Inc. and Subsidiaries

Six Months Ended June 30,				2010			2009


				(In millions)
Cash Flows From Operating Activities
	Net income (loss)			$	275.1		$	(91.4	)
	Adjustments to reconcile to net cash (used in) provided by operating activities
		Depreciation, depletion, and amortization			256.7			297.5
		Amortization of nuclear fuel			—			67.0
		Amortization of energy contracts and derivatives designated as hedges			70.6			(86.7	)
		All other amortization			14.6			74.9
		Accretion of asset retirement obligations			0.9			36.1
		Deferred income taxes			(47.9	)		(121.6	)
		Investment tax credit adjustments			(2.2	)		(3.0	)
		Deferred fuel costs			39.0			32.4
		Defined benefit obligation expense			33.7			64.7
		Defined benefit obligation payments			(39.0	)		(328.6	)
		Workforce reduction costs			—			11.2
		Impairment losses and other costs			—			95.8
		Impairment losses on nuclear decommissioning trust assets			—			62.4
		Merger termination and strategic alternatives costs			—			37.2
		(Gain) loss on divestitures			(5.2	)		464.1
		Equity in earnings of affiliates less than dividends received			69.7			18.5
		Derivative contracts classified as financing activities			79.8			785.3
		Changes in:
			Accounts receivable, excluding margin		21.1			599.2
			Derivative assets and liabilities, excluding collateral		227.3			185.2
			Net collateral and margin		(73.4	)		1,094.9
			Materials, supplies, and fuel stocks		(44.2	)		323.4
			Other current assets		49.8			237.0
			Accounts payable		(29.9	)		(786.1	)
			Accrued taxes and other current liabilities		(1,063.9	)		(156.0	)
		Other			(39.2	)		51.0

	Net cash (used in) provided by operating activities				(206.6	)		2,964.4

Cash Flows From Investing Activities
	Investments in property, plant and equipment				(425.0	)		(809.1	)
	Asset and business acquisitions, net of cash acquired				(372.9	)		—
	Investments in nuclear decommissioning trust fund securities				—			(233.4	)
	Proceeds from nuclear decommissioning trust fund securities				—			214.7
	Proceeds from sales of investments and other assets				21.2			80.9
	Proceeds from investment tax credits and grants related to renewable energy investments				21.5			—
	Contract and portfolio acquisitions				(29.0	)		(2,153.7	)
	(Increase) decrease in restricted funds				(30.0	)		1,004.4
	Other				(0.7	)		(1.8	)

	Net cash used in investing activities				(814.9	)		(1,898.0	)

Cash Flows From Financing Activities
	Net repayment of short-term borrowings				(17.0	)		(515.8	)
	Proceeds from issuance of common stock				8.8			13.6
	Proceeds from issuance of long-term debt				—			109.0
	Repayment of long-term debt				(629.0	)		(1,180.3	)
	Debt issuance costs				(0.7	)		(62.8	)
	Common stock dividends paid				(92.6	)		(133.7	)
	BGE preference stock dividends paid				(6.6	)		(6.6	)
	Proceeds from contract and portfolio acquisitions				2.3			2,243.1
	Derivative contracts classified as financing activities				(79.8	)		(785.3	)
	Other				(0.7	)		11.8

	Net cash used in financing activities				(815.3	)		(307.0	)

Net (Decrease) Increase in Cash and Cash Equivalents					(1,836.8	)		759.4
Cash and Cash Equivalents at Beginning of Period					3,440.0			202.2

Cash and Cash Equivalents at End of Period				$	1,603.2		$	961.6

See Notes to Consolidated Financial Statements.

Table of Contents

CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED)

Baltimore Gas and Electric Company and Subsidiaries

			Three Months Ended June 30,						Six Months Ended June 30,

			2010			2009			2010			2009

			(In millions)
Revenues
	Electric revenues		$	651.1		$	655.7		$	1,402.4		$	1,462.5
	Gas revenues			100.4			111.7			418.4			498.6

	Total revenues			751.5			767.4			1,820.8			1,961.1
Expenses
	Operating expenses
		Electricity purchased for resale		286.8			260.0			636.4			580.9
		Electricity purchased for resale from affiliate		114.6			142.5			238.6			346.8
		Gas purchased for resale		42.1			51.6			236.6			309.7
		Operations and maintenance		118.6			121.3			239.1			226.4
		Operations and maintenance from affiliate		27.9			27.6			56.4			49.5
	Depreciation and amortization			60.6			65.7			128.3			132.6
	Taxes other than income taxes			45.0			44.4			92.6			92.2

	Total expenses			695.6			713.1			1,628.0			1,738.1

Income from Operations				55.9			54.3			192.8			223.0
Other Income				5.5			7.2			12.0			14.7
Fixed Charges
	Interest expense			33.9			36.0			68.3			72.7
	Allowance for borrowed funds used during construction			(1.5	)		(1.1	)		(2.8	)		(2.1	)

	Total fixed charges			32.4			34.9			65.5			70.6

Income Before Income Taxes				29.0			26.6			139.3			167.1
Income Taxes				12.0			10.6			57.9			66.1

Net Income				17.0			16.0			81.4			101.0
Preference Stock Dividends				3.3			3.3			6.6			6.6

Net Income Attributable to Common Stock			$	13.7		$	12.7		$	74.8		$	94.4

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

Table of Contents

CONSOLIDATED BALANCE SHEETS

Baltimore Gas and Electric Company and Subsidiaries

				*June 30,* 2010*			December 31, 2009


				(In millions)
Assets
	Current Assets
		Cash and cash equivalents		$	260.2		$	13.6
		Accounts receivable (net of allowance for uncollectibles of $33.3 and $46.2, respectively)			319.3			311.7
		Accounts receivable, unbilled (net of allowance for uncollectibles of $1.0 and $1.0, respectively)			227.3			252.7
		Investment in cash pool, affiliated company			—			314.7
		Accounts receivable, affiliated companies			2.5			15.4
		Fuel stocks			51.1			73.8
		Materials and supplies			31.7			31.9
		Prepaid taxes other than income taxes			0.2			49.5
		Regulatory assets (net)			55.2			72.5
		Restricted cash—consolidated variable interest entity			23.5			24.3
		Deferred income taxes			—			11.2
		Other			10.1			11.3

		Total current assets			981.1			1,182.6

	Investments and Other Assets
		Regulatory assets (net)			386.7			414.4
		Receivable, affiliated company			322.5			326.2
		Other			58.1			98.2

		Total investments and other assets			767.3			838.8

	Utility Plant
		Plant in service
			Electric		4,882.2			4,772.4
			Gas		1,278.3			1,260.6
			Common		499.2			499.0

			Total plant in service		6,659.7			6,532.0
		Accumulated depreciation			(2,382.4	)		(2,318.2	)

		Net plant in service			4,277.3			4,213.8
		Construction work in progress			249.0			215.5
		Plant held for future use			6.6			2.4

		Net utility plant			4,532.9			4,431.7

	Total Assets			$	6,281.3		$	6,453.1

* Unaudited
See Notes to Consolidated Financial Statements.

Table of Contents

CONSOLIDATED BALANCE SHEETS

Baltimore Gas and Electric Company and Subsidiaries

			*June 30,* 2010*			December 31, 2009


			(In millions)
Liabilities and Equity
	Current Liabilities
		Short-term borrowings	$	—		$	46.0
		Current portion of long-term debt—consolidated variable interest entity		58.1			56.5
		Accounts payable		157.6			166.0
		Accounts payable, affiliated companies		73.8			98.3
		Customer deposits		78.5			76.0
		Deferred income taxes		29.4			—
		Accrued taxes		37.0			80.2
		Residential customer rate credit		—			112.4
		Accrued expenses and other		87.8			96.1

		Total current liabilities		522.2			731.5

	Deferred Credits and Other Liabilities
		Deferred income taxes		1,107.2			1,087.6
		Payable, affiliated company		243.3			243.4
		Deferred investment tax credits		9.0			9.5
		Liability for uncertain tax positions		67.7			73.3
		Other		16.5			20.0

		Total deferred credits and other liabilities		1,443.7			1,433.8

	Long-term Debt
		Rate stabilization bonds—consolidated variable interest entity		482.8			510.9
		Other long-term debt		1,431.5			1,431.5
		6.20% deferrable interest subordinated debentures due October 15, 2043 to wholly owned BGE Capital Trust II relating to trust preferred securities		257.7			257.7
		Unamortized discount and premium		(2.1	)		(2.2	)
		Current portion of long-term debt—consolidated variable interest entity		(58.1	)		(56.5	)

		Total long-term debt		2,111.8			2,141.4

	Equity
		Common shareholder's equity		2,013.6			1,938.8
		Preference stock not subject to mandatory redemption		190.0			190.0
		Noncontrolling interest		—			17.6

		Total equity		2,203.6			2,146.4

	Commitments, Guarantees, and Contingencies (see Notes)
	Total Liabilities and Equity		$	6,281.3		$	6,453.1

* Unaudited
See Notes to Consolidated Financial Statements.

Table of Contents

CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)

Baltimore Gas and Electric Company and Subsidiaries

Six Months Ended June 30,				2010			2009


				(In millions)
Cash Flows From Operating Activities
	Net income			$	81.4		$	101.0
	Adjustments to reconcile to net cash provided by operating activities
		Depreciation and amortization			128.3			132.6
		Other amortization			1.6			3.7
		Deferred income taxes			55.2			46.7
		Investment tax credit adjustments			(0.5	)		(0.5	)
		Deferred fuel costs			39.0			32.4
		Defined benefit plan expenses			17.4			17.5
		Allowance for equity funds used during construction			(5.2	)		(4.2	)
		Changes in:
			Accounts receivable		16.0			82.8
			Accounts receivable, affiliated companies		12.9			2.2
			Materials, supplies, and fuel stocks		22.9			87.8
			Other current assets		49.9			57.9
			Accounts payable		(7.8	)		(111.6	)
			Accounts payable, affiliated companies		(24.5	)		(38.3	)
			Other current liabilities		(119.8	)		10.6
			Long-term receivables and payables, affiliated companies		(13.9	)		(171.8	)
			Other		(71.7	)		(3.1	)

	Net cash provided by operating activities				181.2			245.7

Cash Flows From Investing Activities
	Utility construction expenditures (excluding equity portion of allowance for funds used during construction)				(190.3	)		(166.7	)
	Change in cash pool at parent				314.7			(5.2	)
	Proceeds from sales of investments and other assets				20.9			—
	Decrease in restricted funds				0.8			0.7

	Net cash provided by (used in) investing activities				146.1			(171.2	)

Cash Flows From Financing Activities
	Repayment of long-term debt				(28.1	)		(51.6	)
	Net repayment of short-term borrowings				(46.0	)		(30.1	)
	Debt issuance costs				—			(0.3	)
	Contribution from noncontrolling interest				—			8.0
	Preference stock dividends paid				(6.6	)		(6.6	)

	Net cash used in financing activities				(80.7	)		(80.6	)

Net Increase (Decrease) in Cash and Cash Equivalents					246.6			(6.1	)
Cash and Cash Equivalents at Beginning of Period					13.6			10.7

Cash and Cash Equivalents at End of Period				$	260.2		$	4.6

See Notes to Consolidated Financial Statements.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

Basis of Presentation

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

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

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

Reclassifications

In accordance with the presentation requirements for consolidated variable interest entities (VIEs), which we adopted on January 1, 2010, we have separately presented the following material assets and liabilities of these VIEs on our, and/or BGE's, Consolidated Balance Sheets:

•: "Accounts receivable—consolidated variable interest entities,"
•: "Restricted cash—consolidated variable interest entities,"
•: "Current portion of long-term debt—consolidated variable interest entities,"
•: "Accounts payable—consolidated variable interest entities," and
•: "Long-term Debt, Net of Current Portion—consolidated variable interest entities."

We discuss our adoption of the reporting requirements for consolidated variable interest entities below in the Variable Interest Entities section.

We have also reclassified certain prior-period amounts:

•: We have separately presented "Other comprehensive income—other equity method investees, net of taxes" that was previously reported within "Reclassification of net loss on hedging instruments from OCI to net income (loss), net of taxes" and "Net unrealized gain (loss) on hedging instruments, net of taxes" on our Consolidated Statements of Comprehensive Income (Loss).
•: 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.
•: We have separately presented "Accounts Payable" that was previously reported within "Accounts Payable and Accrued Liabilities" on our Consolidated Balance Sheets.

Variable Interest Entities

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

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

We consolidate three VIEs for which we are the primary beneficiary, and we have significant interests in six VIEs for which we do not have controlling financial interests and, accordingly, are not the primary beneficiary.

Consolidated Variable Interest Entities

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

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

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for rate stabilization charges to BondCo. During the quarter and six months ended June 30, 2010, BGE remitted $18.2 million and $42.0 million, respectively, to BondCo.

BGE did not provide any additional financial support to BondCo during the quarter and six months ended June 30, 2010. Further, BGE does not have any contractual commitments or obligations to provide additional financial support to BondCo unless additional rate stabilization bonds are issued. The BondCo creditors do not have any recourse to the general credit of BGE in the event the rate stabilization charges are not sufficient to cover the bond principal and interest payments of BondCo.

During 2009, our retail gas operation formed two new entities and combined them with our existing retail gas operation 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
•: As of June 30, 2010, we provided a $100 million parental guarantee and a $37 million letter of credit to the third party gas supplier in support of the retail gas entity group.

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

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

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

	(In millions)


Current assets	$	475.8
Noncurrent assets		74.1

Total Assets	$	549.9

Current liabilities	$	299.5
Noncurrent liabilities		434.1

Total Liabilities	$	733.6

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

Unconsolidated Variable Interest Entities

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

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	$30.5 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	$5.0 million debt guarantee and working capital funding	Prior to 2003

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

We concluded that power over the most economically significant activities of two of the power project VIEs is shared equally among the equity holders. Accordingly,

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neither of the equity holders consolidate these VIEs. The equity holders own 50% interests in these VIEs and all of the significant decisions require the mutual consent of the equity holders.

The following is summary information available as of June 30, 2010 about these entities:

		Power Contract Monetization VIEs		All Other VIEs		Total


		(In millions)
Total assets		$	498.5	$	315.6	$	814.1
Total liabilities			388.2		111.0		499.2
Our ownership interest			—		53.2		53.2
Other ownership interests			110.3		151.4		261.7
Our maximum exposure to loss			30.5		59.4		89.9
Carrying amount and location of variable interest on balance sheet:
	-Other investments		—		54.4		54.4

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

•: the carrying amount of our investment totaling $54.4 million, and
•: debt and payment guarantees totaling $35.5 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 VIEs.

Earnings Per Share

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

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

	Quarter Ended June 30,				Six Months Ended June 30,

	2010		2009		2010		2009

	(In millions)
Non-dilutive stock options		4.4		5.0		4.4		5.3
Dilutive common stock equivalent shares		1.8		0.8		1.6		0.5

As a result of the Company incurring a loss for the six months ended June 30, 2009, dilutive common stock equivalent shares were not included in calculating diluted EPS for that reporting period.

Acquisitions

Criterion Wind Project

In April 2010, we completed the acquisition of the Criterion wind project in Garrett County, Maryland. This 70 MW wind energy project will be developed, constructed, and owned by our Generation business and is expected to have a completed cost of approximately $140 million. We expect to place this facility in commercial operation during the first quarter of 2011.

Texas Combined Cycle Generation Facilities

In May 2010, we acquired the 550 MW Colorado Bend Energy Center and the 550 MW Quail Run Energy Center natural gas combined cycle generation facilities in Texas. We include these facilities as part of our Generation business and have included their results of operations in our consolidated financial statements since the date of acquisition.

We acquired 100% ownership of these facilities for $372.9 million, all of which was paid in cash at closing.

We recorded the major classes of assets acquired and liabilities assumed as follows:

At May 17, 2010

Current assets	$	8.6
Property, plant and equipment		367.4

Total assets acquired		376.0

Current liabilities		(3.1	)

Net assets acquired	$	372.9

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The preliminary net assets acquired are based on estimates and the purchase price is subject to adjustment, which could impact the amounts recognized for net assets acquired.

The pro-forma impact of this acquisition would not have been material to our results of operations for the quarter and six months ended June 30, 2010 and 2009.

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

In August 2010, we completed the sale of our 50% equity interest in the Mammoth Lakes geothermal generating facility in California. We received net cash proceeds of approximately $72 million. In the third quarter of 2010, our Generation business will record an approximately $38 million pre-tax gain on this transaction. We will have no further involvement in the activities of this generating facility.

On November 6, 2009, we completed the sale of a 49.99% membership interest in CENG, our nuclear generation and operation business, to EDF Group and affiliates (EDF). As a result of this transaction, we retained a 50.01% economic interest in CENG, but we and EDF have equal voting rights over the activities of CENG. Accordingly, we deconsolidated CENG and began to record our investment in CENG under the equity method of accounting. For the quarter and six months ended June 30, 2010, our equity investment losses were as follows:

1 For the quarter and six months ended June 30, 2010, total equity investment losses in CENG includes $0.5 million and $1.6 million, respectively, of expense related to the portion of cost of certain share-based awards that we fund on behalf of EDF.

The basis difference is the difference between the fair value of our investment in CENG at closing and our share of the underlying equity in CENG, because the underlying assets of CENG were retained at their carrying value. See Note 2 to our 2009 Annual Report on Form 10-K for a more detailed discussion.

Summarized income statement information for CENG for the quarter and six months ended June 30, 2010 is as follows:

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

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

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.

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

Our Generation business operating results for the quarter and six months ended June 30, 2010 include the following after-tax charges:

Our NewEnergy business operating results for the quarter and six months ended June 30, 2010 include the following after-tax charges:

Our Regulated Electric business operating results for the six months ended June 30, 2010 include an after-tax charge for the deferred income tax expense relating to federal subsidies for providing post-employment prescription drug benefits of $3.1 million as a result of healthcare reform legislation enacted in March 2010.

Our Holding Company and Other businesses operating results for the six months ended June 30, 2010 include an after-tax charge for the deferred income tax expense relating to federal subsidies for providing post-employment prescription drug benefits of $4.8 million as a result of healthcare reform legislation enacted in March 2010.

Total assets declined approximately $1.8 billion during 2010 due primarily to a decrease in cash and cash equivalents as a result of income taxes paid on the transaction with EDF and the retirement of debt.

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

1 BGE's portion of our net periodic pension benefit cost, excluding amounts capitalized, was $8.5 million for the quarter ended June 30, 2010 and $7.2 million for the quarter ended June 30, 2009. BGE's portion of our net periodic pension benefit cost, excluding amounts capitalized, was $14.8 million for the six months ended June 30, 2010 and $14.4 million for the six months ended June 30, 2009. Net periodic pension benefit costs exclude settlement charges of $1.5 million in the quarter and six months ended June 30, 2010 and $7.7 million in the quarter and six months ended June 30, 2009.

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

1 BGE's portion of our net periodic postretirement benefit cost, excluding amounts capitalized, was $4.6 million for the quarter ended June 30, 2010 and $5.2 million for the quarter ended June 30, 2009. BGE's portion of our net periodic postretirement benefit costs, excluding amounts capitalized, was $9.4 million for the six months ended June 30, 2010 and $9.8 million for the six months ended June 30, 2009.

Our non-qualified pension plans and our postretirement benefit programs are not funded; however, we have trust assets securing certain executive pension benefits. We estimate that we will incur approximately $9.8 million in pension benefit payments for our non-qualified pension plans and approximately $28.0 million for retiree health and life insurance costs in 2010. We contributed $12.2 million to our qualified pension plans in April 2010 and an additional $12.2 million in July 2010.

During March 2010, the Patient Protection and Affordable Care Act and the Healthcare and Education Reconciliation Act of 2010 were signed into law. These laws eliminate the tax exempt status of drug subsidies provided to companies under Medicare Part D after December 31, 2012. As a result of this new legislation, we recorded a noncash charge to reflect additional deferred income tax expense of $8.8 million in the six months ended June 30, 2010.

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.

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 June 30, 2010 for short-term financial needs as follows:

At June 30, 2010, we had approximately $1.3 billion in letters of credit issued including $0.3 billion in letters of credit issued under the commodity-linked credit facility discussed below and no commercial paper outstanding or direct borrowings under these facilities.

The commodity-linked credit facility 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.

At June 30, 2010, Constellation Energy had approximately $29 million of short-term notes outstanding with a weighted average effective interest rate of 6.4%.

BGE has a $600.0 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. At June 30, 2010, BGE had no commercial paper or direct borrowings outstanding. There were immaterial letters of credit outstanding at June 30, 2010.

As part of our voluntary commitment to reduce our debt by $1 billion with funds received from the EDF transaction, we retired the following debt during the six months ended June 30, 2010, completing this commitment.

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%. We recorded a loss on this transaction of $50.1 million within "Interest expense" on our Consolidated Statements of Income (Loss).

In March 2010, we repurchased our outstanding $47 million and $65 million variable rate tax-exempt notes. Since these notes are variable rate instruments, there was no gain or loss recorded upon repurchase.

The following table provides a summary of our, and BGE's, net available liquidity at June 30, 2010.

1 Excludes $0.5 billion commodity-linked credit facility due to its contingent nature and $0.3 billion in letters of credit issued against it.

We have an asset put arrangement with EDF 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 the quarter ended June 30, 2010, we received the final expected regulatory approval for one of the assets, which increased the net after-tax liquidity available through the put arrangement to approximately $1.4 billion.

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 June 30, 2010, the debt to capitalization ratio as defined in the credit agreements was 29%.

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 June 30, 2010, the debt to capitalization ratio for BGE as defined in this credit agreement was 43%.

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

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

We compute the income tax expense (benefit) for each quarter based on the estimated annual effective tax rate for the year. The effective tax rate was 30.9% and 32.6% for the quarter and six months ended June 30, 2010, respectively, compared to 78.3% and 60.4% for the same periods of 2009. The lower effective tax rate for the quarter ended June 30, 2010 reflects the impact of favorable adjustments (primarily related to reductions of uncertain tax positions and higher deductions for qualified production activities). The lower effective tax rate for the six months ended June 30, 2010 reflects the absence in 2010 of the impact of unfavorable nondeductible adjustments in 2009 (primarily related to nondeductible dividends on Series B preferred stock and the write-off of unamortized debt discount on senior notes) in relation to the lower estimated 2009 taxable income (primarily attributable to losses on the divestiture of a majority of our international commodities and our Houston-based gas trading operations).

The BGE effective tax rate was 41.4% and 41.6% for the quarter and six months ended June 30, 2010, respectively, compared to 39.8% and 39.6% for the same periods of 2009. The higher effective tax rate for 2010 is primarily due to the impact of the healthcare reform legislation enacted in the first quarter of 2010, which eliminates the tax exempt status of prescription drug subsidies received under Medicare Part D.

The following table summarizes the change in unrecognized tax benefits during 2010 and our total unrecognized tax benefits at June 30, 2010:

1 BGE's portion of our total unrecognized tax benefits at June 30, 2010 was $100.1 million.

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

Reductions in tax positions related to prior years are primarily due to the resolution of the tax treatment of distributions received from our shipping joint venture, merger termination fees, the timing of losses from international coal hedges, and offsetting tax depreciation associated with potential disallowance of repair deductions.

Total unrecognized tax benefits as of June 30, 2010 of $287.4 million include outstanding claims of approximately

$62.5 million, including $51.6 million in state tax credits, for which no tax benefit was recorded on our Consolidated Balance Sheet because refunds were not received and the claims do not meet the "more-likely-than-not" threshold.

If the total amount of unrecognized tax benefits of $287.4 million were ultimately realized, our income tax expense would decrease by approximately $170 million. However, the $170 million includes state tax refund claims of $51.6 million that have been disallowed by tax authorities and are subject to appeals.

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:

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

Accrued interest and penalties recognized in our Consolidated Balance Sheets were $15.8 million, of which BGE's portion was $2.3 million, at June 30, 2010, and $23.1 million, of which BGE's portion was $1.6 million, at December 31, 2009.

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, and BGE's, Consolidated Statements of Income (Loss). The taxes, surcharges, or fees that are included in revenues were as follows:

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

At June 30, 2010, Constellation Energy had a total of $9.7 billion in guarantees outstanding related to loans, credit facilities, and contractual performance of certain of its subsidiaries as described below.

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

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 NewEnergy business enters into long-term contracts for the capacity and transmission rights for the delivery of energy to meet our physical obligations to our customers. These contracts expire in various years between 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. These contracts expire between 2010 and 2012 and represent BGE's estimated requirements to serve residential and small commercial customers as follows:

The cost of power under these contracts is recoverable under the Provider of Last Resort agreement reached with the Maryland Public Service Commission (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 2010 and 2027. The cost of gas under these contracts is recoverable under BGE's gas cost adjustment clause discussed in Note 1 of our 2009 Annual Report on Form 10-K.

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

At June 30, 2010, the total amount of commitments was $6.3 billion. These commitments are primarily related to our Generation and NewEnergy businesses.

We enter into long-term power sales contracts in connection with our load-serving activities. We also enter into long-term power sales contracts associated with certain of our power plants. Our load-serving power sales contracts extend for terms through 2019 and provide for the sale of energy to electricity distribution utilities and certain retail customers. Our power sales contracts associated with power plants we own extend for terms into 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.

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

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 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. On April 16, 2010, the seventh merger case was dismissed without prejudice by the Court, thereby concluding these cases.

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.

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

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.

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 488 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:

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.

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 late 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 third quarter of 2011. In addition, the allocation of the costs among the potentially responsible parties is not yet known. The clean-up costs we incur could have a material effect on our financial results.

In May 2007, a subsidiary of Constellation Energy entered into a consent decree with the Maryland Department of the Environment to resolve alleged violations of air quality opacity standards at three fossil fuel plants in Maryland. The consent decree requires the subsidiary to pay a $100,000 penalty, provide $100,000 to a supplemental environmental project, and install technology to control emissions from those plants. Our obligations under this consent decree were completed in May 2010.

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.

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 $10.6 million, which includes the $1 million penalty and our estimate of probable costs to remediate contamination, replace drinking water supplies, monitor groundwater conditions, and otherwise comply with the consent decree. We have paid approximately $5.9 million of these costs as of June 30, 2010, resulting in a remaining liability at June 30, 2010 of $4.7 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.

We discuss our non-nuclear insurance programs in Note 12 of our 2009 Annual Report on Form 10-K.

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

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 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:

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:

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

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

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:

We discuss our accounting policies for derivatives and hedging activities and their impacts on our financial statements in Note 1 of our 2009 Annual Report on Form 10-K.

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.

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.

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 $744.6 million at June 30, 2010 and $951.3 million at December 31, 2009.

We expect to reclassify $576.7 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 June 30, 2010. However, the actual amount reclassified into earnings could vary from the amounts recorded at June 30, 2010, due to future changes in market prices.

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

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. 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 $7.3 million at June 30, 2010 and $11.3 million at December 31, 2009. We expect to reclassify $0.6 million of pre-tax net gains on these cash-flow hedges from "Accumulated other comprehensive loss" into "Interest expense" during the next twelve months. We had no hedge ineffectiveness on these swaps.

We elect fair value hedge accounting for a limited portion of our derivative contracts including certain interest rate swaps. The objectives for electing fair value hedging in these situations are to manage our exposure and to optimize the mix of our fixed and floating-rate debt.

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.

We have interest rate swaps qualifying as fair value hedges relating to $400 million of our fixed-rate debt maturing in 2012 and 2015, and converted this notional amount of debt to floating-rate. The fair value of these hedges was an unrealized gain of $44.0 million at June 30, 2010 and $35.8 million at December 31, 2009 and was recorded as an increase in our "Derivative assets" and an increase in our "Long-term debt." We had no hedge ineffectiveness on these interest rate swaps.

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

We did not have any fair value hedges for which we have excluded a portion of the change in fair value from our effectiveness assessment.

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:

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

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

The gross asset and liability values in the tables below are segregated between those derivatives designated in qualifying hedge accounting relationships and those not designated in hedge accounting relationships. Derivatives not designated in hedging relationships include our NewEnergy retail gas operations, economic hedges of accrual activities, the total return swaps entered into to effect the sale of the international commodities and Houston- based gas trading operations, 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.

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

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

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

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 of our 2009 Annual Report on Form 10-K.

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

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

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 the gains and losses on derivatives designated as fair value hedges and the gains and losses on the hedged item represents the recognition of locked-in gains on terminated interest rate swaps.

The following table presents gains and losses on mark-to-market derivatives. As discussed more fully in Note 1 to our 2009 Annual Report on Form 10-K, we record the unrealized gains and losses on mark-to-market derivatives in earnings as they occur. While we use mark-to-market accounting for risk management and trading activities because changes in fair value more closely reflect the economic performance of the activity, we also use mark-to-market accounting for certain derivatives related to 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.

1 Other commodity contracts for the quarter ended June 30, 2009 include oil, freight, weather, and emission allowances. For the quarter ended June 30, 2010 and for the six months ended June 30, 2010 and 2009, other commodity contracts also include 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.

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

through which we are able to manage and mitigate the risks that are inherent in our activities.

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

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

Additionally, the disclosure of derivative quantities potentially could reveal commercially valuable or otherwise competitively sensitive information that could limit the effectiveness and profitability of our business activities. Therefore, in the tables 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 tables below.

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

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

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

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 tables present information related to these derivatives at June 30, 2010 and December 31, 2009. Based on contractual provisions, we estimate that if Constellation Energy's senior unsecured debt were downgraded, our total contingent collateral obligation for derivatives in a net liability position was $0.2 billion at both June 30, 2010 and 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 at both June 30, 2010 and December 31, 2009 after reflecting legally binding master netting agreements and collateral already posted.

We present the gross fair value of derivatives in a net liability position that have credit-risk-related contingent features in the first column in the tables below. This gross fair value amount represents only the out-of-the-money contracts containing such features that are not fully collateralized by cash on a stand-alone basis. Thus, this amount does not reflect the offsetting fair value of in-the-money contracts under legally-binding master netting agreements with the same counterparty, as shown in the second column in the tables. These in-the-money contracts would offset the amount of any gross liability that could be required to be collateralized, and as a result, the actual potential collateral requirements would be based upon the net fair value of derivatives containing such features, not the gross amount. The amount of any possible 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 tables below is the most relevant measure of derivatives in a net liability position with credit-risk-related contingent features. This amount reflects the actual net liability upon which existing collateral postings are computed and upon which any additional contingent collateral obligation would be based.

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 $179.6 million and letters of credit of $601.0 million at June 30, 2010 and $125.6 million and letters of credit of $585.2 million at December 31, 2009.
5 Amounts represent the additional collateral that we could be required to post with counterparties, including both cash collateral and letters of credit, in the event of a credit downgrade to below investment grade after giving consideration to offsetting derivative and non-derivative positions under master netting agreements.

We discuss our concentrations of credit risk, including derivative-related positions, in Note 1 to our 2009 Annual Report on Form 10-K. As of June 30, 2010, we had two counterparties that exceeded 10% of our total credit exposure, including derivative-related positions. We had an approximately 17% exposure related to the power purchase agreement executed in 2009 with CENG, and we had an approximately 11% exposure related to an electric cooperative customer.

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):

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

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.

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

The table below sets forth by level within the fair value hierarchy the gross components of the Company's assets and liabilities that were measured at fair value on a recurring basis as of June 30, 2010. Our net derivative assets and liabilities are disaggregated on a gross contract-by-contract basis. 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. 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.

* 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 June 30, 2010, we included $78.6 million of cash collateral held and $179.6 million of cash collateral posted (excluding margin posted on exchange traded derivatives) in netting amounts in the above table.

The factors that cause changes in the gross components of the 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 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 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

Cash equivalents consist of exchange-traded money market funds, which are valued by multiplying unadjusted quoted prices in active markets by the quantity of the asset and are classified within Level 1.

Equity securities consist of mutual funds, which are valued by multiplying unadjusted quoted prices in active markets by the quantity of the asset and are classified within Level 1.

Derivative instruments include exchange-traded and bilateral contracts. Exchange-traded derivative contracts include futures and options. Bilateral derivative contracts include swaps, forwards, options and structured transactions. We have classified derivative contracts within the fair value hierarchy as follows:

During the quarter and six months ended June 30, 2010, there were no significant transfers of derivatives between Level 1 and Level 2 of the fair value hierarchy.

We utilize models based upon the income approach to measure the fair value of derivative contracts classified as Level 2 or Level 3. Generally, we use similar models to value similar instruments. In order to determine 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:

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

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

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

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

Realized and unrealized gains (losses) are included primarily in "Nonregulated revenues" for our derivative contracts that are marked-to-market in our Consolidated Statements of Income (Loss) and are included in "Accumulated other comprehensive loss" for our derivative contracts designated as cash-flow hedges in our Consolidated Balance Sheets. We discuss the income statement classification for realized gains and losses related to cash-flow hedges for our various hedging relationships in Note 1 to our 2009 Annual Report on Form 10-K.

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

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

In June 2009, the Financial Accounting Standards Board amended the accounting, presentation, and disclosure guidance related to variable interest entities. We adopted this guidance on January 1, 2010 and discuss our adoption in more detail beginning on page 10.

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 an initial fair value of $0.8 billion under which 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.

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. 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.

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 September 30, 2012.

The cost of BGE's purchased energy from nonregulated subsidiaries of Constellation Energy to meet its standard offer service obligation was as follows:

In addition, Constellation Energy charges BGE for the costs of certain corporate functions. These costs are comprised of direct charges as well as costs that are allocated 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.

The following table presents all of the costs Constellation Energy charged to BGE in each period, both directly-charged and allocated.

Other nonregulated affiliates of BGE also charge BGE for the costs of certain services provided.

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

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

BGE's Consolidated Balance Sheets include intercompany amounts related to BGE's purchases to meet its standard offer service obligation, BGE's 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.

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

Constellation Energy Group, Inc. (Constellation Energy) is an energy company that includes a generation business (Generation), a customer supply business (NewEnergy), and Baltimore Gas and Electric Company (BGE). We describe our operating segments in the Notes to Consolidated Financial Statements on page 14.

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

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

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

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

As you read this discussion and analysis, refer to our Consolidated Statements of Income (Loss) on page 2, which present the results of our operations for the quarters and six months ended June 30, 2010 and 2009. We analyze and explain the differences between periods in the specific line items of the Consolidated Statements of Income (Loss).

Various factors affect our financial results. We discuss these various factors in the Forward Looking Statements section on page 69 and in Item 1A. Risk Factors section of our 2009 Annual Report on Form 10-K. We discuss our market risks in the Risk Management section beginning on page 63.

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

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

In May 2010, BGE filed an application for a $46.9 million and a $42.4 million increase in our electric and gas base rates, respectively, with the Maryland Public Service Commission (Maryland PSC). While BGE demonstrated the need for a $110.8 million increase in electric base rates, distribution revenues awarded to BGE in the case are

subject to a 5% cap pursuant to the terms of the 2008 settlement agreement with the State of Maryland as well as the Maryland PSC's order approving the EDF transaction. In the application, we requested an 8.99% rate of return with an 11.65% return on equity. The Maryland PSC is currently reviewing our application and is expected to issue a ruling in December 2010. We cannot provide assurance that the Maryland PSC will approve the base rate increases requested, or if it does, that it will grant BGE the full amounts requested.

In June 2010, the Maryland PSC issued an order rejecting BGE's smart grid initiative proposal as originally filed. In July 2010, BGE filed an application for a rehearing of an amended smart grid proposal. We discuss the status of BGE's smart grid proposal in more detail in the Capital Requirements section on page 62.

The Dodd-Frank Wall Street Reform and Consumer Protection Act (Dodd-Frank Act) was enacted in July 2010. While the Dodd-Frank Act is focused primarily on the regulation and oversight of financial institutions, it also provides for a new regulatory regime for derivatives, including mandatory clearing of certain swaps, exchange trading, margin requirements, and other transparency requirements. The Dodd-Frank Act, however, also preserves the ability of end users in our industry to hedge their risks, which we believe results in the new derivatives requirements not being applicable to us for most of our activities. However, there will be several key rulemakings to implement the derivatives requirements, which, depending on the final scope of the regulations, could attempt to impose significant obligations on us nonetheless. Final regulations may address collateral requirements and exchange margin cash postings, which if applicable to us despite being an end user of derivatives, could have the effect of increasing our collateral requirements or the amount of exchange margin cash postings in lieu of letters of credit currently issued on over-the-counter contracts. These regulations could also result in additional transactional and compliance costs to the extent they apply to us, and could impact market liquidity.

In addition to new regulation over derivatives, the Dodd-Frank Act amends the Sarbanes-Oxley Act to permanently exempt nonaccelerated filers, including BGE, from the requirement to obtain an audit report on internal control over financial reporting.

In January 2010, the U.S. Environmental Protection Agency (EPA) proposed rules to adopt NAAQS for ozone that are stricter than the NAAQS adopted in March 2008, based on the EPA's reevaluation of scientific evidence about ozone and ozone's effects on humans and the environment. In June 2010, the EPA adopted a stricter NAAQS for sulfur dioxide (SO₂). We are unable to determine the impact that complying with the stricter NAAQS for ozone or sulfur dioxide will have on our financial results until the states in which our generating facilities are located adopt plans to meet the new standards. However, costs associated with compliance with these plans could be material.

In July 2010, the EPA proposed regulations to replace the regional cap-and-trade program under the Clean Air Interstate Rule (CAIR) with a program that would require each of 31 eastern states and the District of Columbia to reduce SO₂ and nitrogen oxide (NO_X) emissions. Depending on the scope of any final regulations that may be adopted by the EPA and any plans that may be adopted by the states in which our plants are located, additional regulation could result in additional compliance requirements and costs that could be material.

The State of Maryland has adopted opacity regulations consistent with its commitment to resolve long-standing industry concerns about the prior regulations' continuous compliance requirements and is in the process of obtaining the EPA's approval of Maryland's state implementation plan (SIP) for these regulations. While EPA approval of Maryland's SIP is being obtained, the opacity regulations are being implemented in a manner that will enable our plants to remain in compliance. We anticipate that the regulations under the EPA-approved SIP will be consistent with the regulations as currently implemented.

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

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

We discuss recently adopted accounting standards in the Accounting Standards Adopted section of the Notes to Consolidated Financial Statements on page 37.

In April 2010, we completed the acquisition of the Criterion wind project in Garrett County, Maryland.

In May 2010, we acquired the 550 MW Colorado Bend Energy Center and the 550 MW Quail Run Energy Center natural gas combined cycle generation facilities in Texas for $372.9 million.

We discuss these transactions in more detail beginning on page 12 in Notes to Consolidated Financial Statements.

In June 2010, the Hillabee Energy Center, a 740 MW gas-fired combined cycle power generation facility located in Alabama began commercial dispatch. We had acquired this facility in 2008.

In January 2010, BGE completed the sale of its interest in a nonregulated subsidiary that owns a district chilled water facility to a third party.

In August 2010, we completed the sale of our interests in the Mammoth Lakes geothermal generating facility.

We discuss these transactions in more detail on page 13 in Notes to Consolidated Financial Statements.

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

In March 2010, the Patient Protection and Affordable Care Act and the Healthcare and Education Reconciliation Act of 2010 (Reconciliation Act) were signed into law. We discuss the impact of these new laws on our earnings for the six months ended June 30, 2010 in more detail on page 16 in Notes to Consolidated Financial Statements.

Results of Operations for the Quarter and Six Months Ended June 30, 2010 Compared with the Same Periods of 2009

In this section, we discuss our earnings and the factors affecting them. We begin with a general overview, then separately discuss earnings for our operating segments. Significant changes in other (expense) income, fixed charges, and income taxes are discussed, as necessary, in the aggregate for all segments in the Consolidated Nonoperating Income and Expenses section on page 57.

Our total net income (loss) attributable to common stock for the quarter and six months ended June 30, 2010 was favorable compared to net income (loss) attributable to common stock for the same periods of 2009 by $64.5 million and $379.5 million, respectively, primarily due to the following:

1 Subsequent to June 30, 2010, we assigned an international freight contract incurring an approximately $42 million after-tax loss. This transaction will be recorded in the third quarter of 2010.

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

2 The net impact to the Company of the power purchase agreement with CENG was $47.7 million and $89.9 million pre-tax for the quarter and six months ended June 30, 2010. This amount represents the amortization of our "Unamortized energy contract asset" less our 50.01% equity in CENG's amortization of its "Unamortized energy contract liability."

3 These amounts include the net losses on the sales of the international commodities operation, 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 because the forecasted transactions are probable of not occurring, and earnings that are no longer part of our core business. The impairment losses and other costs and workforce reduction costs line items also include amounts related to the operations we divested.

In the following sections, we discuss our earnings by business segment in greater detail.

We define our Generation business in the Notes to Consolidated Financial Statements on page 14.

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

Above amounts include intercompany transactions eliminated in our Consolidated Financial Statements. The Information by Operating Segment section within the Notes to Consolidated Financial Statements on page 15 provides a reconciliation of operating results by segment to our Consolidated Financial Statements.

Effects of Transaction with EDF on Consolidated Statement of Income (Loss)

Prior to November 6, 2009, Constellation Energy Nuclear Group, LLC (CENG), our nuclear generation and operation business, was a 100% owned consolidated subsidiary. On November 6, 2009, we completed the sale of a 49.99% membership interest in CENG to EDF Group and affiliates (EDF), and we deconsolidated CENG. Specifically, we removed the assets and liabilities of CENG and recorded an investment in CENG at fair value on our Consolidated Balance Sheets, and recorded the proceeds received on our Consolidated Statements of Cash Flows. After November 6, 2009, we record equity investment earnings from CENG on our Consolidated Statements of Income (Loss). We discuss our transaction with EDF in more detail in Note 2 to our 2009 Annual Report on Form 10-K.

Our Generation revenues decreased $132.2 million and $337.8 million in the quarter and six months ended June 30, 2010 compared to the same periods of 2009, primarily due to the following:

Our Generation fuel and purchased energy expenses increased $177.3 million and $282.0 million in the quarter and six months ended June 30, 2010 compared to the same periods of 2009, primarily due to the following:

Our Generation business operating expenses decreased $169.7 million for the quarter ended June 30, 2010 as compared to the same period for 2009 due to lower labor and benefit costs of $126.1 million and lower non-labor operating expenses of $43.6 million, the majority of which results from the absence of costs in 2010 due to the deconsolidation of CENG in 2009.

Our Generation business operating expenses decreased $356.7 million for the six months ended June 30, 2010 as compared to the same period for 2009 due to lower labor and benefit costs of $272.3 million and lower non-labor operating expenses of $84.4 million, the majority of which results from the absence of costs in 2010 due to the deconsolidation of CENG in 2009.

	Quarter Ended June 30, 2010			Six Months Ended June 30, 2010


	(In millions)
CENG	$	40.2		$	63.6
Amortization of basis difference in CENG		(61.5	)		(104.2	)

Total equity investment losses—CENG¹	$	(21.3	)	$	(40.6	)

	Quarter Ended June 30, 2010		Six Months Ended June 30, 2010


	(In millions)
Revenues	$	376.1	$	737.0
Fuel and purchased energy expenses		53.4		111.8
Income from operations		73.2		110.8
Net income		81.3		130.4

	Quarter Ended June 30,						Six Months Ended June 30,

	2010			2009			2010			2009

	(In millions)
Components of net periodic pension benefit cost
Service cost	$	9.1		$	14.4		$	18.6		$	29.6
Interest cost		19.7			31.1			41.4			58.3
Expected return on plan assets		(23.2	)		(38.9	)		(49.9	)		(68.5	)
Recognized net actuarial loss		8.7			11.1			16.8			21.7
Amortization of prior service cost		0.9			2.5			1.9			5.8
Amount capitalized as construction cost		(2.9	)		(2.8	)		(4.8	)		(5.4	)

Net periodic pension benefit cost¹	$	12.3		$	17.4		$	24.0		$	41.5

	Quarter Ended June 30,						Six Months Ended June 30,

	2010			2009			2010			2009

	(In millions)
Components of net periodic postretirement benefit cost
Service cost	$	0.6		$	2.0		$	1.3		$	3.6
Interest cost		5.0			6.3			9.7			12.1
Amortization of transition obligation		0.6			0.6			1.1			1.1
Recognized net actuarial (gain) loss		(0.1	)		0.4			0.2			1.1
Amortization of prior service cost		(0.7	)		(1.0	)		(1.4	)		(1.8	)
Amount capitalized as construction cost		(1.6	)		(1.8	)		(2.9	)		(3.3	)

Net periodic postretirement benefit cost¹	$	3.8		$	6.5		$	8.0		$	12.8

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


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

	Total	$	4.02

	Reportable Segments

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

	(In millions)
Quarter ended June 30,
2010
Unaffiliated revenues	$	283.0	$	2,276.1		$	651.1	$	99.6		$	0.1		$	—		$	3,309.9
Intersegment revenues		267.3		114.7			—		0.8			—			(382.8	)		—

Total revenues		550.3		2,390.8			651.1		100.4			0.1			(382.8	)		3,309.9
Net income (loss)		15.3		50.8			20.9		(3.9	)		0.7			—			83.8
Net income (loss) attributable to common stock		15.3		42.9			18.4		(4.7	)		0.7			—			72.6
2009
Unaffiliated revenues	$	168.3	$	2,926.0		$	655.7	$	111.1		$	3.0		$	—		$	3,864.1
Intersegment revenues		514.2		52.1			—		0.6			—			(566.9	)		—

Total revenues		682.5		2,978.1			655.7		111.7			3.0			(566.9	)		3,864.1
Net income (loss)		62.1		(46.1	)		22.1		(6.2	)		(3.6	)		—			28.3
Net income (loss) attributable to common stock		62.1		(62.9	)		19.5		(6.9	)		(3.7	)		—			8.1
Six months ended June 30,
2010
Unaffiliated revenues	$	574.2	$	4,503.1		$	1,402.4	$	416.7		$	0.1		$	—		$	6,896.5
Intersegment revenues		556.0		238.6			—		1.7			—			(796.3	)		—

Total revenues		1,130.2		4,741.7			1,402.4		418.4			0.1			(796.3	)		6,896.5
Net income (loss)		42.4		154.9			48.1		33.3			(3.6	)		—			275.1
Net income (loss) attributable to common stock		42.4		150.5			43.0		31.8			(3.6	)		—			264.1
2009
Unaffiliated revenues	$	350.1	$	5,854.0		$	1,462.5	$	495.4		$	5.5		$	—		$	8,167.5
Intersegment revenues		1,117.9		138.9			—		3.2			—			(1,260.0	)		—

Total revenues		1,468.0		5,992.9			1,462.5		498.6			5.5			(1,260.0	)		8,167.5
Net income (loss)		103.6		(292.4	)		67.5		33.4			(3.5	)		—			(91.4	)
Net income (loss) attributable to common stock		103.6		(309.7	)		62.4		31.9			(3.6	)		—			(115.4	)

At June 30, 2010	Constellation Energy			BGE


	(In billions)
Credit facilities¹	$	3.5		$	0.6
Less: Letters of credit issued¹		(1.0	)		—
Less: Cash drawn on credit facilities		—			—

Undrawn facilities		2.5			0.6
Less: Commercial paper outstanding		—			—

Net available facilities		2.5			0.6
Add: Cash and cash equivalents		1.3			0.3

Cash and facility liquidity		3.8			0.9
Add: EDF put arrangement		1.4			—

Net available liquidity	$	5.2		$	0.9

At June 30, 2010


	(In millions)
Total unrecognized tax benefits, January 1, 2010	$	312.5
Increases in tax positions related to the current year		6.7
Increases in tax positions related to prior years		11.1
Reductions in tax positions related to prior years		(42.3	)
Reductions in tax positions as a result of a lapse of the applicable statute of limitations		(0.6	)

Total unrecognized tax benefits, June 30, 2010¹	$	287.4

At June 30, 2010	Stated Limit


	(In billions)
Constellation Energy guarantees	$	9.4
BGE guarantees		0.3

Total guarantees	$	9.7

Contract Duration


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

As of June 30, 2010		Derivatives Designated as Hedging Instruments for Accounting Purposes					Derivatives Not Designated As Hedging Instruments for Accounting Purposes					All Derivatives Combined


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

		(In millions)
	Power contracts	$	1,627.5	$	(2,013.0	)	$	11,159.2	$	(11,800.9	)	$	12,786.7		$	(13,813.9	)
	Gas contracts		2,095.6		(1,853.1	)		4,360.1		(4,110.8	)		6,455.7			(5,963.9	)
	Coal contracts		35.8		(33.5	)		348.6		(343.9	)		384.4			(377.4	)
	Other commodity contracts¹		—		—			125.0		(79.7	)		125.0			(79.7	)
	Interest rate contracts		44.0		—			37.4		(44.8	)		81.4			(44.8	)
	Foreign exchange contracts		—		—			6.5		(4.5	)		6.5			(4.5	)

Total gross fair values		$	3,802.9	$	(3,899.6	)	$	16,036.8	$	(16,384.6	)	$	19,839.7		$	(20,284.2	)

	Netting arrangements⁵												(18,850.0	)		18,850.0
	Cash collateral												(78.6	)		179.6

Net fair values												$	911.1		$	(1,254.6	)

Net fair value by balance sheet line item:
Accounts receivable²												$	(197.3	)
Derivative assets—current													558.2
Derivative assets—noncurrent													550.2
Derivative liabilities—current																(621.6	)
Derivative liabilities—noncurrent																(633.0	)

Total Derivatives												$	911.1		$	(1,254.6	)

Cash Flow Hedges												Quarter Ended June 30,


		Gain (Loss) Recorded in AOCI							Gain (Loss) Reclassified from AOCI into Earnings						Ineffectiveness Gain (Loss) Recorded in Earnings
Contract type:		2010			2009			Statement of Income (Loss) Line Item	2010			2009			2010			2009

		(In millions)
Hedges of forecasted sales:								Nonregulated revenues
	Power contracts	$	(80.8	)	$	100.4			$	(1.0	)	$	(37.5	)	$	(20.5	)	$	21.2
	Gas contracts		1.8			7.9				16.2			(0.6	)		(2.9	)		4.5
	Coal contracts		—			—				—			—			—			—
	Other commodity contracts¹		—			(7.1	)			—			(0.8	)		—			(2.2	)
Interest rate contracts			—			—				—			(0.2	)		—			—
Foreign exchange contracts			—			—				—			—			—			—

Total gains (losses)		$	(79.0	)	$	101.2		Total included in nonregulated revenues	$	15.2		$	(39.1	)	$	(23.4	)	$	23.5

Hedges of forecasted purchases:								Fuel and purchased energy expense
	Power contracts	$	163.9		$	(112.8	)		$	(331.6	)	$	(611.9	)	$	(3.4	)	$	(0.3	)
	Gas contracts		(2.6	)		(21.2	)			45.1			66.7			(13.1	)		1.9
	Coal contracts		32.6			(40.5	)			(15.3	)		(52.0	)		2.3			(1.6	)
	Other commodity contracts²		—			(3.7	)			—			(2.7	)		—			—
Foreign exchange contracts			—			—				—			—			—			—

Total losses		$	193.9		$	(178.2	)	Total included in fuel and purchased energy expense	$	(301.8	)	$	(599.9	)	$	(14.2	)	$	—

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

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

Grand total (losses) gains		$	114.9		$	(77.0	)		$	(286.4	)	$	(639.1	)	$	(37.6	)	$	23.5

Fair Value Hedges			Quarter Ended June 30,										Six Months Ended June 30,


			Amount of Gain (Loss) Recognized in Income on Derivative					Amount of Gain (Loss) Recognized in Income on Hedged Item					Amount of Gain (Loss) Recognized in Income on Derivative					Amount of Gain (Loss) Recognized in Income on Hedged Item

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

			(In millions)
Commodity contracts:
	Gas contracts	Nonregulated revenues	$	—	$	—		$	—		$	—	$	—	$	40.6		$	—		$	(16.7	)
Interest rate contracts		Interest expense		4.2		(20.4	)		(4.1	)		20.4		17.4		(15.5	)		(15.2	)		15.5

Total gains (losses)			$	4.2	$	(20.4	)	$	(4.1	)	$	20.4	$	17.4	$	25.1		$	(15.2	)	$	(1.2	)

Mark-to-Market Derivatives			Quarter Ended June 30,						Six Months Ended June 30,


			Amount of Gain (Loss) Recorded in Income on Derivative						Amount of Gain (Loss) Recorded in Income on Derivative

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

			(In millions)
Commodity contracts:
	Power contracts	Nonregulated revenues	$	40.1		$	58.4		$	(24.8	)	$	147.0
	Gas contracts	Nonregulated revenues		5.0			(116.9	)		30.7			(279.5	)
	Coal contracts	Nonregulated revenues		7.6			52.1			7.7			9.8
	Other commodity contracts¹	Nonregulated revenues		(3.8	)		4.3			1.1			0.4
	Coal contracts	Fuel and purchased energy expense		—			(2.2	)		—			(107.7	)
Interest rate contracts		Nonregulated revenues		(0.6	)		(20.1	)		(1.7	)		(20.6	)
Foreign exchange contracts		Nonregulated revenues		(1.2	)		1.9			(2.1	)		9.7

Total gains (losses)			$	47.1		$	(22.5	)	$	10.9		$	(240.9	)

Quantities¹ Under Derivative Contracts											As of June 30, 2010


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

	(In millions)
Power (MWh)		24.9		19.7		8.2		2.4		4.0		1.7		60.9
Gas (MMBTU)		39.3		50.3		13.4		39.8		45.3		19.3		207.4
Coal (Tons)		2.3		4.7		1.3		0.1		—		—		8.4
Oil (BBL)		0.3		—		0.1		—		—		—		0.4
Emission Allowances (Tons)		11.2		—		—		—		—		—		11.2
Interest Rate Contracts	$	264.2	$	204.4	$	318.7	$	241.8	$	60.0	$	250.0	$	1,339.1
Foreign Exchange Rate Contracts	$	31.5	$	64.5	$	7.7	$	16.7	$	16.8	$	15.5	$	152.7

Credit-Risk Related Contingent Feature							As of June 30, 2010


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

(In billions)
$	7.7	$	(6.7	)	$	1.0	$	0.8	$	0.2

			As of June 30, 2010

			Assets			Liabilities

			(In millions)
Cash equivalents			$	1,076.7		$	—
Equity securities				38.5			—
Derivative instruments:
	Classified as derivative assets and liabilities:
		Current		558.2			(621.6	)
		Noncurrent		550.2			(633.0	)

		Total classified as derivative assets and liabilities		1,108.4			(1,254.6	)
	Classified as accounts receivable*			(197.3	)		—

	Total derivative instruments			911.1			(1,254.6	)

Total recurring fair value measurements			$	2,026.3		$	(1,254.6	)

At June 30, 2010		Carrying Amount		Fair Value


		(In millions)
Investments and other assets—Constellation Energy		$	184.4	$	184.6
Fixed-rate long-term debt:
	Constellation Energy (including BGE)		3,707.8		4,084.8
	BGE		2,172.0		2,366.9
Variable-rate long-term debt:
	Constellation Energy (including BGE)		544.1		544.1
	BGE		—		—

Agreement	Amount Recognized in Earnings for the Quarter Ended June 30, 2010			Amount Recognized in Earnings for the Six Months Ended June 30, 2010			Income Statement Classification	Accounts Receivable/ (Accounts Payable) at June 30, 2010


(In millions)
PPA	$	222.1		$	420.6		Fuel and purchased energy expenses	$	(49.6	)
PSA		(4.0	)		(8.0	)	Nonregulated revenues		—
ASA		(16.5	)		(33.0	)	Operating expenses		5.5

	Quarter Ended June 30,			Six Months Ended June 30,

	2010 vs. 2009

	(In millions, after-tax)
Generation gross margin	$	(140	)	$	(272	)
NewEnergy gross margin		(16	)		97
Generation operating expenses, primarily labor and benefit costs due to the deconsolidation of CENG		95			195
Gain on NewEnergy international coal contract assignments¹		10			48
Generation accretion of asset retirement obligations due to deconsolidation of CENG		11			21
NewEnergy hedge ineffectiveness		(41	)		(47	)
Regulated businesses		1			(16	)
Other nonregulated businesses		1			2
Total change in Other Items included in Operations per table below		137			312
All other changes		7			40

Total Change	$	65		$	380

	Quarter Ended June 30,			Six Months Ended June 30,

	2010 vs. 2009

	(In millions)
Decrease in volume of output from nuclear generating assets due to the deconsolidation of CENG	$	(104	)	$	(263	)
Decrease due to higher outages at our fossil plants		(16	)		(77	)
All other		(12	)		2

Total decrease in Generation revenues	$	(132	)	$	(338	)

	Quarter Ended June 30,			Six Months Ended June 30,

	2010 vs. 2009

	(In millions)
Increase in purchased energy costs due to power purchase agreement with CENG compared with nuclear fuel costs in 2009	$	177		$	337
Increase in fuel costs due to higher coal prices		24			24
Decrease due to higher outages at our fossil plants		(16	)		(56	)
All other		(8	)		(23	)

Total increase in Generation fuel and purchased energy expenses	$	177		$	282