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, 2011


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 ý 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 201,321,543 shares outstanding
of Constellation Energy Group, Inc. on July 29, 2011.

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			1
	Item 1—Financial Statements		1
		Constellation Energy Group, Inc. and Subsidiaries
		Consolidated Statements of Income	1
		Consolidated Statements of Comprehensive Income	1
		Consolidated Balance Sheets	2
		Consolidated Statements of Cash Flows	4
		Baltimore Gas and Electric Company and Subsidiaries
		Consolidated Statements of Income	5
		Consolidated Balance Sheets	6
		Consolidated Statements of Cash Flows	8
		Notes to Consolidated Financial Statements	9
	Item 2—Management's Discussion and Analysis of Financial Condition and Results of Operations		37
		Introduction and Overview	37
		Business Environment	37
		Events of 2011	38
		Results of Operations	40
		Financial Condition	52
		Capital Resources	54
	Item 3—Quantitative and Qualitative Disclosures About Market Risk		59
	Item 4—Controls and Procedures		59
Part II—Other Information			60
	Item 1—Legal Proceedings		60
	Item 1A—Risk Factors		60
	Item 2—Issuer Purchases of Equity Securities		63
	Item 5—Other Information		64
	Item 6—Exhibits		65
	Signature		66

Table of Contents

PART I—FINANCIAL INFORMATION

Item 1—Financial Statements

CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED)

Constellation Energy Group, Inc. and Subsidiaries

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

		2011			2010			2011			2010

		(In millions, except per share amounts)
Revenues
	Nonregulated revenues	$	2,704.7		$	2,559.2		$	5,318.6		$	5,077.4
	Regulated electric revenues		546.9			651.1			1,197.0			1,402.4
	Regulated gas revenues		108.2			99.6			414.4			416.7

	Total revenues		3,359.8			3,309.9			6,930.0			6,896.5
Expenses
	Fuel and purchased energy expenses		2,171.6			2,267.7			4,649.8			4,629.8
	Fuel and purchased energy expenses from affiliate		209.3			222.1			404.1			420.6
	Operating expenses		467.9			413.7			906.1			810.1
	Merger costs		31.8			—			31.8			—
	Depreciation, depletion, accretion, and amortization		151.8			125.7			305.9			257.6
	Taxes other than income taxes		76.5			65.6			154.2			132.4

	Total expenses		3,108.9			3,094.8			6,451.9			6,250.5
Equity Investment Losses			(26.3	)		(33.5	)		(35.9	)		(54.2	)
Gain on U.S. Department of Energy Settlement			35.5			—			35.5			—
Net Gain on Divestitures			—			0.3			—			5.2

Income from Operations			260.1			181.9			477.7			597.0
Other Expense			(15.7	)		(8.9	)		(34.7	)		(31.2	)
Fixed Charges
	Interest expense		65.2			60.4			136.5			181.9
	Interest capitalized and allowance for borrowed funds used during construction		(2.2	)		(8.7	)		(4.4	)		(24.3	)

	Total fixed charges		63.0			51.7			132.1			157.6

Income from Continuing Operations Before Income Taxes			181.4			121.3			310.9			408.2
Income Tax Expense			73.3			37.5			123.4			133.1

Net Income			108.1			83.8			187.5			275.1
Less: Net Income Attributable to Noncontrolling Interests and BGE Preference Stock Dividends			8.9			11.2			17.9			11.0

Net Income Attributable to Common Stock		$	99.2		$	72.6		$	169.6		$	264.1

Average Shares of Common Stock Outstanding—Basic			200.1			200.8			199.7			200.6
Average Shares of Common Stock Outstanding—Diluted			201.9			202.6			201.3			202.2

Earnings Per Common Share—Basic		$	0.50		$	0.36		$	0.85		$	1.32

Earnings Per Common Share—Diluted		$	0.49		$	0.36		$	0.84		$	1.31

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,

				2011			2010			2011			2010

				(In millions)
Net Income				$	108.1		$	83.8		$	187.5		$	275.1
	Other comprehensive income (OCI)
		Hedging instruments:
			Reclassification of net loss on hedging instruments from OCI to net income, net of taxes		29.5			179.4			87.6			287.9
			Net unrealized (loss) gain on hedging instruments, net of taxes		(47.4	)		70.9			(42.0	)		(162.0	)
		Available-for-sale securities:
			Reclassification of net gain on sales of securities from OCI to net income, net of taxes		—			—			—			(0.1	)
			Net unrealized gain on securities, net of taxes		0.1			—			0.1			0.2
		Defined benefit obligations:
			Amortization of net actuarial loss, prior service cost, and transition obligation included in net periodic benefit cost, net of taxes		7.8			4.9			15.7			10.8
		Net unrealized gain (loss) on foreign currency, net of taxes			0.3			(10.7	)		1.8			(9.0	)
		Other comprehensive gain (loss)—equity investment in CENG, net of taxes			1.4			(22.1	)		14.2			(12.2	)
		Other comprehensive loss—other equity method investees, net of taxes			—			(0.3	)		—			(0.5	)

	Comprehensive income				99.8			305.9			264.9			390.2
		Less: Comprehensive income attributable to noncontrolling interests, net of taxes			8.9			11.2			17.9			11.0

Comprehensive Income Attributable to Common Stock				$	90.9		$	294.7		$	247.0		$	379.2

See Notes to Consolidated Financial Statements.

Table of Contents

CONSOLIDATED BALANCE SHEETS

Constellation Energy Group, Inc. and Subsidiaries

			*June 30,* 2011*			December 31, 2010


			(In millions)
Assets
	Current Assets
		Cash and cash equivalents	$	954.8		$	2,028.5
		Accounts receivable (net of allowance for uncollectibles of $84.9 and $85.0, respectively)		1,965.8			2,059.2
		Accounts receivable—consolidated variable interest entities (net of allowance for uncollectibles of $95.7 and $87.9, respectively)		260.7			308.9
		Income taxes receivable		81.3			152.7
		Fuel stocks		394.1			361.1
		Materials and supplies		136.3			104.3
		Derivative assets		324.3			534.4
		Unamortized energy contract assets (includes $210.4 and $400.9, respectively, related to CENG)		335.3			544.7
		Restricted cash		2.1			52.0
		Restricted cash—consolidated variable interest entities		46.0			52.3
		Other		241.4			254.5

		Total current assets		4,742.1			6,452.6

Investments and Other Noncurrent Assets
		Investment in CENG		2,974.9			2,991.1
		Other investments		197.7			189.9
		Regulatory assets (net)		370.8			374.1
		Goodwill		180.8			77.0
		Derivative assets		257.5			258.9
		Unamortized energy contract assets		67.9			109.8
		Other		302.5			286.3

		Total investments and other noncurrent assets		4,352.1			4,287.1

Property, Plant and Equipment
		Property, plant and equipment		15,052.5			13,588.9
		Accumulated depreciation		(4,433.3	)		(4,310.1	)

		Net property, plant and equipment		10,619.2			9,278.8

	Total Assets		$	19,713.4		$	20,018.5

* Unaudited
See Notes to Consolidated Financial Statements.

Table of Contents

CONSOLIDATED BALANCE SHEETS

Constellation Energy Group, Inc. and Subsidiaries

				*June 30,* 2011*			December 31, 2010


				(In millions)
Liabilities and Equity
	Current Liabilities
		Short-term borrowings		$	20.6		$	32.4
		Current portion of long-term debt			131.5			245.6
		Current portion of long-term debt—consolidated variable interest entities			61.3			59.7
		Accounts payable			987.0			1,072.6
		Accounts payable—consolidated variable interest entities			151.7			189.8
		Derivative liabilities			494.2			622.3
		Unamortized energy contract liabilities			130.9			130.5
		Deferred income taxes			20.2			56.5
		Accrued taxes			85.1			71.0
		Accrued expenses			261.5			358.1
		Other			551.6			438.7

		Total current liabilities			2,895.6			3,277.2

	Deferred Credits and Other Noncurrent Liabilities
		Deferred income taxes			2,667.6			2,489.8
		Asset retirement obligations			33.4			32.3
		Derivative liabilities			270.1			353.0
		Unamortized energy contract liabilities			362.0			411.1
		Defined benefit obligations			588.0			574.7
		Deferred investment tax credits			25.4			27.6
		Other			248.5			296.0

		Total deferred credits and other noncurrent liabilities			4,195.0			4,184.5

	Long-term Debt, Net of Current Portion				3,947.5			4,054.2
	Long-term Debt, Net of Current Portion—consolidated variable interest entities				370.8			394.6
	Equity
		Common shareholders' equity:
			Common stock		3,265.5			3,231.7
			Retained earnings		5,344.9			5,270.8
			Accumulated other comprehensive loss		(595.9	)		(673.3	)

		Total common shareholders' equity			8,014.5			7,829.2
		BGE preference stock not subject to mandatory redemption			190.0			190.0
		Noncontrolling interests			100.0			88.8

		Total equity			8,304.5			8,108.0

	Commitments, Guarantees, and Contingencies (see Notes)
	Total Liabilities and Equity			$	19,713.4		$	20,018.5

* Unaudited
See Notes to Consolidated Financial Statements.

Table of Contents

CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)

Constellation Energy Group, Inc. and Subsidiaries

Six Months Ended June 30,				2011			2010


				(In millions)
Cash Flows From Operating Activities
	Net income			$	187.5		$	275.1
	Adjustments to reconcile to net cash provided by (used in) operating activities
		Depreciation, depletion, accretion, and amortization			305.9			257.6
		Amortization of energy contracts and derivatives designated as hedges			214.5			70.6
		All other amortization			17.9			14.6
		Deferred income taxes			68.0			(47.9	)
		Investment tax credit adjustments			(2.2	)		(2.2	)
		Deferred fuel costs			17.2			39.0
		Deferred storm costs			(15.5	)		—
		Defined benefit obligation expense			38.2			33.7
		Defined benefit obligation payments			(19.2	)		(39.0	)
		Gain on divestitures			—			(5.2	)
		Gain on U. S. Department of Energy settlement			(35.5	)		—
		Equity in earnings of affiliates less than dividends received			40.2			69.7
		Derivative contracts classified as financing activities			6.7			79.8
		Changes in:
			Accounts receivable, excluding margin		(20.5	)		21.1
			Derivative assets and liabilities, excluding collateral		323.9			227.3
			Net collateral and margin		(46.7	)		(73.4	)
			Materials, supplies, and fuel stocks		(11.5	)		(44.2	)
			Other current assets		127.9			49.8
			Accounts payable		(158.4	)		(29.9	)
			Liability for unrecognized tax benefits		3.7			(26.0	)
			Accrued taxes and other current liabilities		(6.2	)		(1,084.9	)
		Other			(59.4	)		7.8

	Net cash provided by (used in) operating activities				976.5			(206.6	)

Cash Flows From Investing Activities
	Investments in property, plant and equipment				(566.3	)		(425.0	)
	Asset and business acquisitions, net of cash acquired				(1,229.6	)		(372.9	)
	Proceeds from U.S. Department of Energy grant				28.3			—
	Proceeds from sales of investments and other assets				—			21.2
	Proceeds from investment tax credits and grants related to renewable energy investments				37.3			21.5
	Payment for issuance of loans receivable				(15.0	)		—
	Contract and portfolio acquisitions				(3.7	)		(29.0	)
	Decrease (increase) in restricted funds				57.9			(30.0	)
	Other				(9.0	)		(0.7	)

	Net cash used in investing activities				(1,700.1	)		(814.9	)

Cash Flows From Financing Activities
	Net repayment of short-term borrowings				(11.8	)		(17.0	)
	Proceeds from issuance of common stock				11.3			8.8
	Proceeds from issuance of long-term debt				7.5			—
	Repayment of long-term debt				(251.2	)		(629.0	)
	Debt and credit facility costs				(3.2	)		(0.7	)
	Common stock dividends paid				(91.9	)		(92.6	)
	BGE preference stock dividends paid				(6.6	)		(6.6	)
	Proceeds from contract and portfolio acquisitions				1.0			2.3
	Derivative contracts classified as financing activities				(6.7	)		(79.8	)
	Other				1.5			(0.7	)

	Net cash used in financing activities				(350.1	)		(815.3	)

Net Decrease in Cash and Cash Equivalents					(1,073.7	)		(1,836.8	)
Cash and Cash Equivalents at Beginning of Period					2,028.5			3,440.0

Cash and Cash Equivalents at End of Period				$	954.8		$	1,603.2

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

Table of Contents

CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED)

Baltimore Gas and Electric Company and Subsidiaries

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

			2011			2010			2011			2010

			(In millions)
Revenues
	Electric revenues		$	547.1		$	651.1		$	1,197.3		$	1,402.4
	Gas revenues			109.1			100.4			416.4			418.4

	Total revenues			656.2			751.5			1,613.7			1,820.8
Expenses
	Operating expenses
		Electricity purchased for resale		199.5			286.8			496.7			636.4
		Electricity purchased for resale from affiliate		73.2			114.6			129.9			238.6
		Gas purchased for resale		49.8			42.1			220.9			236.6
		Operations and maintenance		130.1			118.6			250.7			239.1
		Operations and maintenance from affiliate		28.5			27.9			60.9			56.4
	Merger costs			9.2			—			9.2			—
	Depreciation and amortization			66.8			60.6			143.1			128.3
	Taxes other than income taxes			46.4			45.0			96.2			92.6

	Total expenses			603.5			695.6			1,407.6			1,628.0

Income from Operations				52.7			55.9			206.1			192.8
Other Income				6.1			5.5			12.2			12.0
Fixed Charges
	Interest expense			33.1			33.9			66.6			68.3
	Allowance for borrowed funds used during construction			(1.6	)		(1.5	)		(3.3	)		(2.8	)

	Total fixed charges			31.5			32.4			63.3			65.5

Income Before Income Taxes				27.3			29.0			155.0			139.3
Income Taxes				10.7			12.0			57.3			57.9

Net Income				16.6			17.0			97.7			81.4
Preference Stock Dividends				3.3			3.3			6.6			6.6

Net Income Attributable to Common Stock			$	13.3		$	13.7		$	91.1		$	74.8

See Notes to Consolidated Financial Statements.

Table of Contents

CONSOLIDATED BALANCE SHEETS

Baltimore Gas and Electric Company and Subsidiaries

				*June 30,* 2011*			December 31, 2010


				(In millions)
Assets
Current Assets
		Cash and cash equivalents		$	120.6		$	50.0
		Accounts receivable (net of allowance for uncollectibles of $33.9 and $34.9, respectively)			328.8			351.4
		Accounts receivable, unbilled (net of allowance for uncollectibles of $1.0 and $1.0, respectively)			173.4			268.8
		Accounts receivable, affiliated companies			2.1			1.1
		Income taxes receivable, net			—			55.9
		Fuel stocks			51.4			66.5
		Materials and supplies			39.6			31.2
		Prepaid taxes other than income taxes			2.3			51.7
		Regulatory assets (net)			85.2			78.7
		Restricted cash—consolidated variable interest entity			25.2			29.5
		Other			7.2			9.5

		Total current assets			835.8			994.3

	Investments and Other Assets
		Regulatory assets (net)			370.8			374.1
		Receivable, affiliated company			476.2			494.3
		Other			48.4			52.2

		Total investments and other assets			895.4			920.6

	Utility Plant
		Plant in service
			Electric		5,287.9			5,127.9
			Gas		1,353.8			1,323.0
			Common		436.0			507.8

			Total plant in service		7,077.7			6,958.7
		Accumulated depreciation			(2,441.7	)		(2,449.3	)

		Net plant in service			4,636.0			4,509.4
		Construction work in progress			290.8			232.9
		Plant held for future use			10.2			10.1

		Net utility plant			4,937.0			4,752.4

	Total Assets			$	6,668.2		$	6,667.3

* Unaudited
See Notes to Consolidated Financial Statements.

Table of Contents

CONSOLIDATED BALANCE SHEETS

Baltimore Gas and Electric Company and Subsidiaries

			*June 30,* 2011*			December 31, 2010


			(In millions)
Liabilities and Equity
	Current Liabilities
		Current portion of long-term debt	$	131.5		$	22.0
		Current portion of long-term debt—consolidated variable interest entity		61.3			59.7
		Accounts payable		215.1			252.9
		Accounts payable, affiliated companies		69.3			84.9
		Customer deposits		80.0			78.9
		Deferred income taxes		32.1			30.1
		Accrued taxes		39.2			19.0
		Liability for uncertain tax positions		58.7			62.8
		Accrued expenses and other		92.0			99.7

		Total current liabilities		779.2			710.0

	Deferred Credits and Other Liabilities
		Deferred income taxes		1,420.9			1,354.9
		Payable, affiliated company		255.1			250.8
		Deferred investment tax credits		7.9			8.4
		Other		16.6			20.1

		Total deferred credits and other liabilities		1,700.5			1,634.2

	Long-term Debt
		Rate stabilization bonds—consolidated variable interest entity		424.7			454.4
		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		(1.9	)		(2.0	)
		Current portion of long-term debt		(131.5	)		(22.0	)
		Current portion of long-term debt—consolidated variable interest entity		(61.3	)		(59.7	)

		Total long-term debt		1,919.2			2,059.9

	Equity
		Common shareholder's equity		2,079.3			2,073.2
		Preference stock not subject to mandatory redemption		190.0			190.0

		Total equity		2,269.3			2,263.2

	Commitments, Guarantees, and Contingencies (see Notes)
	Total Liabilities and Equity		$	6,668.2		$	6,667.3

* 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,				2011			2010


				(In millions)
Cash Flows From Operating Activities
	Net income			$	97.7		$	81.4
	Adjustments to reconcile to net cash provided by operating activities
		Depreciation and amortization			143.1			128.3
		Other amortization			3.6			1.6
		Deferred income taxes			59.7			55.2
		Investment tax credit adjustments			(0.5	)		(0.5	)
		Deferred fuel costs			17.2			39.0
		Deferred storm costs			(15.5	)		—
		Defined benefit plan expenses			20.3			17.4
		Allowance for equity funds used during construction			(7.0	)		(5.2	)
		Changes in:
			Accounts receivable		115.0			16.0
			Accounts receivable, affiliated companies		(1.0	)		12.9
			Materials, supplies, and fuel stocks		6.7			22.9
			Income tax receivable, net		55.9			—
			Other current assets		28.0			49.9
			Accounts payable		(37.8	)		(7.8	)
			Accounts payable, affiliated companies		(15.6	)		(24.5	)
			Other current liabilities		13.8			(119.8	)
			Long-term receivables and payables, affiliated companies		2.1			(13.9	)
			Regulatory assets, net		(11.4	)		(18.8	)
		Other			(7.8	)		(52.9	)

	Net cash provided by operating activities				466.5			181.2

Cash Flows From Investing Activities
	Utility construction expenditures (excluding equity portion of allowance for funds used during construction)				(304.5	)		(190.3	)
	Proceeds from U.S. Department of Energy grant				28.3			—
	Change in cash pool at parent				—			314.7
	Proceeds from sales of investments and other assets				—			20.9
	Decrease in restricted funds				4.3			0.8

	Net cash (used in) provided by investing activities				(271.9	)		146.1

Cash Flows From Financing Activities
	Repayment of long-term debt				(29.7	)		(28.1	)
	Repayment of short-term borrowings				—			(46.0	)
	Credit facility costs				(2.7	)		—
	Preference stock dividends paid				(6.6	)		(6.6	)
	Distribution to parent				(85.0	)		—

	Net cash used in financing activities				(124.0	)		(80.7	)

Net Increase in Cash and Cash Equivalents					70.6			246.6
Cash and Cash Equivalents at Beginning of Period					50.0			13.6

Cash and Cash Equivalents at End of Period				$	120.6		$	260.2

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

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

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

We made the following reclassifications:

-: We have separately presented "Liability for unrecognized tax benefits" that was previously presented within "Other" on our Consolidated Statements of Cash Flows.
-: We have separately presented "Regulatory assets, net" that was previously presented within "Other" on BGE's Consolidated Statements of Cash Flows.

Pending Merger with Exelon Corporation

On April 28, 2011, Constellation Energy entered into an Agreement and Plan of Merger with Exelon Corporation (Exelon). At closing, each issued and outstanding share of common stock of Constellation Energy will be cancelled and converted into the right to receive 0.93 shares of common stock of Exelon, and Constellation Energy will become a wholly owned subsidiary of Exelon.

The merger agreement contains certain termination rights for both Constellation Energy and Exelon. Under specified circumstances Constellation Energy may be required to pay Exelon a termination fee of $200 million and Exelon may be required to pay Constellation Energy a termination fee of $800 million.

In connection with the proposed merger, Exelon and Constellation Energy announced several commitments, each of which is contingent upon completion of the merger, that they included in their filing for approval of the merger with the Maryland Public Service Commission (Maryland PSC). The estimated value of the commitments, including a proposed rate rebate of $100 per residential BGE customer, is approximately $250 million.

The merger agreement has been approved by both companies' boards of directors, but completion of the merger is contingent upon, among other things, the approval of the transaction by stockholders of both companies and receipt of required regulatory approvals, including the Federal Energy Regulatory Commission, the Nuclear Regulatory Commission, the Maryland PSC and several other state and federal regulatory bodies. The parties are working to complete the merger early in 2012.

During the quarter and six months ended June 30, 2011, we incurred $31. 8 million pre-tax in costs related to our pending merger with Exelon.

Variable Interest Entities

As of June 30, 2011, we consolidate four variable interest entities (VIEs) for which we are the primary beneficiary, and we have significant interests in six other VIEs for which we do not have controlling financial interests. We discuss our VIEs in more detail in Note 4 of our 2010 Annual Report on Form 10-K.

Consolidated Variable Interest Entities

Our, and BGE's, consolidated VIEs consist of:

-: RSB BondCo LLC (BondCo), a special purpose bankruptcy-remote limited liability company formed by BGE to acquire, hold, and to issue and service bonds secured by rate stabilization property,
-: a retail gas group formed to enter into a collateralized gas supply agreement with a third party gas supplier,
-: a retail power supply company, and
-: a group of solar project limited liability companies formed to build, own, and operate solar power facilities. While we own 100% of these entities, we determined that the individual solar project entities are VIEs because either the entities require additional subordinated financial support in the form of loans from the customers in order to obtain the necessary funds for construction of the solar facilities, or the customers absorb price variability from the entities through the fixed price power and/or renewable energy credits purchase agreements. We are the primary beneficiary of the solar project entities because we control the design, construction, and operation of the solar power facilities.

We further discuss how we determine whether we are the primary beneficiary of VIEs in more detail in Note 4 of our 2010 Annual Report on Form 10-K.

For each of our consolidated VIEs:

-: The assets of the VIEs are restricted and can only be used to settle obligations of the respective VIE. In the case of BondCo, BGE is required to remit all payments it receives from customers for rate

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stabilization charges to BondCo. During the quarter and six months ended June 30, 2011, BGE remitted $15.9 million and $38.5 million, respectively, to BondCo. During the quarter and six months ended June 30, 2010, BGE remitted $18.2 million and $42.0 million, respectively, to BondCo.

-

Except for providing capital funding to the solar entities for ongoing construction of the solar power facilities and a $75 million parental guarantee to the third party gas supplier in support of the retail gas group, during the quarter and six months ended June 30, 2011, neither we nor BGE:

-: provided any additional financial support to the VIEs, and
-: had any contractual commitments or obligations to provide financial support to the VIEs.

-

The creditors of the VIEs do not have recourse to our or BGE's general credit.

We include the consolidated VIEs in our consolidated financial statements at June 30, 2011 and December 31, 2010 as follows:

	June 30, 2011		December 31, 2010


	(In millions)
Current assets	$	455.4	$	516.6
Noncurrent assets		50.9		57.7

Total Assets	$	506.3	$	574.3

Current liabilities	$	282.8	$	345.5
Noncurrent liabilities		376.3		399.0

Total Liabilities	$	659.1	$	744.5

Unconsolidated Variable Interest Entities

As of June 30, 2011 and December 31, 2010, we had significant interests in six VIEs for which we were not the primary beneficiary. We have not provided any material financial or other support to these entities during the quarter and six months ended June 30, 2011 and we do not intend to provide any additional financial or other support to these entities in the future.

The following tables present summary information about these entities:

As of June 30, 2011		Power Contract Monetization VIEs		All Other VIEs		Total


		(In millions)
Total assets		$	393.2	$	323.1	$	716.3
Total liabilities			310.6		123.0		433.6
Our ownership interest			—		56.1		56.1
Other ownership interests			82.6		144.0		226.6
Our maximum exposure to loss:
	Letters of credit		20.5		—		20.5
	Carrying amount of our investment—Other investments		—		48.9		48.9
	Debt and payment guarantees		—		5.0		5.0

As of December 31, 2010		Power Contract Monetization VIEs		All Other VIEs		Total


		(In millions)
Total assets		$	492.9	$	288.3	$	781.2
Total liabilities			382.6		113.2		495.8
Our ownership interest			—		48.7		48.7
Other ownership interests			110.3		126.4		236.7
Our maximum exposure to loss:
	Letters of credit		24.9		—		24.9
	Carrying amount of our investment—Other investments		—		41.4		41.4
	Debt and payment guarantees		—		5.0		5.0

We assess the risk of a loss equal to our maximum exposure to be remote. 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.

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Earnings Per Share

Basic earnings per common share (EPS) is computed by dividing net income 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,

	2011		2010		2011		2010

	(In millions)
Non-dilutive stock options		4.2		4.4		5.6		4.4
Dilutive common stock equivalent shares		1.8		1.8		1.6		1.6

Acquisitions

MXenergy Holdings Inc.

In July 2011, we acquired all of the outstanding stock of MXenergy Holdings Inc. (MXenergy), a retail energy marketer of natural gas and electric power to residential and commercial customers, for approximately $175 million, subject to certain purchase price adjustments. MXenergy serves approximately 540,000 customers in several markets across the United States and Canada. We will account for this acquisition as a business combination within our NewEnergy business segment. We will include MXenergy's results of operations in our consolidated financial statements as of the date of acquisition.

Star Electricity, Inc.

In May 2011, we acquired all of the outstanding stock of Star Electricity, Inc. (StarTex), a retail electric provider, for $163.5 million in cash, all of which was paid at closing. StarTex serves approximately 170,000 customers in the Texas residential market.

We recorded the acquisition as follows:

At May 27, 2011


	(In millions)
Cash and cash equivalents	$	17.9
Other current assets		42.2
Goodwill¹		100.9
Acquired contracts and intangibles^{1 2}		78.3
Other assets		1.2

Total assets acquired		240.5

Total liabilities		(77.0	)

Net assets acquired	$	163.5

1 None is deductible for tax purposes.
2 The weighted average amortization for these assets is approximately 3 years.

The preliminary net assets acquired are based on estimates, the resolution of which could impact the final net assets acquired.

We have included StarTex's results of operations in our consolidated financial statements as part of our NewEnergy business segment since the date of acquisition.

The proforma impact of this acquisition would not have been material to our results of operations for the quarters and six months ended June 30, 2011 and 2010 and to our financial condition as of December 31, 2010.

Boston Generating

In January 2011, we acquired Boston Generating's 2,950 MW fleet of generating plants for cash of $1.1 billion. The fleet acquired includes the following four natural gas power plants and one fuel oil plant located in the Boston, Massachusetts area:

-: Mystic 7—574 MW,
-: Mystic 8 and 9—1,580 MW,
-: Fore River—787 MW, and
-: Mystic Jet, a fuel oil plant—9 MW.

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We recorded the acquisition as follows:

At January 3, 2011


	(In millions)
Current assets	$	92.2
Land		29.2
Property, plant and equipment		1,061.8
Noncurrent assets		0.1

Total assets acquired		1,183.3

Current liabilities		(77.5	)
Noncurrent liabilities		(21.8	)

Total liabilities		(99.3	)

Net assets acquired	$	1,084.0

We have included the results of operations from these plants in our consolidated financial statements as part of our Generation business segment since the date of acquisition.

Divestitures

Constellation Energy Partners LLC

In June 2011, we agreed to sell all of our interests in Constellation Energy Partners LLC (CEP) to PostRock Energy Corporation (PostRock). Under the terms of that agreement, PostRock would receive all of our voting rights, including our right to appoint two of the five members of CEP's board of directors. In return, we would receive cash, PostRock common stock and warrants to acquire additional shares of PostRock common stock at a premium to the market price at the closing of the transaction. At the date of this filing, we are discussing with PostRock potential modifications to the transaction. We expect this transaction to close in 2011.

Quail Run Energy Center

In December 2010, we signed an agreement to sell our Quail Run Energy Center (Quail Run), a 550 MW natural gas plant in west Texas, to High Plains Diversified Energy Corporation (HPDEC). This agreement was contingent upon HPDEC obtaining financing through the sale of municipal bonds.

In June 2011, we terminated the agreement to sell Quail Run based on the buyer's inability to satisfy all of the conditions for the sale.

Gain on U.S. Department of Energy Settlement

On June 30, 2011, CENG executed a settlement agreement with the United States Department of Energy (DOE) under which Constellation Energy will receive payment of $35.5 million related to costs incurred through October 31, 2008 to store spent nuclear fuel at the Calvert Cliffs nuclear power plant. The settlement also details a framework and procedure for recovery of damages incurred or to be incurred through the end of 2013. The agreement settles a lawsuit that sought to recover damages caused by the DOE's failure to comply with legal and contractual obligations to dispose of spent nuclear fuel at the Calvert Cliffs nuclear power plant. We discuss our lawsuit involving CENG's nuclear plants in more detail in our 2010 Annual Report on Form 10-K.

As part of the 2009 agreement between Constellation Energy and EDF in which Constellation Energy sold a 49.99% interest in CENG to EDF, Constellation Energy retained the right to receive payments from any settlement with the DOE that related to periods prior to the formation of the joint venture on November 6, 2009. As such, Constellation Energy recognized a pre-tax gain in the second quarter of 2011 for $35.5 million and we expect to receive the funds in the third quarter of 2011.

The lawsuits relating to the storage of spent nuclear fuel at the Ginna and Nine Mile Point nuclear power plants remain outstanding.

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Investment in Constellation Energy Nuclear Group, LLC (CENG)

We own a 50.01% interest in CENG, a nuclear generation and operation business. Our total equity in earnings of our investment in CENG is as follows:

	Quarter Ended June 30,						Six Months Ended June 30,

	2011			2010			2011			2010

	(In millions)
CENG	$	14.9		$	40.2		$	27.6		$	63.6
Amortization of basis difference in CENG		(39.9	)		(61.5	)		(69.2	)		(104.2	)

Total equity investment losses—CENG¹	$	(25.0	)	$	(21.3	)	$	(41.6	)	$	(40.6	)

1 For the quarters ended June 30, 2011 and 2010, total equity investment earnings (losses) in CENG include $0.5 million and $0.5 million, respectively, of expense related to the portion of cost of certain share-based awards that we fund on behalf of EDF Group and affiliates (EDF). For the six months ended June 30, 2011 and 2010, total equity investment earnings (losses) in CENG include $0.9 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 carrying amount of our investment in CENG and our share of the underlying equity in CENG, because the underlying assets of CENG were retained at their historical carrying value. See Note 2 to our 2010 Annual Report on Form 10-K for a more detailed discussion.

Summarized income statement information for CENG for the quarters and six months ended June 30, 2011 and 2010 is as follows:

	Quarter Ended June 30,				Six Months Ended June 30,

	2011		2010		2011		2010

	(In millions)
Revenues	$	354.5	$	376.1	$	713.1	$	737.0
Expenses		333.8		302.9		675.2		626.2
Income from operations		20.7		73.2		37.9		110.8
Net income		30.9		81.3		57.1		130.4

Regulatory Assets (net)

In March 2011, the Maryland PSC issued a comprehensive rate order setting forth the details of the decision contained in its abbreviated electric and gas distribution rate order issued in December 2010. As part of the March 2011 comprehensive rate order, BGE was authorized to defer $18.9 million of costs as regulatory assets. These costs will be recovered over a 5-year period beginning December 2010 and relate to the deferral of:

-: $15.8 million of storm costs incurred in February 2010,
-: $2.7 million of electric deferred income tax expense recognized in 2010 relating to the elimination of the tax exempt status of drug subsidies provided to companies under Medicare Part D after December 31, 2012, and
-: $0.4 million of electric workforce reduction costs incurred in 2010.

The regulatory assets for the storm costs and the workforce reduction costs will earn a regulated rate of return.

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Information by Operating Segment

Our reportable operating segments are Generation, NewEnergy, Regulated Electric, and Regulated Gas. We discuss our reportable operating segments in detail in Note 3 of our 2010 Annual Report on Form 10-K.

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

	Reportable Segments

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

	(In millions)
Quarter ended June 30,
2011
Unaffiliated revenues	$	256.4	$	2,447.8	$	546.9	$	108.2		$	0.5		$	—		$	3,359.8
Intersegment revenues		420.1		112.0		0.2		0.9			—			(533.2	)		—

Total revenues		676.5		2,559.8		547.1		109.1			0.5			(533.2	)		3,359.8
Net income (loss)		40.9		51.7		22.9		(6.3	)		(1.1	)		—			108.1
Net income (loss) attributable to common stock		40.9		46.1		20.5		(7.2	)		(1.1	)		—			99.2
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
Six months ended June 30,
2011
Unaffiliated revenues	$	515.9	$	4,802.7	$	1,197.0	$	414.4		$	—		$	—		$	6,930.0
Intersegment revenues		828.2		169.2		0.3		2.0			—			(999.7	)		—

Total revenues		1,344.1		4,971.9		1,197.3		416.4			—			(999.7	)		6,930.0
Net income (loss)		53.7		40.3		62.6		35.1			(4.2	)		—			187.5
Net income (loss) attributable to common stock		53.7		29.0		57.7		33.4			(4.2	)		—			169.6
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

Our Generation business operating results for the quarter and six months ended June 30, 2011 include the following after-tax items:

-: amortization of basis difference in investment in CENG of $24.0 million and $41.6 million, respectively,
-: impact of power purchase agreement with CENG of $30.3 million and $57.3 million, respectively, (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"),
-: gain on settlement with DOE for storage of spent nuclear fuel of $21.3 million and $21.3 million, respectively,
-: transaction fees incurred related to our acquisition of Boston Generating's 2,950 MW fleet of generating plants in Massachusetts of $0.1 million and $10.1 million, respectively, and
-: costs incurred related to our pending merger with Exelon of $9.5 million and $9.5 million, respectively.

Our NewEnergy business operating results for the quarter and six months ended June 30, 2011 include the amortization of credit facility amendment fees in connection with the 2009 EDF transaction of $1.5 million and $3.0 million, respectively, and costs incurred relating to our pending merger with Exelon of $4.3 million and $4.3 million, respectively.

Our Regulated Electric business operating results for the quarter and six months ended June 30, 2011 include costs incurred relating to our pending merger with Exelon of $4.1 million and $4.1 million, respectively. BGE will not seek recovery of these costs in rates.

Our Regulated Gas business operating results for the quarter and six months ended June 30, 2011 include costs incurred relating to our pending merger with Exelon of $1.4 million and $1.4 million, respectively. BGE will not seek recovery of these costs in rates.

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Pension and Postretirement Benefits

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

	Quarter Ended June 30,						Six Months Ended June 30,

	2011			2010			2011			2010

	(In millions)
Components of net periodic pension benefit cost
Service cost	$	15.0		$	9.1		$	26.4		$	18.6
Interest cost		24.6			19.7			47.2			41.4
Expected return on plan assets		(32.3	)		(23.2	)		(62.3	)		(49.9	)
Recognized net actuarial loss		11.9			8.7			24.1			16.8
Amortization of prior service cost		1.1			0.9			2.1			1.9
Amount capitalized as construction cost		(3.2	)		(2.9	)		(6.1	)		(4.8	)

Net periodic pension benefit cost¹	$	17.1		$	12.3		$	31.4		$	24.0

1 BGE's portion of our net periodic pension benefit cost, excluding amounts capitalized, was $9.0 million for the quarter ended June 30, 2011 and $8.5 million for the quarter ended June 30, 2010. BGE's portion of our net periodic pension benefit cost, excluding amounts capitalized, was $18.1 million for the six months ended June 30, 2011 and $14.8 million for the six months ended June 30, 2010. Net periodic pension benefit costs exclude settlement charges of $1.5 million in the quarter and six months ended June 30, 2010.

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

	Quarter Ended June 30,						Six Months Ended June 30,

	2011			2010			2011			2010

	(In millions)
Components of net periodic postretirement benefit cost
Service cost	$	0.8		$	0.6		$	1.5		$	1.3
Interest cost		5.1			5.0			9.3			9.7
Amortization of transition obligation		0.5			0.6			1.0			1.1
Recognized net actuarial loss (gain)		0.2			(0.1	)		0.8			0.2
Amortization of prior service cost		(0.9	)		(0.7	)		(1.5	)		(1.4	)
Amount capitalized as construction cost		(1.7	)		(1.6	)		(3.1	)		(2.9	)

Net periodic postretirement benefit cost¹	$	4.0		$	3.8		$	8.0		$	8.0

1 BGE's portion of our net periodic postretirement benefit cost, excluding amounts capitalized, was $4.9 million for the quarter ended June 30, 2011 and $4.6 million for the quarter ended June 30, 2010. BGE's portion of our net periodic postretirement benefit costs, excluding amounts capitalized, was $9.5 million for the six months ended June 30, 2011 and $9.4 million for the six months ended June 30, 2010.

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 $9.4 million in pension benefit payments for our non-qualified pension plans and approximately $22.6 million for retiree health and life insurance costs in 2011.

Financing Activities

Credit Facilities and Short-term Borrowings

We discuss the purposes for and the types of instruments used for entering into credit facilities and short-term borrowings in Note 8 of our 2010 Annual Report on Form 10-K.

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Constellation Energy

Constellation Energy had bank lines of credit under committed credit facilities totaling $4.2 billion at June 30, 2011 for short-term financial needs, primarily for our NewEnergy business, as follows:

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


Syndicated Revolver		$	2.50	October 2013	Letters of credit and cash
Commodity-linked			0.50	August 2014	Letter of credit and cash
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	$	4.20

At June 30, 2011, we had approximately $1.4 billion in letters of credit issued, including $0.3 billion in letters of credit issued under the commodity-linked credit facility, and no commercial paper outstanding under these facilities. The commodity-linked facility capacity increases as natural gas price levels decrease compared to a reference price that is adjusted periodically. As of June 30, 2011, this facility's capacity was $0.3 billion.

In July 2011, a subsidiary of Constellation Energy entered into a three-year senior secured credit facility that is designed to support the growth of our solar operations. The amount committed under the facility is $150 million, which may be increased up to $200 million at the subsidiary's request with additional commitments by the lenders. At closing, we borrowed $130.0 million. Borrowings incur interest at a variable rate payable quarterly and are secured by the equity interests in the subsidiary and the entities that own the solar projects as well as the assets of the subsidiary and each project entity. The obligations of our subsidiary are guaranteed by Constellation Energy and the project entities. The Constellation Energy guaranty will terminate upon the subsidiary obtaining a stand-alone investment grade credit rating or the satisfaction of a number of conditions, at which time the financing will become nonrecourse to Constellation Energy. We discuss the accounting treatment for our solar operations in more detail on page 9.

Also, in July 2011, we amended and extended our existing reserve based lending facility that supports our upstream gas operations. The borrowing base committed under the facility was increased to $150 million and can grow up to a total of $500 million if the assets support a higher borrowing base and we are able to obtain additional commitments from lenders. The facility now expires in July 2016. Borrowings under this facility are secured by the upstream gas properties, and the lenders do not have recourse against Constellation Energy in the event of a default. At closing, we borrowed $74.0 million under the facility with interest payable quarterly. The facility includes a provision that requires our entities that own the upstream gas properties subject to the agreement to maintain a current ratio of one-to-one.

In July 2011, a subsidiary of Constellation Energy entered into a $40 million nonrecourse project financing to fund construction of our 30MW solar facility in Sacramento, California. Borrowings will incur interest at a variable rate, payable quarterly, and are secured by the equity interests and assets of the subsidiary. The construction borrowings will convert into a 19-year variable rate note upon commercial operation of the facility. Construction is expected to be completed by December 2011. The subsidiary also executed interest rate swaps for a notional amount of $30 million in order to convert the variable interest payments to fixed payments on the $40 million facility amount.

In addition to this facility, this subsidiary entered into a treasury grant bridge loan for $26 million and an equity bridge loan for $28 million. Both loans will be utilized to fund construction and must be repaid shortly after commercial operations of the solar facility.

At June 30, 2011, Constellation Energy had $20.6 million of short-term notes outstanding with a weighted average effective interest rate of 6.54%.

BGE

As of June 30, 2011, BGE has a $600.0 million revolving credit facility expiring in March 2015. 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, 2011, BGE had no commercial paper or direct borrowings outstanding. There were immaterial letters of credit outstanding at June 30, 2011. As of July 31, 2011, BGE had $30.0 million of commercial paper outstanding.

Debt

In January 2011, we redeemed $213.5 million of our 7.00% Notes, which represented the remaining outstanding 7.00% Notes due April 1, 2012, pursuant to a notice to redeem that was issued in December 2010. We redeemed these notes with part of the proceeds from the $550 million 5.15% Notes issued in December 2010, terminated certain interest rate swaps and recognized a pre-tax loss of approximately $5 million on this transaction. We discuss the termination of the interest rate swaps in our Derivative Instruments note.

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Net Available Liquidity

The following table provides a summary of our, and BGE's, net available liquidity at June 30, 2011:

At June 30, 2011	Constellation Energy (excluding BGE)			BGE


	(In billions)
Credit facilities¹	$	3.7		$	0.6
Less: Letters of credit issued¹		(1.1	)		—
Less: Cash drawn on credit facilities		—			—

Undrawn facilities		2.6			0.6
Less: Commercial paper outstanding		—			—

Net available facilities		2.6			0.6
Add: Cash and cash equivalents²		0.8			0.1
Less: Reserved cash³		(0.2	)		—

Net available liquidity	$	3.2		$	0.7

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

2 BGE's cash balance at June 30, 2011 was $120.6 million.

3 Represents cash used in July 2011 to acquire MXenergy. See Acquisitions note for more detail.

Credit Facility Compliance and Covenants

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.

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, 2011, the debt to capitalization ratio as defined in the credit agreements was 33%.

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, 2011, 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 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.

Income Taxes

We compute the income tax expense for each quarter based on the estimated annual effective tax rate for the year. The effective tax rate was 40.4% and 39.7% for the quarter and six months ended June 30, 2011, respectively, compared to 30.9% and 32.6% for the same periods of 2010. The higher effective tax rates for the quarter and six months ended June 30, 2011 are primarily due to lower deductions for qualified production activities and higher expense associated with uncertain tax positions and increased state income taxes, resulting from increased business activity in unitary states and changes in the Illinois and Michigan tax laws.

The BGE effective tax rate was 39.2% and 37.0% for the quarter and six months ended June 30, 2011, respectively, compared to 41.4% and 41.6% for the same periods of 2010. The lower effective tax rates for 2011 are primarily due to the partial reversal during the quarter ended March 31, 2011 of the unfavorable tax adjustment recorded in the quarter ended March 31, 2010 to reflect the impact on our regulated electric business of the healthcare reform legislation that eliminated the tax exempt status of prescription drug subsidies received under Medicare Part D. The partial reversal in 2011 resulted from the Maryland PSC's authorization for BGE to create an electric regulatory asset for this tax law change and amortize the balance over a five-year period as provided in its March 2011 comprehensive order in BGE's most recent base rate case.

Income tax expense for both Constellation Energy and BGE for the quarter and six months ended June 30, 2011 reflects a deferred tax benefit for the costs incurred associated with our pending merger with Exelon. The ultimate treatment of these costs for tax purposes will be determined at the time the merger is closed or terminated. We discuss our pending merger with Exelon on page 9.

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Unrecognized Tax Benefits

The following table summarizes the change in unrecognized tax benefits during 2011 and our total unrecognized tax benefits at June 30, 2011:

At June 30, 2011


	(In millions)
Total unrecognized tax benefits, January 1, 2011	$	239.8
Increases in tax positions related to the current year		1.4
Increases in tax positions related to prior years		4.1
Reductions in tax positions related to prior years		(8.7	)

Total unrecognized tax benefits, June 30, 2011¹	$	236.6

1 BGE's portion of our total unrecognized tax benefits at June 30, 2011 was $66.3 million.

If the total amount of unrecognized tax benefits of $236.6 million were ultimately realized, our income tax expense would decrease by approximately $170 million. The $170 million includes state tax refund claims of $55.9 million that have been disallowed by tax authorities and are subject to appeals.

It is reasonably possible that unrecognized tax benefits could decrease within the next year by approximately $66 million primarily as a result of an expected settlement with the IRS regarding BGE's change of accounting method for tax purposes with respect to certain transmission and distribution expenditures. This decrease is not expected to have a material impact on BGE's financial condition or results of operation.

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

	Quarter Ended June 30,					Six Months Ended June 30,

	2011		2010			2011		2010

	(In millions)
Interest and penalties recorded as tax expense (benefit)	$	2.7	$	(10.7	)	$	5.5	$	(7.3	)

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

Accrued interest and penalties recognized in our Consolidated Balance Sheets were $22.3 million, of which BGE's portion was $5.0 million, at June 30, 2011, and $16.8 million, of which BGE's portion was $3.8 million, at December 31, 2010.

Taxes Other Than Income Taxes

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

BGE and our NewEnergy operations collect certain taxes from customers such as sales and gross receipts taxes, along with other taxes, surcharges, and fees that are levied by state or local governments on the sale or distribution of gas and electricity. 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. 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. The taxes, surcharges, or fees that are included in revenues were as follows:

	Quarter Ended June 30,				Six Months Ended June 30,

	2011		2010		2011		2010

	(In millions)
Constellation Energy (including BGE)	$	35.5	$	30.5	$	70.2	$	61.5
BGE		19.6		19.3		42.6		41.2

Guarantees

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

At June 30, 2011	Stated Limit


	(In billions)
Constellation Energy guarantees	$	9.3
BGE guarantees		0.3

Total guarantees	$	9.6

At June 30, 2011, Constellation Energy had a total of $9.6 billion in guarantees outstanding related to loans, credit facilities, and contractual performance of certain of its subsidiaries as described below.

-

Constellation Energy guaranteed a face amount of $9.3 billion as follows:

-: $8.8 billion on behalf of our Generation and NewEnergy businesses to allow them the

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flexibility needed to conduct business with counterparties without having to post other forms of collateral. Our estimated net exposure for obligations under commercial transactions covered by these guarantees was approximately $1.5 billion at June 30, 2011, which represents the total amount the parent company could be required to fund based on June 30, 2011 market prices. For those guarantees related to our derivative liabilities, the fair value of the obligation is recorded in our Consolidated Balance Sheets.

-: $0.5 billion primarily on behalf of CENG's nuclear generating facilities for nuclear insurance and credit support to ensure these plants have funds to meet expenses and obligations to safely operate and maintain the plants. We recorded the fair value of $11.1 million for these guarantees on our Consolidated Balance Sheets.

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

Commitments and Contingencies

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

-: purchase of electric generating capacity and energy as well as renewable energy credits,
-: procurement and delivery of fuels,
-: the capacity and transmission and transportation rights for the physical delivery of power and gas to meet our obligations to our customers, and
-: service agreements, capital for construction programs, and other.

Our Generation and NewEnergy businesses enter into various contracts for the procurement and delivery of fuels primarily related to supplying 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 2011 and 2030. In addition, our Generation and NewEnergy businesses enter into contracts for the purchase of energy, capacity and transmission rights for the delivery of energy to meet our physical obligations to our customers. These contracts expire in various years between 2011 and 2023.

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

Our regulated electric business enters into various contracts for the procurement of electricity. These contracts expire between 2011 and 2013 and represent BGE's estimated requirements to serve residential and small commercial customers as follows:

Contract Duration


From July 1, 2011 to May 2012	100	%
From June 2012 to September 2012	75
From October 2012 to May 2013	50
From June 2013 to September 2013	25

The cost of power under these contracts is recoverable under the Provider of Last Resort agreement reached with the Maryland PSC.

Our regulated gas business enters into various contracts for the procurement, transportation, and storage of gas. Our regulated gas business has gas procurement contracts that expire in 2011 and transportation and storage contracts that expire between 2012 and 2027. The cost of gas under these contracts is recoverable under BGE's gas cost adjustment clause discussed in Note 1 of our 2010 Annual Report on Form 10-K.

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

At June 30, 2011, the total amount of commitments was $7.0 billion. These commitments are primarily related to our Generation and NewEnergy businesses.

Long-Term Power Sales Contracts

We enter into long-term power sales contracts in connection with our load-serving activities. We also enter into long-term power sales contracts associated with certain of our power plants. Our load-serving power sales contracts extend for terms through 2031 and provide for the sale of energy to electricity distribution utilities and certain retail customers. Our power sales contracts associated with our power producing facilities, including renewable energy, extend for terms into 2033 and provide for the sale of all or a portion of the actual output of certain of our power producing facilities. Substantially all long-term contracts were executed at pricing that approximated market rates, including profit margin, at the time of execution.

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Contingencies

Litigation

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

Merger with Exelon

In late April and early May 2011, shortly after Constellation Energy and Exelon announced their agreement to merge the two companies, twelve shareholder class action lawsuits were filed in the Circuit Court for Baltimore City in Maryland. Each class action suit was filed on behalf of a proposed class of the shareholders of Constellation Energy against Constellation Energy, members of Constellation Energy's board of directors, and Exelon. The shareholder class actions generally allege that the individual directors breached their fiduciary duties by entering into the proposed merger because they failed to maximize the value that the shareholders would receive from the merger, and failed to disclose adequately all material information relating to the proposed merger. The class actions also allege that Constellation Energy and Exelon aided and abetted the individual directors' breaches of their fiduciary duties. The lawsuits challenge the proposed merger, seek to enjoin a shareholder vote on the proposed merger until all material information is provided relating to the proposed merger, and ask for rescission of the proposed merger and any related transactions that have been completed as of the date that the court grants any relief. The class action lawsuits also seek certification as class actions, compensatory damages, costs and disbursements related to the action, including attorneys' and experts' fees, and rescission damages. Plaintiffs in three of the twelve lawsuits subsequently filed motions to consolidate all the lawsuits. The court has granted the motion to consolidate and all actions are now proceeding as a single lawsuit. Given that these lawsuits were recently filed, that the court has not certified any class and the plaintiffs have not quantified their potential damage claims, we are unable at this time to provide an estimate of the range of possible loss relating to these proceedings or to determine the ultimate outcome of these lawsuits or their possible effect on our, or BGE's, financial results or their possible effect on the pending merger with Exelon.

Securities Class Action

Three federal securities class action lawsuits were 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 in Maryland 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. On August 13, 2010, the District Court of Maryland issued a ruling on the motion to dismiss, holding that the plaintiffs failed to state a claim with respect to the claims of the common shareholders under the Securities Act of 1934 and restricting the suit to those persons who purchased Debentures in the June 2008 offering. Given that the discovery phase has just begun, that the court has not certified any class and the plaintiffs have not quantified their potential damage claims relating to the June 2008 offering, we are unable at this time to provide an estimate of the range of possible loss relating to these proceedings or to determine the ultimate outcome of the securities class actions or their possible effect on our, or BGE's financial results.

Mercury

Since September 2002, BGE, Constellation Energy, and several other defendants have been involved in numerous actions filed in the Circuit Court for Baltimore City, Maryland alleging mercury poisoning from several sources, including coal plants formerly owned by BGE. The plants are now owned by a subsidiary of Constellation Energy. In addition to BGE and Constellation Energy, approximately 11 other defendants, consisting of pharmaceutical

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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 any appeals vigorously. We are unable to provide an estimate of the range of possible loss relating to these cases given that only limited discovery occurred in these cases prior to the dismissals being granted and, as a result, we cannot predict the outcome of these cases, or their possible effect on our, or BGE's, financial results.

Asbestos

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

Approximately 477 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 by BGE or Constellation Energy and a small minority of these cases have been resolved for amounts that were not material to our financial results.

Discovery begins in these cases once they are placed on the trial docket. At present, only a small number of our pending cases have reached the trial docket. Given the limited discovery, BGE and Constellation Energy do not know the specific facts that we believe are necessary for us to provide an estimate of the possible loss relating to these claims. The specific facts we do not know include:

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

Insurance and hold harmless agreements from contractors who employed the plaintiffs may cover a portion of any awards in the actions.

Environmental Matters

Solid and Hazardous Waste

In 1999, the EPA proposed to add the 68th Street Dump in Baltimore, Maryland to the Superfund National Priorities List, which is its list of sites targeted for clean-up and enforcement, and sent a general notice letter to BGE and 19 other parties identifying them as potentially responsible 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 potentially responsible parties submitted their investigation of the range of clean-up options in the first quarter of 2011. Although the investigation and options provided to the EPA are still subject to EPA review, we believe that the range of estimated clean-up costs to be allocated among all of the potentially responsible parties will be between approximately $50 million and $64 million depending on the clean-up option selected by the EPA. The EPA is expected to make a final selection of one of the alternatives in 2012. As the alternative to be selected by the EPA and the allocation of the clean-up costs among the potentially responsible parties is not yet known, we cannot provide an estimate of the range of our possible loss.

Air Quality

In January 2009, the EPA issued a notice of violation (NOV) to a subsidiary of Constellation Energy, as well as to the other owners and the operator of the Keystone coal-fired power plant in Shelocta, Pennsylvania. We hold a 20.99% 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

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permits. The EPA could seek civil penalties under the Clean Air Act for the alleged violations.

The owners and operator of the Keystone plant have investigated the allegations and had a meeting with the EPA where they provided the EPA with both legal and factual documentation to support their position that no violations have occurred. Since that time, the EPA has not requested any further meeting or otherwise acted on the allegations. We believe there are meritorious defenses to the allegations contained in the NOV. Because there are significant facts in dispute and this matter is only in the NOV stage, at this time we cannot estimate the range of possible loss or predict whether a proceeding will be commenced.

Water Quality

In October 2007, a subsidiary of Constellation Energy entered into a consent decree with the Maryland Department of the Environment relating to groundwater contamination at a third party facility that was licensed to accept fly ash, a byproduct generated by our coal-fired plants. The consent decree requires the payment of a $1.0 million penalty, remediation of groundwater contamination resulting from the ash placement operations at the site, replacement of drinking water supplies in the vicinity of the site, and monitoring of groundwater conditions. We recorded a liability in our Consolidated Balance Sheets of approximately $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 $7.2 million of these costs as of June 30, 2011, resulting in a remaining liability at June 30, 2011 of $3.4 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.

In April 2007, PennEnvironment and the Sierra Club brought a Clean Water Act citizen suit against the operator of the Conemaugh power plant in Pennsylvania, seeking civil penalties and injunctive relief for alleged violations of Conemaugh's water permit. Throughout the relevant time period, the operator of the Conemaugh plant has been working closely with the Pennsylvania Department of Environmental Protection (PADEP) to ensure that the facility operates in an environmentally sound manner, and does not cause any adverse environmental impacts. Pursuant to a consent order between PADEP and the operator, a variety of studies have been conducted and treatment facilities have been designed and have been built or are pending construction, all in order to comply with the stringent limits set out in Conemaugh's water permit. On March 21, 2011, the court entered a partial summary judgment in the plaintiffs' favor, declaring as a matter of law that discharges from the Conemaugh plant had violated the water permit. In June 2011, the parties agreed to settle the proceeding for an immaterial amount.

Insurance

We discuss our non-nuclear insurance programs in Note 12 of our 2010 Annual Report on Form 10-K.

Derivative Instruments

Risks, Objectives, and Strategies

Substantially all of our risk management activities involving derivatives occur in our competitive businesses. In carrying out our competitive business activities, we purchase and sell power, fuel, and other energy-related commodities in competitive markets. These activities expose us to significant risks, including market risk from price volatility for energy commodities and the credit risks of counterparties with which we enter into contracts.

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. We also enter into derivative contracts for trading purposes.

We discuss the nature of our business and associated risks in connection with our objectives and strategies for using derivatives for both risk management and non-risk management activities in Note 13 of our 2010 Annual Report on Form 10-K.

Accounting for Derivative Instruments

We recognize all qualifying derivative instruments on the balance sheet at fair value as either assets or liabilities.

Accounting Designation

We must evaluate new and existing transactions and agreements to determine whether they meet the definition of a derivative, for which there are several possible accounting treatments. The permissible accounting treatments include:

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

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.

We discuss our accounting policies for derivatives and hedging activities and their impacts on our financial statements in Note 1 to our 2010 Annual Report on Form 10-K.

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In the sections below, we describe the significant activity in 2011 by accounting treatment.

NPNS

We continue to elect NPNS accounting for certain 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.

Cash Flow Hedging

Commodity Cash Flow Hedges

We have designated fixed-price forward contracts as cash-flow hedges of forecasted purchases and sales of energy, fuel, and other related commodities for the years 2011 through 2017. We had net unrealized pre-tax losses on these cash-flow hedges recorded in "Accumulated other comprehensive loss" of $312.5 million at June 30, 2011 and $388.0 million at December 31, 2010.

We expect to reclassify $156.8 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, 2011. However, the actual amount reclassified into earnings could vary from the amounts recorded at June 30, 2011, due to future changes in market prices.

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

	Quarter Ended June 30,					Six Months Ended June 30,

	2011			2010		2011			2010

	(In millions)
Pre-tax gains (losses)	$	(0.3	)	$	1.1	$	(0.3	)	$	(0.3	)

Interest Rate Swaps Designated as Cash Flow Hedges

Accumulated other comprehensive loss includes net unrealized pre-tax gains on interest rate cash-flow hedges of prior debt issuances totaling $8.8 million at June 30, 2011 and $10.1 million at December 31, 2010. We expect to reclassify $0.1 million of pre-tax net gains on these cash-flow hedges from "Accumulated other comprehensive loss" into "Interest expense" during the next twelve months. We had no hedge ineffectiveness on these swaps.

Fair Value Hedging

We elect fair value hedge accounting for a limited portion of our derivative contracts including certain interest rate swaps and certain forward contracts and swaps associated with natural gas fuel in storage. The objectives for electing fair value hedge accounting in these situations are to manage our exposure to changes in the fair value of our assets and liabilities, to optimize the mix of our fixed and floating-rate debt, and to hedge the value of our natural gas in storage.

Interest Rate Swaps Designated as Fair Value Hedges

At December 31, 2010, we had interest rate swaps qualifying as fair value hedges relating to $400 million of our fixed-rate debt maturing in 2012 and 2015. The fair value of these hedges was an unrealized gain of $35.7 million at December 31, 2010.

At June 30, 2011, we have interest rate swaps qualifying as fair value hedges relating to $550 million of our fixed-rate debt maturing in 2015, and converted this notional amount of debt to floating-rate. The fair value of these hedges was an unrealized gain of $35.3 million at June 30, 2011.

We recorded the fair value of these hedges as an increase in our "Derivative assets" and an increase in our "Long-term debt."

Hedge Ineffectiveness

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

	Quarter Ended June 30,						Six Months Ended June 30,

	2011			2010			2011			2010

	(In millions)
Cash-flow hedges	$	(5.9	)	$	(37.6	)	$	(22.8	)	$	(24.3	)
Fair value hedges		(1.9	)		—			(1.8	)		—

Total	$	(7.8	)	$	(37.6	)	$	(24.6	)	$	(24.3	)

The ineffectiveness in the table above excludes a pre-tax gain of $1.1 million related to the change in our fair value hedges excluded from hedge ineffectiveness for the quarter and six months ended June 30, 2011. We did not recognize any gain or loss related to the change in our fair value hedges excluded from hedge ineffectiveness during the quarter and six months ended June 30, 2010.

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Mark-to-Market

During February 2011, we entered into interest rate swaps through 2015 related to $150 million of our fixed rate debt maturing in 2020, and converted this notional amount of debt to floating rate over the related time frame. However, these interest rate swaps do not qualify as fair value hedges and will be marked to market through earnings.

Quantitative Information About Derivatives and Hedging Activities

Balance Sheet Tables

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

The following tables provide information about the 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.

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.

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The contracts in the tables below are segregated between derivatives designated for hedge accounting and those not designated for hedge accounting. Derivatives not designated in hedging relationships include our NewEnergy retail operations, economic hedges of accrual activities, and risk management and trading activities. We use the end of period accounting designation to determine the classification for each derivative position.

As of June 30, 2011		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	$	1,018.7	$	(1,037.6	)	$	4,573.0	$	(4,977.8	)	$	5,591.7		$	(6,015.4	)
	Gas contracts		1,405.9		(1,432.1	)		2,682.9		(2,516.5	)		4,088.8			(3,948.6	)
	Coal contracts		55.0		(32.0	)		154.7		(142.8	)		209.7			(174.8	)
	Other commodity contracts¹		—		—			305.9		(299.8	)		305.9			(299.8	)
	Interest rate contracts		35.3		—			40.7		(37.9	)		76.0			(37.9	)
	Foreign exchange contracts		—		—			13.7		(8.2	)		13.7			(8.2	)

Total gross fair values		$	2,514.9	$	(2,501.7	)	$	7,770.9	$	(7,983.0	)	$	10,285.8		$	(10,484.7	)

	Netting arrangements⁵												(9,717.9	)		9,717.9
	Cash collateral												(58.8	)		2.5

Net fair values												$	509.1		$	(764.3	)

Net fair value by balance sheet line item:
Accounts receivable²												$	(72.7	)
Derivative assets—current													324.3
Derivative assets—noncurrent													257.5
Derivative liabilities—current																(494.2	)
Derivative liabilities—noncurrent																(270.1	)

Total Derivatives												$	509.1		$	(764.3	)

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

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

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

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

5 Represents the effect of legally enforceable master netting agreements.

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As of December 31, 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	$	1,167.9	$	(1,362.8	)	$	6,795.0	$	(7,166.5	)	$	7,962.9		$	(8,529.3	)
	Gas contracts		1,902.3		(1,832.8	)		3,390.1		(3,155.3	)		5,292.4			(4,988.1	)
	Coal contracts		97.0		(48.6	)		266.0		(259.7	)		363.0			(308.3	)
	Other commodity contracts¹		—		—			61.4		(61.6	)		61.4			(61.6	)
	Interest rate contracts		35.7		—			34.4		(35.7	)		70.1			(35.7	)
	Foreign exchange contracts		—		—			11.0		(8.4	)		11.0			(8.4	)

Total gross fair values		$	3,202.9	$	(3,244.2	)	$	10,557.9	$	(10,687.2	)	$	13,760.8		$	(13,931.4	)

	Netting arrangements⁵												(12,955.5	)		12,955.5
	Cash collateral												(28.4	)		0.6

Net fair values												$	776.9		$	(975.3	)

Net fair value by balance sheet line item:
Accounts receivable²												$	(16.4	)
Derivative assets—current													534.4
Derivative assets—noncurrent													258.9
Derivative liabilities—current																(622.3	)
Derivative liabilities—noncurrent																(353.0	)

Total Derivatives												$	776.9		$	(975.3	)

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.

Gain and (Loss) Tables

The tables below summarize derivative gains and losses segregated into the following categories:

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

The tables only include this information for derivatives and do not reflect the related gains or losses that arise from generation and generation-related assets, nonderivative accrual contracts, or NPNS contracts within our Generation and NewEnergy businesses, other than fair value hedges, for which we separately show the gain or loss on the hedged asset or liability. As a result, 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 2010 Annual Report on Form 10-K.

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The following tables present gains and losses on derivatives designated as cash flow hedges.

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:		2011			2010			Statement of Income (Loss) Line Item	2011			2010			2011			2010

		(In millions)
Hedges of forecasted sales:								Nonregulated revenues
	Power contracts	$	(32.4	)	$	(80.8	)		$	23.3		$	(1.0	)	$	56.2		$	(20.5	)
	Gas contracts		49.7			1.8				73.1			16.2			(51.2	)		(2.9	)
	Coal contracts		—			—				—			—			—			—
	Other commodity contracts¹		—			—				—			—			—			—
Foreign exchange contracts			—			—				—			—			—			—

Total gains (losses)		$	17.3		$	(79.0	)	Total included in nonregulated revenues	$	96.4		$	15.2		$	5.0		$	(23.4	)

Hedges of forecasted purchases:								Fuel and purchased energy expense
	Power contracts	$	(14.9	)	$	163.9			$	(133.3	)	$	(331.6	)	$	(6.8	)	$	(3.4	)
	Gas contracts		(67.2	)		(2.6	)			(10.6	)		45.1			(5.2	)		(13.1	)
	Coal contracts		(8.8	)		32.6				2.1			(15.3	)		1.1			2.3
	Other commodity contracts²		—			—				—			—			—			—
Foreign exchange contracts			—			—				—			—			—			—

Total (losses) gains		$	(90.9	)	$	193.9		Total included in fuel and purchased energy expense	$	(141.8	)	$	(301.8	)	$	(10.9	)	$	(14.2	)

Hedges of interest rates:								Interest expense
	Interest rate contracts		—			—				—			0.2			—			—

Total gains		$	—		$	—		Total included in interest expense	$	—		$	0.2		$	—		$	—

Grand total (losses) gains		$	(73.6	)	$	114.9			$	(45.4	)	$	(286.4	)	$	(5.9	)	$	(37.6	)

1 Other commodity sale contracts include oil and freight contracts.

2 Other commodity purchase contracts include freight and emission allowances.

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Cash Flow Hedges									Six Months Ended June 30,


		Gain (Loss) Recorded in AOCI							Gain (Loss) Reclassified from AOCI into Earnings						Ineffectiveness Gain (Loss) Recorded in Earnings
Contract type:		2011			2010			Statement of Income (Loss) Line Item	2011			2010			2011			2010

		(In millions)
Hedges of forecasted sales:								Nonregulated revenues
	Power contracts	$	(55.8	)	$	121.7			$	5.0		$	(60.2	)	$	57.4		$	1.3
	Gas contracts		60.8			(33.1	)			95.3			36.4			(49.0	)		(4.0	)
	Coal contracts		—			—				—			—			—			—
	Other commodity contracts¹		—			—				—			(0.7	)		—			—
Foreign exchange contracts			—			—				—			—			—			—

Total gains (losses)		$	5.0		$	88.6		Total included in nonregulated revenues	$	100.3		$	(24.5	)	$	8.4		$	(2.7	)

Hedges of forecasted purchases:								Fuel and purchased energy expense
	Power contracts	$	2.6		$	(291.6	)		$	(232.1	)	$	(534.7	)	$	(19.1	)	$	(12.7	)
	Gas contracts		(69.1	)		(76.2	)			(17.9	)		123.1			(12.9	)		(13.1	)
	Coal contracts		(3.4	)		21.8				9.4			(27.8	)		0.8			4.0
	Other commodity contracts²		—			(0.2	)			—			(0.3	)		—			0.2
Foreign exchange contracts			—			—				—			—			—			—

Total losses		$	(69.9	)	$	(346.2	)	Total included in fuel and purchased energy expense	$	(240.6	)	$	(439.7	)	$	(31.2	)	$	(21.6	)

Hedges of interest rates:								Interest expense
	Interest rate contracts		—			—				1.1			4.1			—			—

Total gains		$	—		$	—		Total included in interest expense	$	1.1		$	4.1		$	—		$	—

Grand total (losses) gains		$	(64.9	)	$	(257.6	)		$	(139.2	)	$	(460.1	)	$	(22.8	)	$	(24.3	)

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.

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

		Statement of Income (Loss) Line Item
Contract type:		Statement of Income (Loss) Line Item	2011		2010		2011			2010			2011		2010		2011			2010

			(In millions)
Commodity contracts:
	Gas contracts	Nonregulated revenues	$	0.8	$	—	$	—		$	—		$	0.8	$	—	$	—		$	—
Interest rate contracts		Interest expense		14.4		4.2		(16.0	)		(4.1	)		16.4		17.4		(17.5	)		(15.2	)

Total gains (losses)			$	15.2	$	4.2	$	(16.0	)	$	(4.1	)	$	17.2	$	17.4	$	(17.5	)	$	(15.2	)

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The following table presents gains and losses on mark-to-market derivatives.

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	2011		2010			2011			2010

			(In millions)
Commodity contracts:
	Power contracts	Nonregulated revenues	$	15.9	$	40.1		$	39.2		$	(24.8	)
	Gas contracts	Nonregulated revenues		8.5		5.0			19.7			30.7
	Coal contracts	Nonregulated revenues		7.9		7.6			(0.7	)		7.7
	Other commodity contracts¹	Nonregulated revenues		7.3		(3.8	)		(9.3	)		1.1
	Coal contracts	Fuel and purchased energy expense		—		—			—			—
Interest rate contracts		Nonregulated revenues		0.1		(0.6	)		(0.6	)		(1.7	)
Interest rate contracts		Interest expense		3.3		—			3.3			—
Foreign exchange contracts		Nonregulated revenues		5.3		(1.2	)		(6.7	)		(2.1	)

Total gains (losses)			$	48.3	$	47.1		$	44.9		$	10.9

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

Volume of Derivative Activity

The volume of our derivatives activity is directly related to the fundamental nature and scope of our business and the risks we manage. We own or control electric generating facilities, which exposes us to both power and fuel price risk; we serve electric and gas wholesale and retail customers within our NewEnergy business, which exposes us to electricity and natural gas price risk; and we provide risk management services and engage in trading activities, which can expose us to a variety of commodity price risks. 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. As such, we use derivatives in the following ways:

-: 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.
-: 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 also use 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.

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

-: 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.
-: The tables 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

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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.

-: 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. The disclosure of such could limit the effectiveness and profitability of our business activities.
-: The volume information for commodity derivatives represents the "delta equivalent" quantity of those contracts rather than the gross notional amount. 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. 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, 2011 and December 31, 2010 shown by contractual settlement year.

Quantities¹ Under Derivative Contracts									As of June 30, 2011


Contract Type (Unit)	2011		2012		2013		2014		2015		Thereafter		Total

	(In millions)
Power (MWH)		17.3		12.4		11.8		2.6		2.4		1.4		47.9
Gas (mmBTU)		123.4		134.2		47.3		64.4		29.8		0.9		400.0
Coal (Tons)		2.1		2.1		0.9		—		—		—		5.1
Oil (BBL)		0.2		0.2		0.1		—		—		—		0.5
Emission Allowances (Tons)		0.9		0.1		—		—		—		—		1.0
Renewable Energy Credits (Number of credits)		0.3		0.3		0.3		0.3		0.3		0.4		1.9
Interest Rate Contracts	$	97.8	$	884.3	$	568.2	$	185.0	$	1,150.0	$	315.0	$	3,200.3
Foreign Exchange Rate Contracts	$	16.8	$	17.5	$	16.7	$	16.8	$	15.5	$	—	$	83.3

Quantities¹ Under Derivative Contracts									As of December 31, 2010


Contract Type (Unit)	2011		2012		2013		2014		2015		Thereafter		Total

	(In millions)
Power (MWH)		21.2		—		3.8		4.2		2.3		0.2		31.7
Gas (mmBTU)		175.3		90.1		80.2		64.7		24.1		—		434.4
Coal (Tons)		4.4		2.5		0.1		—		—		—		7.0
Oil (BBL)		0.2		0.1		0.1		—		—		—		0.4
Emission Allowances (Tons)		1.5		—		—		—		—		—		1.5
Renewable Energy Credits (Number of credits)		0.4		0.3		0.3		0.3		0.3		0.7		2.3
Interest Rate Contracts	$	639.4	$	490.7	$	941.8	$	405.0	$	460.0	$	175.0	$	3,111.9
Foreign Exchange Rate Contracts	$	48.7	$	8.7	$	16.8	$	16.8	$	15.5	$	—	$	106.5

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.

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Credit-Risk Related Contingent Features

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

The following tables present information related to credit-risk related contingent features of our derivatives at June 30, 2011 and December 31, 2010.

Credit-Risk Related Contingent Feature							As of June 30, 2011


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)
$	3.1	$	(2.6	)	$	0.5	$	0.4	$	0.1

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


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

(In billions)
$	4.6	$	(3.7	)	$	0.9	$	0.7	$	0.1

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 $2.5 million and letters of credit of $412.4 million at June 30, 2011 and cash collateral posted of $0.6 million and letters of credit of $656.9 million at December 31, 2010.

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

Concentrations of Credit Risk

We discuss our concentrations of credit risk, including derivative-related positions, in Note 1 to our 2010 Annual Report on Form 10-K. As of June 30, 2011, we had a total exposure of 14% to one counterparty, a large power cooperative.

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Fair Value Measurements

Recurring Measurements

Our assets and liabilities measured at fair value on a recurring basis consist of the following (immaterial for BGE assets):

			As of June 30, 2011						As of December 31, 2010

			Assets			Liabilities			Assets			Liabilities

			(In millions)
Cash equivalents			$	316.6		$	—		$	1,545.4		$	—
Equity securities				44.2			—			43.7			—
Derivative instruments:
	Classified as derivative assets and liabilities:
		Current		324.3			(494.2	)		534.4			(622.3	)
		Noncurrent		257.5			(270.1	)		258.9			(353.0	)

		Total classified as derivative assets and liabilities		581.8			(764.3	)		793.3			(975.3	)
	Classified as accounts receivable¹			(72.7	)		—			(16.4	)		—

	Total derivative instruments			509.1			(764.3	)		776.9			(975.3	)

Total recurring fair value measurements			$	869.9		$	(764.3	)	$	2,366.0		$	(975.3	)

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

Cash equivalents represent money market funds included in "Cash and cash equivalents" in the Consolidated Balance Sheets. Equity securities primarily represent mutual fund investments included in "Other assets" in the Consolidated Balance Sheets. Derivative instruments represent unrealized amounts related to all derivatives. We classify exchange-listed derivatives as part of "Accounts Receivable" in our Consolidated Balance Sheets. We classify the remainder of our derivatives as "Derivative assets" or "Derivative liabilities" in our Consolidated Balance Sheets.

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, 2011 and December 31, 2010. We disaggregate our net derivative assets and liabilities by separating each individual derivative contract that is in-the-money from each contract that is out-of-the-money regardless of master netting agreements and collateral. 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. 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. Therefore, 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.

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At June 30, 2011		Level 1			Level 2			Level 3			Netting and Cash Collateral¹			Total Net Fair Value


		(In millions)
Cash equivalents		$	316.6		$	—		$	—		$	—		$	316.6
Equity securities			44.2			—			—			—			44.2
Derivative assets:
	Power contracts		—			4,718.2			873.5
	Gas contracts		68.9			3,568.9			451.0
	Coal contracts		—			209.1			0.6
	Other commodity contracts		50.7			58.6			196.6
	Interest rate contracts		35.8			40.2			—
	Foreign exchange contracts		—			13.7			—

	Total derivative assets		155.4			8,608.7			1,521.7			(9,776.7	)		509.1

Derivative liabilities:
	Power contracts		—			(5,004.4	)		(1,011.0	)
	Gas contracts		(66.5	)		(3,530.6	)		(351.5	)
	Coal contracts		—			(174.8	)		—
	Other commodity contracts		(48.7	)		(51.8	)		(199.3	)
	Interest rate contracts		(37.9	)		—			—
	Foreign exchange contracts		—			(8.2	)		—

Total derivative liabilities			(153.1	)		(8,769.8	)		(1,561.8	)		9,720.4			(764.3	)

	Net derivative position		2.3			(161.1	)		(40.1	)		(56.3	)		(255.2	)

Total		$	363.1		$	(161.1	)	$	(40.1	)	$	(56.3	)	$	105.6

1 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, 2011, we included $58.8 million of cash collateral held and $2.5 million of cash collateral posted (excluding margin posted on exchange traded derivatives) in netting amounts in the above table.

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At December 31, 2010		Level 1			Level 2			Level 3			Netting and Cash Collateral¹			Total Net Fair Value


		(In millions)
Cash equivalents		$	1,545.4		$	—		$	—		$	—		$	1,545.4
Equity securities			43.7			—			—			—			43.7
Derivative assets:
	Power contracts		—			7,509.6			453.3
	Gas contracts		63.9			5,113.3			115.2
	Coal contracts		—			355.6			7.4
	Other commodity contracts		6.6			54.8			—
	Interest rate contracts		33.1			37.0			—
	Foreign exchange contracts		—			11.0			—

	Total derivative assets		103.6			13,081.3			575.9			(12,983.9	)		776.9

Derivative liabilities:
	Power contracts		—			(7,758.2	)		(771.1	)
	Gas contracts		(72.7	)		(4,910.3	)		(5.1	)
	Coal contracts		—			(307.4	)		(0.9	)
	Other commodity contracts		(7.1	)		(54.5	)		—
	Interest rate contracts		(35.7	)		—			—
	Foreign exchange contracts		—			(8.4	)		—

Total derivative liabilities			(115.5	)		(13,038.8	)		(777.1	)		12,956.1			(975.3	)

	Net derivative position		(11.9	)		42.5			(201.2	)		(27.8	)		(198.4	)

Total		$	1,577.2		$	42.5		$	(201.2	)	$	(27.8	)	$	1,390.7

1 We present our derivative assets and liabilities in our Consolidated Balance Sheets on a net basis. We net derivative assets and liabilities, including cash collateral, when a legally enforceable master netting agreement exists between us and the counterparty to a derivative contract. At December 31, 2010, we included $28.4 million of cash collateral held and $0.6 million of cash collateral posted (excluding margin posted on exchange traded derivatives) in netting amounts in the above table.

We discuss our valuation techniques and inputs used to develop those measurements in greater detail in Note 13 of our 2010 Annual Report of Form 10-K. There have not been significant changes to our valuation techniques nor to their inputs during 2011.

During the quarter and six months ended June 30, 2011, there were no significant transfers of derivatives between Level 1 and Level 2 of the fair value hierarchy.

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During the quarters and six months ended June 30, 2011 and 2010, our Level 3 fair value measurements, predominantly power contracts, changed as follows:

		Quarter Ended June 30,						Six Months Ended June 30,

		2011			2010			2011			2010

		(In millions)
Balance at beginning of period		$	(172.8	)	$	(315.2	)	$	(201.2	)	$	(291.5	)
Realized and unrealized (losses) gains:
	Recorded in income		39.8			58.0			(20.5	)		(78.7	)
	Recorded in other comprehensive income		19.2			(2.8	)		29.5			73.6
Purchases			(3.6	)					(3.6	)
Sales			—						—
Issuances			(3.5	)					1.1
Settlements			—						—

	Net purchases, sales, issuances, and settlements¹		(7.1	)		7.4			(2.5	)		16.6
Transfers into Level 3²			34.1			93.0			145.7			208.0
Transfers out of Level 3²			46.7			(16.1	)		8.9			(103.7	)

Balance at end of period		$	(40.1	)	$	(175.7	)	$	(40.1	)	$	(175.7	)

Change in unrealized gains recorded in income relating to derivatives still held at end of period		$	23.0		$	82.9		$	(1.4	)	$	8.9

1 Effective January 1, 2011, we are required to present separately purchases, sales, issuances, and settlements.

2 For purposes of this reconciliation, we assumed transfers into and out of Level 3 occurred on the last day of the quarter. All transfers are predominantly the result of changes in the observability of the forward commodity price curves.

We have defined the categories of purchases, sales, issuances, and settlements to include the inflow or outflow of value as follows:

-: purchases—includes the acquisition of pre-existing derivative contracts,
-: sales—includes the sale or assignment of pre-existing derivative contracts,
-: issuances—includes the acquisition of derivative contracts at inception, and
-: settlements—includes the termination of existing derivative contracts prior to normal maturity or settlement.

During the quarter and six months ended June 30, 2011, we had purchases related to our acquisition of StarTex and our issuances related to premiums paid for option contracts.

We discuss the financial statement classification for realized and unrealized gains and losses related to cash-flow hedges for our various hedging relationships in Note 1 to our 2010 Annual Report on Form 10-K.

Fair Value of Financial Instruments

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

At June 30, 2011		Carrying Amount		Fair Value


		(In millions)
Investments and other assets—Constellation Energy		$	179.5	$	179.8
Fixed-rate long-term debt:
	Constellation Energy (including BGE)		3,843.0		4,187.5
	BGE		2,113.9		2,284.1
Variable-rate long-term debt:
	Constellation Energy (including BGE)		671.8		671.8
	BGE		—		—

We discuss our valuation techniques and assumptions for estimating the fair value of financial instruments in Note 13 of our 2010 Annual Report on Form 10-K. There have been no changes in these techniques and assumptions during the quarter and six months ended June 30, 2011.

Accounting Standards Issued

Fair Value Measurements

In May 2011, the Financial Accounting Standards Board (FASB) issued updated guidance on fair value measurements and disclosure requirements. The update aligns the accounting requirements for fair value measurements under generally accepted accounting principles in the United States and international financial reporting standards. The new requirements will be effective for us as of January 1, 2012. We do not expect the adoption of this update to have a material impact on our, or BGE's financial results; however, it will result in additional disclosures.

Comprehensive Income

In June 2011, the FASB issued updated requirements on the presentation of comprehensive income which eliminate the option to present other comprehensive income in the statement of changes in equity. The new requirements will be effective for us as of January 1, 2012. We do not expect the adoption of this amendment to have an impact on our, or BGE's financial results, other than the presentation of a separate statement of comprehensive income.

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Related Party Transactions

Constellation Energy

CENG

We have a unit contingent power purchase agreement (PPA) with CENG 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 through 2014. Beginning on January 1, 2015 and continuing to the end of the life of the respective plants, we will purchase 50.01% of the output of CENG's nuclear plants, and EDF will purchase 49.99% of that output.

In addition to the PPA, we have a power services agency agreement (PSA) and an administrative service agreement (ASA) with CENG. 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 expires in 2017 and under the agreement we provide certain administrative services to CENG including back office, human resources and information technology. The ASA includes both a consumption-based pricing structure as well as a fixed-price structure which are subject to change in future years based on the level of service needed. The fixed price fee for 2011 is approximately $48 million and will increase annually in line with inflation. The charges under this agreement are intended to represent the actual cost of the services provided to CENG by us.

The impact of transactions under these agreements is summarized below:

	Increase (Decrease) in Earnings																At December 31, 2010 Accounts Receivable/ (Accounts Payable)

	Increase (Decrease) in Earnings													At June 30, 2011 Accounts Receivable/ (Accounts Payable)
	Quarter Ended June 30,						Six Months Ended June 30,
	Quarter Ended June 30,						Six Months Ended June 30,						Income Statement Classification
Agreement	2011			2010			2011			2010			Income Statement Classification

PPA	$	(209.3	)	$	(222.1	)	$	(404.1	)	$	(420.6	)	Fuel and purchased energy expenses	$	(46.5	)	$	(47.6	)
PSA		4.0			4.0			8.0			8.0		Nonregulated revenues		—			—
ASA		12.0			16.5			24.0			33.0		Operating expenses		4.0			5.5

In May 2011, CENG issued an unsecured revolving promissory note to borrow up to an aggregate principal amount of $62.5 million from a subsidiary of Constellation Energy. CENG also issued a promissory note to EDF on substantially identical terms, such that any request for borrowings by CENG must be submitted 50% to Constellation Energy and 50% to EDF.

Interest accrues on the amounts borrowed on a daily basis at a fixed rate per year equal to the rate at which deposits of United States dollars are offered by prime banks in the London interbank market, plus 250 basis points. Amounts are due at the earlier of October 31, 2012 or the date upon which the note is accelerated in accordance with the terms of the agreement.

As of June 30, 2011, CENG has borrowed $15.0 million from Constellation Energy.

In June 2011, CENG executed a settlement agreement with the DOE under which Constellation Energy will receive payment of $35.5 million related to costs incurred through October 31, 2008 to store spent nuclear fuel at the Calvert Cliffs nuclear power plant. As a result, we recorded $35.5 million as an amount due from CENG in "Accounts receivable" on our Consolidated Balance Sheets. We discuss this settlement in more detail on page 12.

BGE—Income Statement

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

Our NewEnergy business will supply a portion of BGE's market-based standard offer service obligation to electric customers through September 30, 2013.

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