Edgar Filing: CONSTELLATION ENERGY GROUP INC

QuickLinks -- Click here to rapidly navigate through this document

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, 2008


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

MARYLAND
(State of Incorporation of both registrants)

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

410-470-2800

(Registrants' telephone number, including area code)

NOT APPLICABLE

(Former name, former address and former fiscal year, if changed since last report)

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

Indicate by check mark whether 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 178,331,875 shares outstanding
of Constellation Energy Group, Inc. on July 31, 2008.

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

			Page

Part I—Financial Information
	Item 1—Financial Statements
		Constellation Energy Group, Inc. and Subsidiaries
		Consolidated Statements of Income	3
		Consolidated Statements of Comprehensive Income	3
		Consolidated Balance Sheets	4
		Consolidated Statements of Cash Flows	6
		Baltimore Gas and Electric Company and Subsidiaries
		Consolidated Statements of Income	7
		Consolidated Balance Sheets	8
		Consolidated Statements of Cash Flows	10
		Notes to Consolidated Financial Statements	11
	Item 2—Management's Discussion and Analysis of Financial Condition and Results of Operations
		Introduction and Overview	26
		Strategy	26
		Business Environment	27
		Events of 2008	27
		Results of Operations	29
		Financial Condition	43
		Capital Resources	45
	Item 3—Quantitative and Qualitative Disclosures About Market Risk		50
	Items 4 and 4(T)—Controls and Procedures		50
Part II—Other Information
	Item 1—Legal Proceedings		51
	Item 1A—Risk Factors		51
	Item 2—Issuer Purchases of Equity Securities		52
	Item 5—Other Information		53
	Item 6—Exhibits		54
	Signature		55

PART 1—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,

		2008			2007			2008			2007

		(In millions, except per share amounts)
Revenues
	Nonregulated revenues	$	4,445.3		$	4,172.9		$	8,157.2		$	8,366.7
	Regulated electric revenues		448.7			544.3			1,158.0			1,059.1
	Regulated gas revenues		183.1			159.1			574.1			561.6

	Total revenues		5,077.1			4,876.3			9,889.3			9,987.4
Expenses
	Fuel and purchased energy expenses		3,880.4			3,885.2			7,623.5			7,901.9
	Operating expenses		711.5			580.4			1,301.6			1,149.1
	Impairment losses and other costs		—			20.2			—			20.2
	Workforce reduction costs		—			2.3			—			2.3
	Depreciation, depletion, and amortization		141.9			142.8			290.2			275.2
	Accretion of asset retirement obligations		17.0			18.2			33.6			35.9
	Taxes other than income taxes		71.1			72.8			145.9			146.0

	Total expenses		4,821.9			4,721.9			9,394.8			9,530.6
Gains on Sales of Upstream Gas Assets			76.5			—			91.5			—

Income from Operations			331.7			154.4			586.0			456.8
Gains on Sale of CEP LLC Equity			—			12.9			—			12.9
Other Income, primarily interest income			15.1			45.2			57.4			87.6
Fixed Charges
	Interest expense		73.5			71.1			152.3			151.4
	Interest capitalized and allowance for borrowed funds used during construction		(8.6	)		(4.5	)		(15.7	)		(8.4	)
	BGE preference stock dividends		3.3			3.3			6.6			6.6

	Total fixed charges		68.2			69.9			143.2			149.6

Income from Continuing Operations Before Income Taxes			278.6			142.6			500.2			407.7
Income Tax Expense			107.1			26.3			183.0			94.1

Income from Continuing Operations			171.5			116.3			317.2			313.6
	Loss from discontinued operations, net of income taxes of $0.8		—			—			—			(1.6	)

Net Income		$	171.5		$	116.3		$	317.2		$	312.0

Earnings Applicable to Common Stock		$	171.5		$	116.3		$	317.2		$	312.0

Average Shares of Common Stock Outstanding—Basic			178.4			180.3			178.3			180.5
Average Shares of Common Stock Outstanding—Diluted			180.2			182.7			180.2			182.8
Earnings Per Common Share from Continuing Operations—Basic		$	0.96		$	0.65		$	1.78		$	1.74
	Loss from discontinued operations		—			—			—			(0.01	)

Earnings Per Common Share—Basic		$	0.96		$	0.65		$	1.78		$	1.73

Earnings Per Common Share from Continuing Operations—Diluted		$	0.95		$	0.64		$	1.76		$	1.72
	Loss from discontinued operations		—			—			—			(0.01	)

Earnings Per Common Share—Diluted		$	0.95		$	0.64		$	1.76		$	1.71

Dividends Declared Per Common Share		$	0.4775		$	0.435		$	0.955		$	0.87

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)

Constellation Energy Group, Inc. and Subsidiaries

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

				2008			2007			2008			2007

				(In millions)
Net Income				$	171.5		$	116.3		$	317.2		$	312.0
	Other comprehensive income (loss) (OCI)
		Hedging instruments:
			Reclassification of net (gain) loss on hedging instruments from OCI to net income, net of taxes		(99.0	)		158.9			78.0			558.3
			Net unrealized gain (loss) on hedging instruments, net of taxes		511.8			(448.7	)		873.4			(138.4	)
		Available-for-sale securities:
			Reclassification of net loss (gain) on sales of securities from OCI to net income, net of taxes		1.9			(1.9	)		1.6			(2.8	)
			Net unrealized gain (loss) on securities, net of taxes		16.4			33.2			(28.7	)		13.7
		Defined benefit obligations:
			Amortization of net actuarial loss, prior service cost, and transition obligation included in net periodic benefit cost, net of taxes		5.4			6.2			10.5			12.5
		Net unrealized gain (loss) on foreign currency, net of taxes			2.1			2.8			(0.4	)		3.1

Comprehensive Income (Loss)				$	610.1		$	(133.2	)	$	1,251.6		$	758.4

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

CONSOLIDATED BALANCE SHEETS

Constellation Energy Group, Inc. and Subsidiaries

			*June 30,* 2008*			December 31, 2007


			(In millions)
Assets
	Current Assets
		Cash and cash equivalents	$	1,230.7		$	1,095.9
		Accounts receivable (net of allowance for uncollectibles of $154.8 and $44.9, respectively)		5,356.1			4,289.5
		Fuel stocks		931.3			591.3
		Materials and supplies		213.4			207.5
		Derivative assets		3,714.7			760.6
		Unamortized energy contract assets		86.1			32.0
		Deferred income taxes		—			300.7
		Other		704.3			408.1

		Total current assets		12,236.6			7,685.6

Investments and Other Noncurrent Assets
		Nuclear decommissioning trust funds		1,315.0			1,330.8
		Other investments		507.5			542.2
		Regulatory assets (net)		532.4			576.2
		Goodwill		266.4			261.3
		Derivative assets		3,000.2			1,030.2
		Unamortized energy contract assets		170.8			178.3
		Other		386.0			370.6

		Total investments and other noncurrent assets		6,178.3			4,289.6

Property, Plant and Equipment
		Property, plant and equipment		14,993.4			14,138.2
		Nuclear fuel (net of amortization)		367.2			374.3
		Accumulated depreciation		(4,923.6	)		(4,745.4	)

		Net property, plant and equipment		10,437.0			9,767.1

	Total Assets		$	28,851.9		$	21,742.3

* Unaudited

See Notes to Consolidated Financial Statements.

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

CONSOLIDATED BALANCE SHEETS

Constellation Energy Group, Inc. and Subsidiaries

			*June 30,* 2008*			December 31, 2007


			(In millions)
Liabilities and Equity
	Current Liabilities
		Short-term borrowings	$	145.7		$	14.0
		Current portion of long-term debt		144.4			380.6
		Accounts payable and accrued liabilities		3,638.4			2,630.1
		Customer deposits and collateral		492.1			146.6
		Derivative liabilities		3,349.6			1,134.3
		Unamortized energy contract liabilities		389.7			392.2
		Deferred income taxes		546.9			—
		Accrued expenses and other		805.2			956.0

		Total current liabilities		9,512.0			5,653.8

	Deferred Credits and Other Noncurrent Liabilities
		Deferred income taxes		1,349.5			1,588.5
		Asset retirement obligations		951.5			917.6
		Derivative liabilities		2,566.2			1,118.9
		Unamortized energy contract liabilities		1,090.2			1,218.6
		Defined benefit obligations		774.6			828.6
		Deferred investment tax credits		47.2			50.5
		Other		164.6			155.9

		Total deferred credits and other noncurrent liabilities		6,943.8			5,878.6

	Long-term Debt, net of current portion			5,734.9			4,660.5
	Minority Interests			20.1			19.2
	BGE Preference Stock Not Subject to Mandatory Redemption			190.0			190.0
	Common Shareholders' Equity
		Common stock		2,571.2			2,513.3
		Retained earnings		4,038.1			3,919.5
		Accumulated other comprehensive loss		(158.2	)		(1,092.6	)

		Total common shareholders' equity		6,451.1			5,340.2

	Commitments, Guarantees, and Contingencies (see Notes)
	Total Liabilities and Equity		$	28,851.9		$	21,742.3

* Unaudited

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

CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)

Constellation Energy Group, Inc. and Subsidiaries

Six Months Ended June 30,				2008			2007


				(In millions)
Cash Flows From Operating Activities
	Net income			$	317.2		$	312.0
	Adjustments to reconcile to net cash provided by operating activities
		Depreciation, depletion, and amortization			240.5			239.5
		Accretion of asset retirement obligations			33.6			35.9
		Deferred income taxes			39.2			60.2
		Investment tax credit adjustments			(3.2	)		(3.4	)
		Deferred fuel costs			19.7			(260.5	)
		Defined benefit obligation expense			55.5			73.1
		Defined benefit obligation payments			(100.3	)		(146.5	)
		Workforce reduction costs			—			2.3
		Impairment losses and other costs			—			20.2
		Gains on sale of CEP LLC equity			—			(12.9	)
		Gains on sale of assets			(99.2	)		—
		Gains on termination of contracts			(68.9	)		—
		Accrual of Maryland settlement agreement credit			188.2			—
		Equity in earnings of affiliates less than dividends received			7.4			33.4
		Derivative power sales contracts classified as financing activities under SFAS No. 149			0.5			(3.8	)
		Changes in
			Accounts receivable		(949.7	)		10.8
			Derivative assets and liabilities		(700.6	)		17.2
			Materials, supplies, and fuel stocks		(235.5	)		72.7
			Other current assets		(187.0	)		11.4
			Accounts payable and accrued liabilities		1,051.7			133.3
			Other current liabilities		905.0			(179.3	)
			Other		19.3			(5.5	)

	Net cash provided by operating activities				533.4			410.1

Cash Flows From Investing Activities
	Investments in property, plant and equipment				(869.5	)		(564.1	)
	Acquisitions, net of cash acquired				(312.4	)		(250.6	)
	Investments in nuclear decommissioning trust fund securities				(282.7	)		(352.7	)
	Proceeds from nuclear decommissioning trust fund securities				264.0			343.9
	Proceeds from sales of property, plant and equipment				217.0			4.7
	Contract and portfolio acquisitions				—			(474.2	)
	Increase in restricted funds				(196.9	)		(8.4	)
	Other				12.9			7.8

	Net cash used in investing activities				(1,167.6	)		(1,293.6	)

Cash Flows From Financing Activities
	Net issuance of short-term borrowings				103.7			—
	Proceeds from issuance of
		Common stock			8.3			39.2
		Long-term debt			1,100.0			643.2
	Repayment of long-term debt				(265.1	)		(731.7	)
	Debt issuance costs				(15.6	)		—
	Common stock dividends paid				(165.0	)		(147.6	)
	Reacquisition of common stock				—			(114.4	)
	Proceeds from contract and portfolio acquisitions				—			847.8
	Derivative power sales contracts classified as financing activities under SFAS No. 149				(0.5	)		3.8
	Other				3.2			22.1

	Net cash provided by financing activities				769.0			562.4

Net Increase (Decrease) in Cash and Cash Equivalents					134.8			(321.1	)
Cash and Cash Equivalents at Beginning of Period					1,095.9			2,289.1

Cash and Cash Equivalents at End of Period				$	1,230.7		$	1,968.0

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

CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED)

Baltimore Gas and Electric Company and Subsidiaries

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

			2008			2007			2008			2007

			(In millions)
Revenues
	Electric revenues		$	448.7		$	544.3		$	1,158.1		$	1,059.1
	Gas revenues			188.1			162.8			584.5			570.1

	Total revenues			636.8			707.1			1,742.6			1,629.2
Expenses
	Operating expenses
		Electricity purchased for resale		404.3			320.9			859.6			595.1
		Gas purchased for resale		127.7			102.9			397.7			387.0
		Operations and maintenance		136.8			131.3			270.4			254.4
	Depreciation and amortization			59.0			58.5			121.7			117.4
	Taxes other than income taxes			40.1			43.0			86.6			88.8

	Total expenses			767.9			656.6			1,736.0			1,442.7

(Loss) Income from Operations				(131.1	)		50.5			6.6			186.5
Other Income				6.4			5.4			14.4			10.0
Fixed Charges
	Interest expense			32.0			29.1			67.0			57.1
	Allowance for borrowed funds used during construction			(1.1	)		(0.7	)		(2.1	)		(1.1	)

	Total fixed charges			30.9			28.4			64.9			56.0

(Loss) Income Before Income Taxes				(155.6	)		27.5			(43.9	)		140.5
Income Taxes				(51.5	)		10.6			(16.1	)		54.3

Net (Loss) Income				(104.1	)		16.9			(27.8	)		86.2
Preference Stock Dividends				3.3			3.3			6.6			6.6

(Loss) Earnings Applicable to Common Stock			$	(107.4	)	$	13.6		$	(34.4	)	$	79.6

See Notes to Consolidated Financial Statements.

CONSOLIDATED BALANCE SHEETS

Baltimore Gas and Electric Company and Subsidiaries

				*June 30,* 2008*			December 31, 2007


				(In millions)
Assets
	Current Assets
		Cash and cash equivalents		$	14.9		$	17.6
		Accounts receivable (net of allowance for uncollectibles of $23.1 and $20.3, respectively)			309.8			316.7
		Accounts receivable, unbilled (net of allowance for uncollectibles of $0.8 and $0.8, respectively)			179.7			209.5
		Investment in cash pool, affiliated company			181.1			78.4
		Accounts receivable, affiliated companies			7.8			4.2
		Fuel stocks			96.1			98.8
		Materials and supplies			40.4			42.7
		Prepaid taxes other than income taxes			2.3			49.9
		Regulatory assets (net)			—			74.9
		Restricted cash			246.8			39.2
		Income taxes refundable			107.9			—
		Other			1.6			7.4

		Total current assets			1,188.4			939.3

	Investments and Other Assets
		Regulatory assets (net)			532.4			576.2
		Receivable, affiliated company			174.8			149.2
		Other			127.7			148.1

		Total investments and other assets			834.9			873.5

	Utility Plant
		Plant in service
			Electric		4,365.2			4,244.4
			Gas		1,202.0			1,181.7
			Common		457.2			456.1

			Total plant in service		6,024.4			5,882.2
		Accumulated depreciation			(2,135.9	)		(2,080.8	)

		Net plant in service			3,888.5			3,801.4
		Construction work in progress			214.7			166.4
		Plant held for future use			2.4			2.4

		Net utility plant			4,105.6			3,970.2

	Total Assets			$	6,128.9		$	5,783.0

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

CONSOLIDATED BALANCE SHEETS

Baltimore Gas and Electric Company and Subsidiaries

			*June 30,* 2008*			December 31, 2007


			(In millions)
Liabilities and Equity
	Current Liabilities
		Current portion of long-term debt	$	142.2		$	375.0
		Accounts payable and accrued liabilities		251.1			182.4
		Accounts payable and accrued liabilities, affiliated companies		300.8			164.5
		Customer deposits and collateral		185.9			70.5
		Current portion of deferred income taxes		43.3			44.1
		Accrued taxes		17.3			34.4
		Regulatory liabilities (net)		114.2			—
		Accrued expenses and other		75.7			96.3

		Total current liabilities		1,130.5			967.2

	Deferred Credits and Other Liabilities
		Deferred income taxes		810.2			785.6
		Payable, affiliated company		246.1			243.7
		Deferred investment tax credits		11.2			11.9
		Other		22.8			33.6

		Total deferred credits and other liabilities		1,090.3			1,074.8

	Long-term Debt
		Rate stabilization bonds		589.9			623.2
		First refunding mortgage bonds		—			119.7
		Other long-term debt		1,508.0			1,214.5
		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
		Long-term debt of nonregulated businesses		25.0			25.0
		Unamortized discount and premium		(2.4	)		(2.6	)
		Current portion of long-term debt		(142.2	)		(375.0	)

		Total long-term debt		2,236.0			1,862.5

	Minority Interest			16.6			16.8
	Preference Stock Not Subject to Mandatory Redemption			190.0			190.0
	Common Shareholder's Equity
		Common stock		912.2			912.2
		Retained earnings		552.7			758.8
		Accumulated other comprehensive income		0.6			0.7

		Total common shareholder's equity		1,465.5			1,671.7

	Commitments, Guarantees, and Contingencies (see Notes)
	Total Liabilities and Equity		$	6,128.9		$	5,783.0

* Unaudited
See Notes to Consolidated Financial Statements.

CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)

Baltimore Gas and Electric Company and Subsidiaries

Six Months Ended June 30,				2008			2007


				(In millions)
Cash Flows From Operating Activities
	Net (loss) income			$	(27.8	)	$	86.2
	Adjustments to reconcile to net cash provided by (used in) operating activities
		Depreciation and amortization			128.6			123.7
		Deferred income taxes			11.3			87.3
		Investment tax credit adjustments			(0.7	)		(0.8	)
		Deferred fuel costs			19.7			(260.5	)
		Defined benefit plan expenses			18.7			20.3
		Allowance for equity funds used during construction			(4.0	)		(2.1	)
		Accrual of Maryland settlement agreement credit			188.2			—
		Changes in
			Accounts receivable		36.7			(65.3	)
			Accounts receivable, affiliated companies		(3.6	)		0.3
			Materials, supplies, and fuel stocks		5.0			27.9
			Other current assets		(54.4	)		64.1
			Accounts payable and accrued liabilities		68.7			(27.9	)
			Accounts payable and accrued liabilities, affiliated companies		50.7			(8.5	)
			Other current liabilities		88.9			(29.5	)
			Long-term receivables and payables, affiliated companies		(42.0	)		(37.8	)
			Other		(15.1	)		(1.6	)

	Net cash provided by (used in) operating activities				468.9			(24.2	)

Cash Flows From Investing Activities
	Utility construction expenditures (excluding equity portion of allowance for funds used during construction)				(219.6	)		(175.5	)
	Change in cash pool at parent				(102.7	)		331.4
	Sales of investments and other assets				12.9			—
	Increase in restricted funds				(207.7	)		(3.1	)

	Net cash (used in) provided by investing activities				(517.1	)		152.8

Cash Flows From Financing Activities
	Proceeds from issuance of long-term debt				400.0			623.2
	Repayment of long-term debt				(259.5	)		(121.4	)
	Debt issuance costs				(2.4	)		—
	Preference stock dividends paid				(6.6	)		(6.6	)
	Distribution to parent				(86.0	)		—

	Net cash provided by financing activities				45.5			495.2

Net (Decrease) Increase in Cash and Cash Equivalents					(2.7	)		623.8
Cash and Cash Equivalents at Beginning of Period					17.6			10.9

Cash and Cash Equivalents at End of Period				$	14.9		$	634.7

See Notes to Consolidated Financial Statements.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

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

Basis of Presentation

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

Reclassifications

We have reclassified certain prior-period amounts:

•: Revenues for the quarter and six months ended June 30, 2007 were increased to reflect the reclassification of $56.1 million and $111.7 million, respectively, from fuel and purchased energy expenses to conform with the current presentation.
•: Derivative assets and liabilities as of December 31, 2007 reflect the adoption of Staff Position FIN 39-1, Amendment of FASB Interpretation No. 39, on January 1, 2008. We discuss the adoption of Staff Position FIN 39-1 in more detail on page 22.
•: We have separately presented "Restricted cash" that was previously reported within "Other current assets" on BGE's Consolidated Balance Sheet.

Variable Interest Entities

We have a significant interest in the following variable interest entities (VIE) for which we are not the primary beneficiary:

VIE	Nature of Involvement	Date of Involvement


Power projects	Equity investment and guarantees	Prior to 2003
Power contract monetization entities	Power sale agreements, loans, and guarantees	March 2005
Retail power supply	Power sale agreement	September 2006

We discuss the nature of our involvement with the power contract monetization VIEs in detail in Note 4 to our 2007 Annual Report on Form 10-K.

The following is summary information available as of June 30, 2008 about the VIEs in which we have a significant interest, but are not the primary beneficiary:

	Power Contract Monetization VIEs		All Other VIEs		Total


	(In millions)
Total assets	$	676.2	$	388.2	$	1,064.4
Total liabilities		532.9		215.1		748.0
Our ownership interest		—		46.8		46.8
Other ownership interests		143.3		126.3		269.6
Our maximum exposure to loss		51.6		210.9		262.5

The maximum exposure to loss represents the loss that we would incur in the unlikely event that our interests in all of these entities were to become worthless and we were required to fund the full amount of all guarantees associated with these entities.

Our maximum exposure to loss as of June 30, 2008 consists of the following:

•: outstanding receivables, loans and letters of credit totaling $213.7 million,
•: the carrying amount of our investments totaling $46.8 million, and
•: debt and performance guarantees totaling $2.0 million.

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

Workforce Reduction Costs

We incurred costs related to workforce reduction efforts initiated in 2006 and 2007. We discuss these costs in more detail in Note 2 of our 2007 Annual Report on Form 10-K.

We substantially completed both of these workforce reduction efforts in the first half of 2008.

Earnings Per Share

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

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

	Quarter Ended June 30,				Six Months Ended June 30,

	2008		2007		2008		2007

	(In millions)
Non-dilutive stock options		1.3		—		0.9		—
Dilutive common stock equivalent shares		1.8		2.4		1.9		2.3

Accretion of Asset Retirement Obligations

We discuss our asset retirement obligations in more detail in Note 1 of our 2007 Annual Report on Form 10-K. The change in our "Asset retirement obligations" liability during 2008 was as follows:

	(In millions)


Liability at January 1, 2008	$	917.6
Accretion expense		33.6
Liabilities incurred		0.8
Liabilities settled		(0.3	)
Revisions to cash flows		—
Other		(0.2	)

Liability at June 30, 2008	$	951.5

Acquisitions

Hillabee Energy Center

On February 14, 2008, we acquired the Hillabee Energy Center, a partially completed 774MW gas-fired combined cycle power generation facility located in Alabama for $156.9 million (including direct costs), which we accounted for as an asset acquisition. We allocated the purchase price primarily to the equipment with lesser amounts allocated to land and contracts acquired. We plan to complete the construction of this facility and expect it to be ready for commercial operation in early 2010.

West Valley Power Plant

On June 1, 2008, we acquired the West Valley Power Plant, a 200MW gas-fired peaking plant located in Utah for approximately $88.6 million (including direct costs). We accounted for this transaction as an asset acquisition and have included this plant's results of operations in our Generation operations of our merchant energy business segment since the date of acquisition. We allocated the purchase price primarily to the equipment with lesser amounts allocated to land and spare parts inventory.

Nufcor International Limited

On June 26, 2008, we acquired Nufcor International Limited (Nufcor). We include Nufcor as part of our Global Commodities operation in our merchant energy business segment and have included its results of operations in our consolidated financial statements since the date of acquisition. Nufcor is a uranium market participant that provides marketing services to uranium producers, utilities and an investment fund in the North American and European markets.

We acquired 100% ownership of Nufcor for $105.9 million, including direct costs, of which $104.9 million was paid in cash at closing. As part of the purchase, we acquired $37.3 million in cash.

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

At June 26, 2008


	(In millions)
Cash	$	37.3
Fuel stocks		126.8
Other current assets		13.6

Total current assets		177.7
Goodwill¹		5.1
Other assets		30.5

Total assets acquired		213.3

Short-term borrowings		(28.0	)
Unamortized energy contract liabilities		(15.8	)
Other current liabilities		(30.6	)

Total current liabilities		(74.4	)
Unamortized energy contract liabilities		(33.0	)

Total liabilities		(107.4	)

Net assets acquired	$	105.9

1 Not deductible for tax purposes.

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

The pro-forma impact of the Nufcor acquisition would not have been material to our results of operations for the quarter and six months ended June 30, 2008 and 2007.

Asset Sales

Working Interests in Gas Producing Fields

On June 30, 2008, our merchant energy business sold a portion of its working interests in proved natural gas reserves and unproved properties in Arkansas for total proceeds of $145.4 million, which is subject to certain purchase price adjustments. Our merchant energy business recognized a $76.5 million pre-tax gain on this sale. The gain is included in "Gains on Sales of Upstream Gas Assets" line in our Consolidated Statements of Income.

In addition, on March 31, 2008, we sold our working interest in oil and natural gas producing properties to Constellation Energy Partners LLC (CEP), a related party, and recognized a net gain of $14.3 million. We discuss this transaction in more detail on page 25.

Dry Bulk Vessel

On July 10, 2008, a shipping joint venture, in which our merchant energy business has a 50% ownership interest, sold one of the six freight ships it owns. This sale produced an approximate $29 million pre-tax gain for us. We will record the gain in the third quarter of 2008.

Emissions Allowances

On July 11, 2008, the United States Court of Appeals for the D. C. Circuit (the "Court") issued an opinion vacating the Clean Air Interstate Rule (CAIR), subject to a 45 day delay during which parties may petition for rehearing. If no petitions are filed during this period, the Court's decision will become effective at that time. CAIR required states in the eastern United States to reduce emissions of sulfur dioxide (SO₂) and established cap-and-trade programs for nitrogen oxides (NO_x) emissions.

Following the Court's decision, the market prices for SO₂ and annual NO_x allowances decreased significantly. For example, as of July 31, 2008, the market price for current-year SO₂ allowances decreased approximately 60% since June 30, 2008.

We account for our allowance inventory at the lower of cost or market, which includes consideration of our expected requirements for future generation of electricity. The weighted-average cost of our current-year SO₂ allowance inventory in excess of amounts needed to satisfy these requirements was greater than market at June 30. After giving consideration to the Court's decision and the subsequent decline in the market price of these allowances, we recorded a write-down of our SO₂ allowance inventory totaling $22.1 million pre-tax to reflect the June 30, 2008 market price. We did not record a write-down of our inventory of annual NO_x allowances as of June 30, 2008 because the market price of these allowances exceeded our weighted-average cost at that date.

As a result of the substantial decrease in market prices after the Court's July 11, 2008 decision, we may be required to record an additional write-down of our excess SO₂ and annual NO_x allowance inventories during the third quarter of 2008 to reflect the lower market price levels following the Court's decision. Also, certain derivative contracts for the forward sale of annual NO_x allowances may be impaired if the Court decision is implemented in its current form. Based on market prices as of July 31, 2008, we estimate we would have to record a combined pre-tax loss for our excess SO₂ allowance inventory, annual NO_x allowance inventory, and certain derivative contracts for the forward sale of annual NOx allowances totaling approximately $85 million pre-tax. However, this additional loss would be offset by mark-to-market gains totaling approximately $38 million pre-tax on derivative contracts to forward sell SO₂ allowances which we currently expect will not be affected by the Court's decision. Taken together, these factors would result in a net pre-tax loss in the third quarter of 2008 totaling approximately $47 million pre-tax based on market prices as of July 31, 2008.

The ultimate amount of any additional losses and any mark-to-market gains or losses to be recognized in the third quarter of 2008 will be determined based on actual market prices as of September 30, 2008, which could vary materially from current market price levels. At this time, we cannot predict if there will be any further judicial, regulatory or legislative developments that would result in some or all of the provisions of CAIR being preserved. If any of these developments were to occur prior to September 30, 2008, the market prices of SO₂ and annual NO_x allowances may recover and a further write-down of our inventory of allowances and contracts for the forward sale of annual NO_x allowances may be reduced or avoided. As a result, these developments could have a material impact on our financial results.

Information by Operating Segment

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

•

Our merchant energy business is nonregulated and includes:

—: full requirements load-serving sales of energy and capacity to utilities, cooperatives, and commercial, industrial, and governmental customers,
—: structured transactions and risk management services for various customers (including hedging of output from generating facilities and fuel costs),
—: deployment of risk capital through portfolio management and trading activities,

—: gas retail energy products and services to commercial, industrial, and governmental customers,
—: fossil, nuclear, and interests in hydroelectric generating facilities and qualifying facilities, and power projects in the United States,
—: upstream (exploration and production) and downstream (transportation and storage) natural gas operations,
—: coal sourcing and logistics services and uranium marketing services for the variable or fixed supply needs of global customers, and
—: generation operations and maintenance.

•: Our regulated electric business purchases, transmits, distributes, and sells electricity in Central Maryland.
•: Our regulated gas business purchases, transports, and sells natural gas in Central Maryland.

Our remaining nonregulated businesses:

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

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

	Reportable Segments

	Merchant Energy Business			Regulated Electric Business			Regulated Gas Business			Other Nonregulated Businesses			Eliminations			Consolidated

	(In millions)
For the three months ended June 30,
2008
Unaffiliated revenues	$	4,379.3		$	448.7		$	183.1		$	66.0		$	—		$	5,077.1
Intersegment revenues		221.8			—			5.0			0.1			(226.9	)		—

Total revenues		4,601.1			448.7			188.1			66.1			(226.9	)		5,077.1
Net income (loss)		279.7			(104.2	)		(3.1	)		(0.9	)		—			171.5
2007
Unaffiliated revenues	$	4,128.1		$	544.3		$	159.1		$	44.8		$	—		$	4,876.3
Intersegment revenues		267.7			—			3.7			—			(271.4	)		—

Total revenues		4,395.8			544.3			162.8			44.8			(271.4	)		4,876.3
Net income (loss)		102.2			19.4			(5.7	)		0.4			—			116.3
For the six months ended June 30,
2008
Unaffiliated revenues	$	8,032.1		$	1,158.0		$	574.1		$	125.1		$	—		$	9,889.3
Intersegment revenues		516.0			0.1			10.4			0.2			(526.7	)		—

Total revenues		8,548.1			1,158.1			584.5			125.3			(526.7	)		9,889.3
Net income (loss)		351.9			(70.5	)		36.3			(0.5	)		—			317.2
2007
Unaffiliated revenues	$	8,247.2		$	1,059.1		$	561.6		$	119.5		$	—		$	9,987.4
Intersegment revenues		590.6			—			8.5			—			(599.1	)		—

Total revenues		8,837.8			1,059.1			570.1			119.5			(599.1	)		9,987.4
Loss from discontinued operations		(1.6	)		—			—			—			—			(1.6	)
Net income		222.2			51.6			28.0			10.2			—			312.0

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

Total assets increased approximately $7.1 billion during 2008. Most of the increase relates to our Merchant Energy Business segment assets and is primarily due to the increase in derivative assets. We discuss this increase in more detail on page 23 of the Notes to the Consolidated Financial Statements.

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,

	2008			2007			2008			2007

	(In millions)
Components of net periodic pension benefit cost
Service cost	$	12.8		$	12.2		$	27.8		$	24.7
Interest cost		22.7			22.9			50.2			47.3
Expected return on plan assets		(25.0	)		(24.7	)		(55.9	)		(51.3	)
Recognized net actuarial loss		6.5			8.4			12.4			16.4
Amortization of prior service cost		2.6			1.3			5.5			2.6
Amount capitalized as construction cost		(2.1	)		(2.9	)		(4.8	)		(5.9	)

Net periodic pension benefit cost¹	$	17.5		$	17.2		$	35.2		$	33.8

1 BGE's portion of our net periodic pension benefit cost, excluding amounts capitalized, was $4.2 million for the quarter ended June 30, 2008 and $5.1 million for the quarter ended June 30, 2007. BGE's portion of our net periodic pension benefit cost, excluding amounts capitalized, was $8.7 million for the six months ended June 30, 2008 and $10.3 million for the six months ended June 30, 2007.

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

	Quarter Ended June 30,						Six Months Ended June 30,

	2008			2007			2008			2007

	(In millions)
Components of net periodic postretirement benefit cost
Service cost	$	1.9		$	1.8		$	3.6		$	3.5
Interest cost		7.2			7.1			13.9			13.3
Amortization of transition obligation		0.7			0.7			1.2			1.2
Recognized net actuarial loss		0.1			0.8			1.1			2.2
Amortization of prior service cost		(1.1	)		(1.1	)		(2.0	)		(1.9	)
Amount capitalized as construction cost		(1.9	)		(2.2	)		(4.0	)		(4.3	)

Net periodic postretirement benefit cost¹	$	6.9		$	7.1		$	13.8		$	14.0

1 BGE's portion of our net periodic postretirement benefit cost, excluding amounts capitalized, was $4.0 million for the quarter ended June 30, 2008 and $4.2 million for the quarter ended June 30, 2007. BGE's portion of our net periodic postretirement benefit costs, excluding amounts capitalized, was $7.7 million for the six months ended June 30, 2008 and $8.2 million for the six months ended June 30, 2007.

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 million in pension benefit payments for our non-qualified pension plans and approximately $32 million for retiree health and life insurance benefit payments during 2008. We contributed $76 million to our qualified pension plans in March 2008.

Financing Activities

Constellation Energy had bank lines of credit under facilities totaling $5.7 billion at June 30, 2008 for short-term financial needs. These facilities can issue letters of credit and/or cash borrowings up to approximately $5.7 billion. At June 30, 2008, we had $4.3 billion in letters of credit issued and at the end of July 2008 we estimate that we had $3.6 billion in letters of credit issued under these facilities. In addition, at June 30, 2008, we had $145.7 million in commercial paper outstanding and at the end of July 2008 we had approximately $630 million in commercial paper outstanding under these facilities.

BGE had a $400.0 million five-year revolving credit facility expiring in 2011 at June 30, 2008. BGE can borrow directly from the banks, use the facility to allow commercial paper to be issued or issue letters of credit. As of June 30, 2008 and July 31, 2008, BGE had $1.1 million in letters of credit issued under this facility. In addition, at June 30, 2008 BGE had no commercial paper outstanding and at the end of July 2008 BGE had approximately $200 million in commercial paper outstanding.

In June 2008, Constellation Energy closed on the following financing transactions:

•: Issued $250.0 million of Zero Coupon Senior Notes due June 2023. Interest, compounded semi-annually, will be paid at maturity or when redeemed. The yield on these notes based on the original maturity date of June 2023 is 6.96%. These notes include a put option, which allows the holder to sell the notes back to us on the put option dates at a price equal to the principal amount plus accrued interest. The put option dates commence in June 2010 and occur yearly at that time through maturity, except for 2012 and 2015. As a result of the put option feature, these notes will be classified as a current liability beginning in June 2009.
•: Issued $450.0 million of Series A Junior Subordinated Debentures at 8.625% due June 15, 2063, but which can be automatically extended to no later than June 15, 2068 at our discretion. Interest is payable quarterly in March, June, September, and December. However, we may choose at any time to defer interest payments on

these debentures for up to ten consecutive years. During this deferral period, interest will continue to accrue, compounded quarterly, and the deferred interest payments will accrue additional interest at a rate equal to the interest rate on these debentures.

In connection with this offering, Constellation Energy executed a replacement capital covenant (RCC) for the benefit of holders of Constellation Energy's 7.60% Notes due April 1, 2032. Under the terms of the RCC, Constellation Energy may not redeem, purchase or defease any subordinated debentures on or before June 15, 2033, or, if the maturity date is extended, the date which is 30 years prior to the maturity date of the subordinated debentures (but not later than June 15, 2038), unless a specified amount of qualifying securities are issued to non-affiliates in a replacement offering during the 180 days prior to the redemption, purchase or defeasance date. Qualifying securities include those that have equity-like characteristics that are the same as, or more equity-like than, the applicable characteristics of the subordinated debentures at the time of redemption, purchase or defeasance.

In June 2008, BGE issued $400.0 million of 6.125% Notes due July 1, 2013. Interest is payable semi-annually on January 1 and July 1, beginning January 1, 2009.

All net proceeds from the issuances above will be used for general corporate purposes.

Maryland Settlement Agreement

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

•: Each party acknowledged that the agreements adopted in 1999 relating to Maryland's electric restructuring law are final and binding and the Maryland PSC will close ongoing proceedings relating to the 1999 settlement.
•: BGE will provide its residential electric customers approximately $188 million in the form of a one-time $170 per customer rate credit by no later than December 31, 2008. We recorded the liability and related charge in the second quarter of 2008 as a current regulatory liability on our and BGE's Consolidated Balance Sheets and a reduction to "Electric revenues" on our and BGE's Consolidated Statements of Income. BGE expects to issue the credit to customers in the third quarter of 2008.
•: BGE customers will be relieved of the potential future liability for decommissioning Constellation Energy's Calvert Cliffs Unit 1 and Unit 2, scheduled to occur no earlier than 2034 and 2036, respectively, and will no longer be obligated to pay a total of $520 million, in 1993 dollars adjusted for inflation, pursuant to the 1999 Maryland PSC order regarding the deregulation of electric generation. BGE will continue to collect $18.7 million annually from all electric customers through 2016 for nuclear decommissioning at Calvert Cliffs and continue to rebate this amount to residential electric customers, as previously required by Senate Bill 1, which had been enacted in June 2006.
•: BGE resumed collection of the residential return portion of the Provider of Last Resort (POLR) administrative charge, which had been eliminated under Senate Bill 1, on June 1, 2008 and will continue collection through May 31, 2010 without having to rebate it to residential customers. This will total approximately $40 million over this period. This charge will be suspended from June 1, 2010 through December 31, 2016.
•: Any electric distribution base rate case filed by BGE will not result in increased distribution rates prior to October 2009, and any increase in electric distribution revenue awarded will be capped at 5% with certain exceptions. Any subsequent electric distribution base rate case may not be filed prior to August 1, 2010. The agreement does not govern or affect our ability to recover costs associated with gas rates, federally approved transmission rates and charges, electric riders, tax increases or increases associated with standard offer service power supply auctions.
•: Effective June 1, 2008, BGE implemented revised depreciation rates for regulatory and financial reporting purposes. The revised rates will reduce depreciation expense approximately $22—$24 million annually without impacting rates charged to customers.
•: Effective June 1, 2008, Maryland laws governing investments in companies that own and operate regulated gas and electric utilities were amended to make them less restrictive with respect to certain capital stock acquisition transactions.
•: Constellation Energy will elect two independent directors to the Board of Directors of BGE within six months from the execution of the settlement agreement.

Income Taxes

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

		Quarter Ended June 30,						Six Months Ended June 30,

		2008			2007			2008			2007

		(In millions)
Income before income taxes (excluding BGE preference stock dividends)		$	281.9		$	145.9		$	506.8		$	414.3
Statutory federal income tax rate			35	%		35	%		35	%		35	%

Income taxes computed at statutory federal rate			98.7			51.1			177.4			145.0
(Decreases) increases in income taxes due to:
	Synthetic fuel tax credits flowed through to income		—			(42.9	)		—			(82.6	)
	Synthetic fuel tax credit phase-out		—			12.4			—			23.9
	Synthetic fuel tax credit true-up for prior period flowed through to income		—			—			(4.6	)		(7.9	)
	State income taxes, net of federal tax benefit		14.1			5.8			23.4			17.6
	Other		(5.7	)		(0.1	)		(13.2	)		(1.9	)

Total income taxes		$	107.1		$	26.3		$	183.0		$	94.1

Effective tax rate			38.0	%		18.0	%		36.1	%		22.7	%

The increase in our effective tax rate for the quarter and six months ended June 30, 2008 compared to the quarter and six months ended June 30, 2007 is primarily due to the absence of synthetic fuel tax credits, which expired at December 31, 2007.

BGE's effective tax rate was 33.1% and 36.7% for the quarter and six months ended June 30, 2008, respectively, compared to 38.5% and 38.7% for the quarter and six months ended June 30, 2007. This reflects the impact of estimated lower 2008 taxable income related to the Maryland settlement agreement, which increased the relative impact of favorable permanent tax adjustments on BGE's effective tax rate.

State income taxes for the quarter and six months ended June 30, 2008 reflect the impact of an increase in the State of Maryland corporate tax rate from 7% to 8.25% effective January 1, 2008.

Unrecognized Tax Benefits

The following table summarizes the change in unrecognized tax benefits during 2008 and our total unrecognized tax benefits at June 30, 2008:

At June 30, 2008


	(In millions)
Total unrecognized tax benefits, January 1, 2008	$	114.5
Increases in tax positions related to the current year		12.1
Reductions in tax positions related to prior years		(9.5	)
Reductions in tax positions related to audit settlements		(21.5	)

Total unrecognized tax benefits, June 30, 2008¹	$	95.6

1 BGE's portion of our total unrecognized tax benefits at June 30, 2008 was $4.2 million.

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

In April 2008, we received a closing agreement from the State of Hawaii regarding audit examinations for the tax years 2001-2003. Additionally, in June 2008, we received notice that the United States Congressional Joint Committee on Taxation had approved the results of the IRS examination of our federal consolidated income tax returns for the 2002-2004 tax years. We reduced our liability for unrecognized tax benefits at June 30, 2008 by $21.5 million to reflect the results of these audits. Substantially all of this reduction has been reclassified to current tax liabilities on our Consolidated Balance Sheets to reflect payments due to the tax authorities in connection with the audit results. The impact of the audit settlements on income tax expense was immaterial.

Total unrecognized tax benefits as of June 30, 2008 of $95.6 million include outstanding state refund claims of approximately $49 million for which no tax benefit was recorded on our Consolidated Balance Sheets because refunds were not received and the claims do not meet the "more-likely-than-not" threshold.

If the total amount of unrecognized tax benefits of $95.6 million were ultimately realized, our income tax expense would decrease by approximately $65 million. However, the $65 million includes state tax refund claims of approximately $49 million discussed above that have been disallowed by tax authorities and we believe that there is a remote likelihood of ultimately realizing any benefit from these refund claim amounts. These refund claims and other unrecognized state tax benefits of $2.7 million currently being reviewed by state tax authorities may be resolved by June 30, 2009. For this reason, we believe it is reasonably possible that reductions to our total unrecognized tax benefits in the range of $40 to $50 million may occur by June 30, 2009, but would not materially impact income tax expense.

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,

	2008		2007		2008		2007

	(In millions)
Interest and penalties recorded as tax expense	$	0.7	$	1.7	$	1.7	$	2.4

Accrued interest and penalties recognized in our Consolidated Balance Sheets were $12.5 million at June 30, 2008 and $16.8 million at December 31, 2007.

Taxes Other Than Income Taxes

BGE collects from certain customers franchise and other taxes that are levied by state or local governments on the sale or distribution of gas and electricity. We include these types of taxes in "Taxes other than income taxes" in our Consolidated Statements of Income. Some of these taxes are imposed on the customer and others are imposed on BGE. We account for the taxes imposed on the customer on a net basis, which means we do not recognize revenue and an offsetting tax expense for the taxes collected from customers. We account for the taxes imposed on BGE on a gross basis, which means we recognize revenue for the taxes collected from customers. Accordingly, we record the taxes accounted for on a gross basis as revenues in the accompanying Consolidated Statements of Income for BGE as follows:

	Quarter Ended June 30,				Six Months Ended June 30,

	2008		2007		2008		2007

	(In millions)
Taxes other than income taxes included in revenues—BGE	$	14.3	$	17.8	$	35.2	$	38.5

Commitments, Guarantees, and Contingencies

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

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

Our merchant energy business enters into various long-term contracts for the procurement and delivery of fuels to supply our generating plant requirements. In most cases, our contracts contain provisions for price escalations, minimum purchase levels, and other financial commitments. These contracts expire in various years between 2008 and 2020. In addition, our merchant energy business enters into long-term contracts for the capacity and transmission rights for the delivery of energy to meet our physical obligations to our customers. These contracts expire in various years between 2008 and 2024.

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

Our regulated electric business enters into various long-term contracts for the procurement of electricity. These contracts expire during 2009 and 2010, representing 100% of our estimated requirements until May 2009, approximately 75% of our estimated requirements from June 2009 to September 2009, approximately 50% of our estimated requirements from October 2009 to May 2010, and approximately 25% of our estimated requirements from June 2010 to September 2010. The cost of power under these contracts is recoverable under the POLR agreement reached with the Maryland PSC.

Our regulated gas business enters into various long-term contracts for the procurement, transportation, and storage of gas. Our regulated gas business has gas procurement, transportation and storage contracts that expire between 2008 and 2028. As discussed in Note 1 of our 2007 Annual Report on Form 10-K, our regulated gas business charges its customers for natural gas, and other associated costs, using gas adjustment clauses set by the Maryland PSC.

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

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

At June 30, 2008, the total amount of commitments was $6,354.0 million. These commitments are primarily related to our merchant energy business.

Long-Term Power Sales Contracts

We enter into long-term power sales contracts in connection with our load-serving activities. We also enter into long-term power sales contracts associated with certain of our power plants. Our load-serving power sales contracts extend for terms through 2019 and provide for the sale of energy to electricity distribution utilities and certain retail customers. Our power sales contracts associated with power plants we own extend for terms into 2014 and provide for the sale of all or a portion of the actual output of certain of our power plants. Most long-term contracts were executed at pricing that approximated market rates, including profit margin, at the time of execution.

Guarantees

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

At June 30, 2008	Stated Limit


	(In millions)
Merchant energy guarantees	$	15,962.3
Nuclear guarantees		812.9
BGE guarantees		250.0
Other non-regulated guarantees		159.6
Power project guarantees		79.6

Total guarantees	$	17,264.4

At June 30, 2008, Constellation Energy had a total of $17,264.4 million in guarantees outstanding related to loans, credit facilities, and contractual performance of certain of its subsidiaries as described below.

•: Constellation Energy guaranteed a face amount of $15,962.3 million on behalf of our subsidiaries for merchant energy activities in order to allow our subsidiaries the flexibility needed to conduct business with counterparties without having to post other forms of collateral. Our calculated fair value of obligations for commercial transactions covered by these guarantees was $4,950.1 million at June 30, 2008, which represents the total amount the parent company could be required to fund based on June 30, 2008 market prices. For those guarantees related to our derivative liabilities, the fair value of the obligation is recorded in our Consolidated Balance Sheets.
•: Constellation Energy guaranteed $812.9 million primarily on behalf of our nuclear generating facilities for nuclear insurance and credit support to ensure these plants have funds to meet expenses and obligations to safely operate and maintain the plants.
•: BGE guaranteed the Trust Preferred Securities of $250.0 million of BGE Capital Trust II.
•: Constellation Energy guaranteed two-thirds of certain debt of Safe Harbor Water Power Corporation, an unconsolidated investment. At June 30, 2008, Safe Harbor Water Power Corporation had outstanding debt of $65.0 million. The maximum amount of Constellation Energy's guarantee is $43.3 million.
•: Constellation Energy guaranteed $107.1 million on behalf of our other nonregulated businesses primarily for loans and performance bonds of which $25.0 million was recorded in our Consolidated Balance Sheets at June 30, 2008.
•: Our other nonregulated business guaranteed $9.2 million primarily for performance bonds.
•: Our merchant energy business guaranteed $79.6 million for loans, performance guarantees, and other payment obligations related to certain power projects in which we have an investment.

We believe it is unlikely that we would be required to perform or incur any losses associated with guarantees of our subsidiaries' obligations.

Contingencies

Environmental Matters

Solid and Hazardous Waste

The Environmental Protection Agency (EPA) and several state agencies have notified us that we are considered a potentially responsible party with respect to the clean-up of certain environmentally contaminated sites. We cannot estimate the final clean-up costs for all of these sites, but the current estimated costs for, and current status of, each site is described in more detail below.

68th Street Dump

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

Spring Gardens

In December 1996, BGE signed a consent order with the Maryland Department of the Environment that requires it to implement remedial action plans for contamination at and around the Spring Gardens site, located in Baltimore, Maryland. The Spring Gardens site was once used to manufacture gas from coal and oil. Based on remedial action plans and cost modeling performed in late 2006, BGE estimates its probable clean-up costs will total $43 million. BGE has recorded these costs as a liability in its Consolidated Balance Sheets and has deferred these

costs, net of accumulated amortization and amounts it recovered from insurance companies, as a regulatory asset. Based on the results of studies at this site, it is reasonably possible that additional costs could exceed the amount BGE has recognized by approximately $3 million. Through June 30, 2008, BGE has spent approximately $41 million for remediation at this site.

BGE also has investigated other small sites where gas was manufactured in the past. We do not expect the clean-up costs of the remaining smaller sites to have a material effect on our financial results.

Air Quality

In late July 2005, we received two Notices of Violation (NOVs) from the Placer County Air Pollution Control District, Placer County California (District) alleging that the Rio Bravo Rocklin facility located in Lincoln, California had violated certain District air emission regulations between January 2003 and March 2005. We have a combined 50% ownership interest in the partnership which owns the Rio Bravo Rocklin facility. In July 2008, the partnership settled the allegations by agreeing to pay approximately $242,000, of which our share will be approximately $121,000, and to implement supplemental environmental projects at the facility over the next 18 months.

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

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 $5 million, which includes the $1 million penalty and our estimate of probable costs to remediate contamination, replace drinking water supplies, and monitor groundwater conditions. 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 November 2007, a class action complaint was filed in Baltimore City Circuit Court alleging that the subsidiary's ash placement operations at the third party site damaged surrounding properties. The complaint seeks injunctive and remedial relief relating to the alleged contamination, unspecified compensatory damages for any personal injuries and property damages associated with the alleged contamination, and unspecified punitive damages. We cannot predict the timing, or outcome, of this proceeding.

Litigation

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

Mercury

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

In rulings applicable to all but three of the cases, involving claims related to approximately 47 children, the Circuit Court for Baltimore City dismissed with prejudice all claims against BGE and Constellation Energy. Plaintiffs may attempt to pursue appeals of the rulings in favor of BGE and Constellation Energy once the cases are finally concluded as to all defendants. We believe that we have meritorious defenses and intend to defend the remaining actions vigorously. However, we cannot predict the timing, or outcome, of these cases, or their possible effect on our, or BGE's, financial results.

Asbestos

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

Approximately 536 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 against us have been dismissed or resolved without any payment and a small minority have been resolved for amounts that were not material to our financial results. The remaining claims are currently pending in state courts in Maryland and Pennsylvania.

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

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

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

Insurance

We discuss our nuclear and non-nuclear insurance programs in Note 12 of our 2007 Annual Report on Form 10-K.

SFAS No. 133 Hedging Activities

We are exposed to market risk, including changes in interest rates and the impact of market fluctuations in the price and transportation costs of electricity, natural gas, and other commodities. We discuss our market risk in more detail in our 2007 Annual Report on Form 10-K.

Commodity Prices

Our merchant energy business uses a variety of derivative and non-derivative instruments to manage the commodity price risk of our wholesale and retail activities and our electric generation facilities, including power sales, fuel and energy purchases, gas purchased for resale, emission credits, weather risk, and the market risk of outages. In order to manage these risks, we may enter into fixed-price derivative or non-derivative contracts to hedge the variability in future cash flows from forecasted sales of energy and purchases of fuel and energy. The objectives for entering into such hedges include:

•: fixing the price for a portion of anticipated future electricity sales at a level that provides an acceptable return on our electric generation operations,
•: fixing the price of a portion of anticipated fuel purchases for the operation of our power plants,
•: fixing the price for a portion of anticipated energy purchases to supply our load-serving customers,
•: fixing the price for a portion of anticipated sales of natural gas to customers, and
•: fixing the price for a portion of anticipated sales or purchases of freight and coal.

The portion of forecasted transactions hedged may vary based upon management's assessment of market, weather, operational, and other factors.

Our merchant energy business designated certain fixed-price forward contracts as cash-flow hedges of forecasted sales of energy and forecasted purchases of fuel and energy for the years 2008 through 2016 under Statement of Financial Accounting Standard (SFAS) No. 133, Accounting for Derivative Instruments and Hedging Activities, as amended. Our merchant energy business had net unrealized pre-tax gains on these cash-flow hedges recorded in "Accumulated other comprehensive loss" of $27.4 million at June 30, 2008 and net unrealized pre-tax losses of $1,498.7 million at December 31, 2007.

We expect to reclassify $813.7 million of net pre-tax gains on cash-flow hedges from "Accumulated other comprehensive loss" into earnings during the next twelve months based on market prices at June 30, 2008. However, the actual amount reclassified into earnings could vary from the amounts recorded at June 30, 2008, due to future changes in market prices. Additionally, for cash-flow hedges settled by physical delivery of the underlying commodity, "Reclassification of net gains or losses on hedging instruments from OCI to net income" represents the fair value of those derivatives, which is realized through gross settlement at the contract price.

During the six months ended June 30, 2008, we de-designated contracts previously designated as cash-flow hedges for which the forecasted transactions originally hedged are probable of not occurring and as a result we recognized a pre-tax gain of $0.7 million. During the six months ended June 30, 2007, we de-designated contracts previously designated as cash-flow hedges and as a result we recognized a pre-tax loss of $21.6 million.

Our merchant energy business also enters into natural gas storage contracts under which the gas in storage qualifies for fair value hedge accounting treatment under SFAS No. 133. We record changes in fair value of these hedges related to our wholesale supply operations as a component of "Nonregulated revenues" in our Consolidated Statements of Income.

We recorded in earnings the following pre-tax (losses) gains related to hedge ineffectiveness:

	Quarter Ended June 30,						Six Months Ended June 30,

	2008			2007			2008			2007

	(In millions)
Cash-flow hedges	$	(44.7	)	$	(13.8	)	$	(89.8	)	$	(30.3	)
Fair value hedges		6.4			3.3			12.9			1.1

Total	$	(38.3	)	$	(10.5	)	$	(76.9	)	$	(29.2	)

The ineffectiveness amounts in the table on the previous page exclude:

•: a $31.3 million pre-tax loss related to derivatives that did not qualify for cash-flow hedge accounting under SFAS No. 133 for some period within the six months ended June 30, 2008, and
•: a $16.4 million pre-tax loss for the quarter and six months ended June 30, 2007 related to the change in value for the portion of our fair value hedges excluded from hedge assessment.

Interest Rates

We use interest rate swaps to manage our interest rate exposures associated with new debt issuances, to manage our exposure to fluctuations in interest rates on variable rate debt, and to optimize the mix of fixed and floating-rate debt. The swaps used to manage our exposure prior to the issuance of new debt are designated as cash-flow hedges under SFAS No. 133, with the effective portion of gains and losses, net of associated deferred income tax effects, recorded in "Accumulated other comprehensive loss" in anticipation of planned financing transactions. We reclassify gains and losses on the hedges from "Accumulated other comprehensive loss" into "Interest expense" in our Consolidated Statements of Income during the periods in which the interest payments being hedged occur.

The swaps used to optimize the mix of fixed and floating-rate debt are designated as fair value hedges under SFAS No. 133. We record any gains or losses on swaps that qualify for fair value hedge accounting treatment, as well as changes in the fair value of the debt being hedged, in "Interest expense," and we record any changes in fair value of the swaps and the debt in "Derivative assets and liabilities" and "Long-term debt", respectively, in our Consolidated Balance Sheets. In addition, we record the difference between interest on hedged fixed-rate debt and floating-rate swaps in "Interest expense" in the periods that the swaps settle.

"Accumulated other comprehensive loss" includes net unrealized pre-tax gains on interest rate cash-flow hedges terminated upon debt issuance totaling $12.0 million at June 30, 2008 and $11.9 million at December 31, 2007. 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.

In order to optimize the mix of fixed and floating-rate debt, we entered into interest rate swaps qualifying as fair value hedges relating to $450.0 million of our fixed-rate debt maturing in 2012 and 2015, and converted this notional amount of debt to floating-rate. The change in fair value of these hedges resulted in an unrealized gain of $13.2 million at June 30, 2008 and was recorded as an increase in our "Derivative assets" and "Long-term debt." The change in fair value of these hedges resulted in an unrealized gain of $11.8 million at December 31, 2007 and was recorded as an increase in our "Derivative assets" and "Long-term debt." We had no hedge ineffectiveness on these interest rate swaps.

Accounting Standards Issued

SFAS No. 161

In March 2008, the FASB issued SFAS No. 161, Disclosures About Derivative Instruments and Hedging Activities. SFAS No. 161 is effective beginning January 1, 2009 and requires entities to provide expanded disclosure about derivative instruments and hedging activities regarding (1) the ways in which an entity uses derivatives, (2) the accounting for derivatives and hedging activities, and (3) the impact that derivatives have (or could have) on an entity's financial position, financial performance, and cash flows. SFAS No. 161 requires expanded disclosures, but does not change the accounting for derivatives. We are currently evaluating the impact of SFAS No. 161, but, because it only provides for additional disclosure, we do not expect the adoption of this standard to have a material impact on our, or BGE's, financial results.

Accounting Standards Adopted

FSP FIN 39-1

In April 2007, the FASB issued Staff Position (FSP) FIN 39-1, Amendment of FASB Interpretation No. 39. As amended, FIN 39, Offsetting of Amounts Related to Certain Contracts, requires an entity to report all derivatives recorded at fair value net of any associated fair value cash collateral with the same counterparty under a master netting arrangement. Therefore, effective January 1, 2008, we reported all derivatives recorded at fair value net of the associated fair value cash collateral. We applied the provisions of FSP FIN 39-1 by adjusting all financial statement periods presented, which reduced total assets at December 31, 2007 by $203.4 million. We present the fair value cash collateral that has been offset against our net derivative positions as part of our adoption of SFAS No. 157, Fair Value Measurements, below.

SFAS No. 157

Effective January 1, 2008, we adopted SFAS No. 157, Fair Value Measurements, which defines fair value, establishes a framework for measuring fair value, and requires certain disclosures about fair value measurements. Fair value is the price that we would receive to sell an asset or pay to transfer a liability in an orderly transaction between market participants at the measurement date (exit price).

related to cash-flow hedges and a pre-tax gain in earnings totaling $3 million for the remainder of our derivative liabilities. All other impacts of adoption were immaterial.

Our assets and liabilities measured at fair value on a recurring basis consist of the following:

			As of June 30, 2008

			Assets			Liabilities

			(In millions)
Debt and equity securities			$	1,398.0		$	—

Derivative instruments:
	Classified as derivative assets and liabilities:
		Current		3,714.7			3,349.6
		Noncurrent		3,000.2			2,566.2

		Total classified as derivative assets and liabilities		6,714.9			5,915.8
	Classified as accounts receivable *			(708.6	)		—

	Total derivative instruments			6,006.3			5,915.8

Total recurring fair value measurements			$	7,404.3		$	5,915.8

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

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

The table below sets forth by level within the fair value hierarchy the company's assets and liabilities that were measured at fair value on a recurring basis as of June 30, 2008. The gross derivative assets and liabilities presented in this table increased significantly during the quarter ended June 30, 2008. This increase is primarily due to a rising commodity price environment coupled with an increase in the level of open positions from a higher level of business activity. For example, the following represents the approximate increases we have experienced in commodity prices during the six months ended June 30, 2008:

•: 33% in power,
•: 44% in natural gas,
•: 153% in coal, and
•: 55% in crude oil.

Even after reflecting the impacts of netting and cash collateral, the balances of our derivative assets and liabilities increased significantly and by approximately the same magnitude during the quarter ended June 30, 2008.

At June 30, 2008		Level 1			Level 2			Level 3			Netting and Cash Collateral*			Total Net Fair Value


		(In millions)
Debt and equity securities		$	436.7		$	961.3		$	—		$	—		$	1,398.0

Derivative assets			1,139.6			77,364.6			8,987.1			(81,485.0	)		6,006.3
Derivative liabilities			(1,419.3	)		(76,275.7	)		(8,775.7	)		80,554.9			(5,915.8	)

	Net derivative position		(279.7	)		1,088.9			211.4			(930.1	)		90.5

Total		$	157.0		$	2,050.2		$	211.4		$	(930.1	)	$	1,488.5

* We present our derivative assets and liabilities in our Consolidated Balance Sheets on a net basis. We net derivative assets and liabilities, including cash collateral, when a legally enforceable master netting agreement exists between us and the counterparty to a derivative contract. At June 30, 2008, we included $1,007.2 million of cash collateral held and $77.1 million of cash collateral posted (excluding margin posted on exchange traded derivatives) in netting amounts in the above table. See discussion of FSP FIN 39-1 on the prior page for more details on our net presentation.

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

•: Level 1—Quoted prices available in active markets for identical assets or liabilities as of the reporting date.
•: Level 2—Pricing inputs other than quoted prices in active markets included in Level 1, which are either directly or indirectly observable as of the reporting date.
•: Level 3—Pricing inputs include significant inputs that are generally not observable from market activity.

We determine the fair value of our assets and liabilities using quoted market prices (Level 1) or pricing inputs that are observable (Level 2) whenever that information is available. We use unobservable inputs (Level 3) to estimate fair value only when relevant observable inputs are not available.

We classify assets and liabilities within the fair value hierarchy based on the lowest level of input that is significant to the fair value measurement of each individual asset and liability taken as a whole. We determine fair value using Level 1 inputs by multiplying the price by the quantity of the asset or liability we hold. We primarily determine fair value measurements classified as Level 2 or Level 3 using the income valuation approach, which involves discounting estimated cash flows.

Debt and equity securities include our nuclear decommissioning trust funds, trust assets securing certain executive benefits and other marketable securities. Nuclear decommissioning trust funds primarily consist of publicly traded individual securities, which are valued based on unadjusted quoted prices in active markets, and are classified within Level 1; and commingled funds, which are valued based on the fund share price, which is observable on a less frequent basis, and are classified within Level 2. Trust assets securing certain executive benefits consist of mutual funds, which are actively traded and are valued based upon unadjusted quoted prices, and are classified within Level 1. Our other marketable securities consist of publicly traded individual securities, which are valued based on unadjusted quoted prices in active markets, and are classified within Level 1.

Derivative assets and liabilities include exchange-traded contracts and bilateral contracts. Exchange-traded derivative contracts, including futures and certain options, which are valued based on unadjusted quoted prices in active markets are classified within Level 1. However, some exchange-traded derivatives are valued using pricing inputs based upon market quotes or market transactions. In such cases, these exchange-traded derivatives are classified within Level 2.

Bilateral derivative instruments include swaps, forwards, certain options and complex structured transactions that may be offset economically with similar positions in exchange-traded markets. In certain instances, we may utilize models to measure the fair value of these instruments. Generally, we use similar models to value similar instruments. Valuation models utilize various inputs which include quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in markets that are not active, other observable inputs for the asset or liability, and market-corroborated inputs, which are inputs derived principally from or corroborated by observable market data by correlation or other means. Where observable inputs are available for substantially the full term and value of the asset or liability, we classify the instrument in Level 2.

Certain bilateral derivatives trade in less active markets with a lower availability of pricing information. In addition, complex or structured transactions may require us to use internally-developed model inputs, which might not be observable in or corroborated by the market, to determine fair value. When such inputs have more than an insignificant impact on the measurement of fair value, we classify the instrument in Level 3.

In order to determine fair value, we utilize various factors, including market data and assumptions that market participants would use in pricing assets or liabilities as well as assumptions about the risks inherent in the inputs to the valuation technique. These factors include:

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

We regularly evaluate and validate the inputs we use to estimate fair value by a number of methods, including various market price verification procedures as well as review and verification of models and changes to those models. These activities are undertaken by individuals that are independent of those responsible for estimating fair value.

The Company's assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the classification of assets and liabilities within the fair value hierarchy. Because of the long-term nature of certain assets and liabilities measured at fair value as well as differences in the availability of market prices and market liquidity over their terms, inputs for some assets and liabilities may fall into any one of the three levels in the fair value hierarchy or some combination thereof. While SFAS No. 157 requires us to classify these assets and liabilities in the lowest level in the hierarchy for which inputs are significant to the fair value measurement,

a portion of that measurement may be determined using inputs from a higher level in the hierarchy.

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

		Quarter ended June 30, 2008			Six months ended June 30, 2008


		(In millions)
Balance at beginning of period		$	400.4		$	(147.1	)
Realized and unrealized gains (losses):
	Recorded in income		181.0			165.9
	Recorded in other comprehensive income		74.6			250.5
Purchases, sales, issuances, and settlements			5.2			36.3
Transfers into and out of level 3			(449.8	)		(94.2	)

Balance as of June 30, 2008		$	211.4		$	211.4

Change in unrealized gains relating to derivatives still held as of June 30, 2008		$	247.6		$	246.0

Realized and unrealized gains (losses) are included primarily in "Nonregulated revenues" for our derivative contracts that are marked-to-market in our Consolidated Statements of Income and are included in "Accumulated other comprehensive loss" for our derivative contracts designated as cash-flow hedges in our Consolidated Balance Sheets. We discuss the income statement classification for realized gains and losses related to cash-flow hedges for our various hedging relationships in Note 1 of our 2007 Annual Report on Form 10-K.

Realized and unrealized gains (losses) include the realization of derivative contracts through maturity. Purchases, sales, issuances, and settlements represent cash paid or received for option premiums, and the acquisition or termination of derivative contracts prior to maturity. Transfers into Level 3 represent existing assets or liabilities that were previously categorized at a higher level for which the inputs to the model became unobservable. Transfers out of Level 3 represent assets and liabilities that were previously classified as Level 3 for which the inputs became observable based on the criteria discussed on the previous page for classification in either Level 1 or Level 2.

Related Party Transactions

Constellation Energy

On March 31, 2008, our merchant energy business sold its working interest in 83 oil and natural gas producing wells in Oklahoma to Constellation Energy Partners (CEP), an equity method investment of Constellation Energy, for total proceeds of approximately $53 million. Our merchant energy business recognized a $14.3 million gain, net of the minority interest gain of $0.7 million on the sale and exclusive of our 28.5% ownership interest in CEP. This gain is recorded in "Gains on Sales of Upstream Gas Assets" in our Consolidated Statements of Income.

BGE—Income Statement

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

Our merchant energy business will supply a portion of BGE's market-based standard offer service obligation to residential electric customers through May 31, 2010.

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

	Quarter Ended June 30,				Six Months Ended June 30,

	2008		2007		2008		2007

	(In millions)
Purchased energy	$	186.0	$	254.3	$	457.3	$	557.0

In addition, Constellation Energy charges BGE for the costs of certain corporate functions. Certain costs are directly assigned to BGE. We allocate other corporate function costs based on a total percentage of expected use by BGE. We believe this method of allocation is reasonable and approximates the cost BGE would have incurred as an unaffiliated entity.

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

	Quarter Ended June 30,				Six Months Ended June 30,

	2008		2007		2008		2007

	(In millions)
Charges to BGE	$	35.0	$	35.5	$	70.1	$	69.8

BGE—Balance Sheet

BGE participates in a cash pool under a Master Demand Note agreement with Constellation Energy. Under this arrangement, participating subsidiaries may invest in or borrow from the pool at market interest rates. Constellation Energy administers the pool and invests excess cash in short-term investments or issues commercial paper to manage consolidated cash requirements. Under this arrangement, BGE had invested $181.1 million at June 30, 2008 and had invested $78.4 million at December 31, 2007.

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

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

Item 2. Management's Discussion

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

Introduction and Overview

Constellation Energy Group, Inc. (Constellation Energy) is an energy company that conducts its business through various subsidiaries including a merchant energy business and Baltimore Gas and Electric Company (BGE). We describe our operating segments in the Notes to Consolidated Financial Statements beginning on page 13.

This Quarterly Report on Form 10-Q is a combined report of Constellation Energy and BGE. References in this report to "we" and "our" are to Constellation Energy and its subsidiaries, collectively. References in this report to the "regulated business(es)" are to BGE. We discuss our business in more detail in Item 1—Business section of our 2007 Annual Report on Form 10-K and we discuss the risks affecting our business in Item 1A. Risk Factors section on page 51.

Our 2007 Annual Report on Form 10-K includes a detailed discussion of various items impacting our business, our results of operations, and our financial condition. These include:

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

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

Effective January 1, 2008, we adopted SFAS No. 157, Fair Value Measurements, as discussed in the Notes to Consolidated Financial Statements beginning on page 22. We discuss our accounting policy for determining fair value in more detail in the Notes to Consolidated Financial Statements as well as in our Critical Accounting Policies section and Note 1 in our 2007 Annual Report on Form 10-K.

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

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

As you read this discussion and analysis, refer to our Consolidated Statements of Income on page 3, which present the results of our operations for the quarters and six months ended June 30, 2008 and 2007. We analyze and explain the differences between periods in the specific line items of the Consolidated Statements of Income.

We have organized our discussion and analysis as follows:

•: We describe changes to our strategy and our business environment during the year.
•: We highlight significant events that occurred in 2008 that are important to understanding our results of operations and financial condition.
•: We then review our results of operations beginning with an overview of our total company results, followed by a more detailed review of those results by operating segment.
•: We review our financial condition, addressing our sources and uses of cash, capital resources, commitments, and liquidity.
•: We conclude with a discussion of our exposure to various market risks.

Strategy

We discuss our business strategy in detail in the Strategy section of our 2007 Annual Report on Form 10-K. In that discussion, we indicate that we are constantly reevaluating our strategies. We have announced that in addition to focusing on our basic plan and in the context of optimizing our business mix as it relates to our allocation of capital and achieving long-term growth by continuing to make investments to grow our physical asset base, we are actively assessing the ongoing capital requirements of our Global Commodities business. In that regard, we are considering various strategic alternatives for our Global Commodities business, including partnership arrangements.

Business Environment

With the evolving regulatory environment surrounding customer choice, increasing competition, and the growth of our merchant energy business, various factors affect our financial results. We discuss these various factors in the Forward Looking Statements section on page 53 and in Item 1A. Risk Factors section on page 51. We discuss our market risks in the Market Risk section beginning on page 47.

In this section, we discuss in more detail events which have impacted our business during 2008.

Federal Regulation

In May 2008, five state public service commissions, including the Public Service Commission of Maryland (Maryland PSC), consumer advocates and others filed a complaint against PJM Interconnection, the regional transmission organization for the Mid-atlantic region (PJM), at the Federal Energy Regulatory Commission (FERC) alleging that the PJM reliability pricing model (RPM) produced unreasonable prices during the period from June 1, 2008 through May 31, 2011. The complaint requests that FERC establish a refund effective date of June 1, 2008, reject the results of the 2007/08 through 2010/11 RPM capacity auction results, and significantly reduce prices for capacity beginning as of June 1, 2008 through 2011/12. We, along with other power suppliers and supplier trade groups, have filed protests to the complaint. We cannot predict the outcome of this proceeding or the amount of refunds that may be owed by or due to us, if any. However, the outcome, and any refunds that are ultimately assessed, could have a material impact on our financial results.

Environmental Matters

Air Quality

National Ambient Air Quality Standards (NAAQS)

In March 2008, the Environmental Protection Agency (EPA) adopted a stricter NAAQS for ozone. We are unable to determine the impact that complying with the stricter NAAQS for ozone will have on our financial results until the states in which our generating facilities are located adopt plans to meet the new standards.

In July 2008, the United States Court of Appeals for the District of Columbia Circuit issued a ruling that effectively repealed the Clean Air Interstate Rule (CAIR). We do not believe that the decision will result in a material change to our emissions reduction plan in Maryland as the emissions reduction requirements of Maryland's Healthy Air Act and Clean Power Rule are more stringent and apply sooner than those under CAIR. However, we cannot predict what additional judicial, legislative or regulatory actions will be taken in response to the court's decision or whether such actions may affect our financial results. We discuss the impact that this ruling had on our second quarter of 2008 results in the Merchant Energy Business section on page 33. We discuss this ruling in more detail in the Notes to Consolidated Financial Statements on page 13.

Capital Expenditures

As discussed in our 2007 Annual Report on Form 10-K, we expect to incur additional environmental capital expenditures to comply with air quality laws and regulations. Based on updated information from vendors, we expect our estimated environmental capital requirements for these air quality projects to be approximately $530 million in 2008, $345 million in 2009, $15 million in 2010 and $25 million from 2011-2012.

Our estimates may change further as we implement our compliance plan. As discussed in our 2007 Annual Report on Form 10-K, our estimates of capital expenditures continue to be subject to significant uncertainties.

Accounting Standards Issued and Adopted

We discuss recently issued and adopted accounting standards in the Accounting Standards Issued and Accounting Standards Adopted sections of the Notes to Consolidated Financial Statements beginning on page 22.

Events of 2008

Acquisitions

Hillabee Energy Center

On February 14, 2008, we acquired a partially completed gas-fired power generating facility in Alabama. We discuss this acquisition in more detail in the Notes to Consolidated Financial Statements on page 12.

West Valley Power Plant

On June 1, 2008, we acquired a gas-fired peaking plant in Utah. We discuss this acquisition in more detail in the Notes to Consolidated Financial Statements on page 12.

Nufcor International Limited

On June 26, 2008, we acquired a uranium marketing services company in the United Kingdom. We discuss this acquisition in more detail in the Notes to Consolidated Financial Statements on page 12.

Asset Sales

Working Interests in Gas Properties

On June 30, 2008, we sold a portion of our working interests in proved and unproved gas properties in Arkansas. We discuss this asset sale in more detail in the Notes to Consolidated Financial Statements on page 13.

Dry Bulk Vessel

On July 10, 2008, a shipping joint venture in which our merchant energy business owns a 50% ownership interest sold one of six freight ships it owns for a gain to us of approximately $29 million. This gain will be recorded in the third quarter of 2008. We discuss this sale in more detail in the Notes to Consolidated Financial Statements on page 13.

Financing Activities

In June 2008, we issued the following:

•: $250.0 million of Zero Coupon Senior Notes due June 2023, and
•: $450.0 million of Series A Junior Subordinated Debentures due June 2063.

Also, in June 2008, BGE issued $400.0 million of 6.125% Notes due July 1, 2013.

We discuss our financing activities in more detail in the Notes to Consolidated Financial Statements beginning on page 15.

Maryland Settlement Agreement

In March 2008, Constellation Energy, BGE and a Constellation Energy affiliate entered into a settlement agreement with the State of Maryland, the Maryland PSC and certain State of Maryland officials to resolve pending litigation and to settle other prior legal, regulatory and legislative issues. We discuss this settlement in more detail in the Notes to Consolidated Financial Statements on page 16.

Commodity Prices

During the first half of 2008, the energy markets were affected by higher commodity prices including increases in the prices for:

•: power of approximately 33%,
•: natural gas of approximately 44%,
•: coal of approximately 153%, and
•: crude oil of approximately 55%

The higher coal prices primarily resulted from greater global demand, which created significant performance risk for some coal producers who have had to increase capital spending to ensure production sufficient to meet higher contractual forward commitments. Power prices also increased, but at a rate less than the underlying rate of increase in fuel prices. This commodity price environment contributed to the following impacts on our results:

•: We experienced significant mark-to-market gains as a result of increased commodity prices. We discuss our mark-to-market results in our Mark-to-Market section on page 34.
•: Our total derivative assets increased $4,924.1 million and total derivative liabilities increased $3,662.6 million since December 31, 2007. We discuss our derivative assets and liabilities in more detail on page 35.
•: We experienced an increase in our exposure to lower credit quality wholesale counterparties primarily due to the increase in coal prices. We discuss our wholesale credit risk exposure in more detail in the Wholesale Credit Risk section beginning on page 48.
•: One of our domestic coal suppliers was unable to meet production targets and filed for bankruptcy. As a result, in the quarter ended March 31, 2008, we incurred a credit loss related to this supplier. We discuss the impact of this event on our results in more detail on page 33.
•: We executed several contract settlements and amended certain other contracts, primarily in the quarter ended March 31, 2008, to reduce our exposure to supplier nonperformance risk and/or credit risk. We discuss these transactions in more detail on page 33.
•: We incurred gains and losses recognized on hedges due to ineffectiveness, and certain cash-flow hedges that no longer qualify for hedge accounting. We discuss hedge ineffectiveness in more detail on page 33.

Higher commodity prices also impact the level of capital required to support our business activities. We had additional issuances of letters of credit to support our Global Commodities activities. In the second quarter of 2008, we issued $1.75 billion in letters of credit. We discuss our financing activities in more detail in our Available Sources of Funding section on page 44.

Results of Operations for the Quarter and Six Months Ended June 30, 2008 Compared with the Same Periods of 2007

In this section, we discuss our earnings and the factors affecting them. We begin with a general overview, then separately discuss earnings for our operating segments. Changes in other income, fixed charges, and income taxes are discussed, as necessary, in the aggregate for all segments in the Consolidated Nonoperating Income and Expenses section on page 42.

Overview

Results

		Quarter Ended June 30,						Six Months Ended June 30,

		2008			2007			2008			2007

		(In millions, after-tax)
Merchant energy		$	279.7		$	102.2		$	351.9		$	223.8
Regulated electric			(104.2	)		19.4			(70.5	)		51.6
Regulated gas			(3.1	)		(5.7	)		36.3			28.0
Other nonregulated			(0.9	)		0.4			(0.5	)		10.2

Income from Continuing Operations			171.5			116.3			317.2			313.6
	Loss from discontinued operations		—			—			—			(1.6	)

Net Income		$	171.5		$	116.3		$	317.2		$	312.0

Other Items Included in Operations
	Impairment losses and other costs	$	—		$	(12.2	)	$	—		$	(12.2	)
	Accrual of Maryland settlement credit		(125.3	)		—			(125.3	)		—
	BGE effective tax rate impact of Maryland settlement agreement		2.1			—			8.7			—
	Non-qualifying hedges		(34.7	)		1.4			(69.3	)		(7.9	)
	Workforce reduction costs		—			(1.5	)		—			(1.5	)

Total Other Items		$	(157.9	)	$	(12.3	)	$	(185.9	)	$	(21.6	)

Quarter and Six Months Ended June 30, 2008

Our total net income for the quarter and six months ended June 30, 2008 compared to the same periods of 2007 increased primarily due to the following:

	Quarter Ended June 30,			Six Months Ended June 30,

	2008 vs. 2007

	(In millions, after-tax)
Global Commodities mark-to-market results	$	146		$	120
Global Commodities realization of previously originated contracts		39			39
Contract terminations and sales		—			90
Customer Supply margin		35			24
Sale of upstream gas assets		46			55
Hedge ineffectiveness		11			(16	)
Regulated operations, primarily Maryland settlement agreement credit		(121	)		(114	)
Merchant operating expenses, primarily labor and benefit costs		(68	)		(75	)
Credit loss—coal supplier bankruptcy		—			(33	)
Interest and investment income		(18	)		(18	)
Emissions allowance write-down		(13	)		(13	)
Synthetic fuel facilities		(11	)		(26	)
Other nonregulated businesses		—			(11	)
All other changes		9			(17	)

Total change in net income	$	55		$	5

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

Merchant Energy Business

Background

Our merchant energy business is a competitive provider of energy solutions for various customers. We discuss the impact of deregulation on our merchant energy business in Item 1. Business—Competition section of our 2007 Annual Report on Form 10-K.

Our merchant energy business focuses on delivery of physical, customer-oriented products to producers and consumers, manages the risk and optimizes the value of our owned generation assets, and uses our portfolio management and trading capabilities both to manage risk and to deploy risk capital to generate additional returns. We continue to identify and pursue opportunities which can generate additional returns through portfolio management and trading activities within our business. These opportunities have increased due to the significant growth in scale of our wholesale and retail operations.

We record merchant energy revenues and expenses in our financial results in different periods depending upon which portion of our business they affect and based on the associated accounting policies. We discuss our revenue recognition policies in the Critical Accounting Policies section and Note 1 of our 2007 Annual Report on Form 10-K. We summarize our revenue and expense recognition policies as follows:

•: We record revenues as they are earned and fuel and purchased energy costs as they are incurred for contracts and activities subject to accrual accounting, including certain load-serving activities.
•: Prior to the settlement of the forecasted transaction being hedged, we record changes in the fair value of contracts designated as cash-flow hedges in other comprehensive income to the extent that the hedges are effective. We record the effective portion of changes in fair value of hedges in earnings in the period the settlement of the hedged transaction occurs. We record the ineffective portion of the changes in fair value of hedges, if any, in earnings in the period in which the change occurs.
•: We record changes in the fair value of contracts that are subject to mark-to-market accounting in revenues or fuel and purchased energy expenses in the period in which the change occurs.

The accounting for derivatives requires us to use judgment to make estimates and assumptions in determining the fair value of certain contracts and in recording revenues from those contracts. We discuss the effects of mark-to-market accounting on our results in the Mark-to-Market section beginning on page 34.

Our Global Commodities operation actively transacts in energy and energy-related commodities in order to manage our portfolio of energy purchases and sales to customers through structured transactions. As part of these activities, we trade energy and energy-related commodities and deploy risk capital in the management of our portfolio in order to earn additional returns. These activities are managed through daily value at risk and stop loss limits and liquidity guidelines, and may have a material impact on our financial results. We discuss the impact of our portfolio management and trading activities and value at risk in more detail in the Mark-to-Market section beginning on page 34 and the Market Risk section beginning on page 47.

Results

		Quarter Ended June 30,						Six Months Ended June 30,

		2008			2007			2008			2007

		(In millions)
Revenues		$	4,601.1		$	4,395.8		$	8,548.1		$	8,837.8
Fuel and purchased energy expenses			(3,550.2	)		(3,724.4	)		(6,849.1	)		(7,488.8	)
Operating expenses			(546.2	)		(431.7	)		(976.0	)		(851.9	)
Impairment losses and other costs			—			(20.2	)		—			(20.2	)
Workforce reduction costs			—			(2.3	)		—			(2.3	)
Depreciation, depletion, and amortization			(68.1	)		(67.9	)		(139.2	)		(130.8	)
Accretion of asset retirement obligations			(17.0	)		(18.2	)		(33.6	)		(35.9	)
Taxes other than income taxes			(30.5	)		(29.1	)		(58.2	)		(55.9	)
Gains on sales of upstream gas assets			76.5			—			91.5			—

Income from Operations		$	465.6		$	102.0		$	583.5		$	252.0

Income from Continuing Operations (after-tax)		$	279.7		$	102.2		$	351.9		$	223.8
	Loss from discontinued operations (after-tax)		—			—			—			(1.6	)

Net Income		$	279.7		$	102.2		$	351.9		$	222.2

Other Items Included in Operations (after-tax)
	Impairment losses and other costs	$	—		$	(12.2	)	$	—		$	(12.2	)
	Non-qualifying hedges		(34.7	)		1.4			(69.3	)		(7.9	)
	Workforce reduction costs		—			(1.5	)		—			(1.5	)

Total Other Items		$	(34.7	)	$	(12.3	)	$	(69.3	)	$	(21.6	)

Certain prior-period amounts have been reclassified to conform with the current period's presentation. Above amounts include intercompany transactions eliminated in our Consolidated Financial Statements. The Information by Operating Segment section within the Notes to Consolidated Financial Statements on page 14 provides a reconciliation of operating results by segment to our Consolidated Financial Statements.

Revenues and Fuel and Purchased Energy Expenses

Our merchant energy business manages the revenues we realize from the sale of energy and energy-related products to our customers and our costs of procuring fuel and energy. As previously discussed, our merchant energy business uses either accrual or mark-to-market accounting to record our revenues and expenses. Mark-to-market results reflect the net impact of amounts recorded in earnings to recognize the changes in fair value of derivative contracts subject to mark-to-market accounting during the reporting period. We discuss the effects of mark-to-market accounting on our results separately in the Mark-to-Market section beginning on page 34.

Revenues

Our merchant energy revenues increased $205.3 million and decreased $289.7 million during the quarter and six months ended June 30, 2008, respectively, compared to the same periods in 2007 primarily due to the following:

	Quarter Ended June 30,			Six Months Ended June 30,

	2008 vs. 2007

	(In millions)
Change in Global Commodities mark-to-market revenues	$	312		$	212
Growth at Global Commodities and Customer Supply operations		459			704
All other (substantially all due to change in gas procurement activities)¹		(566	)		(1,206	)

Total increase (decrease) in merchant revenues	$	205		$	(290	)

¹ In the third quarter of 2007, we changed the management of the wholesale procurement function for retail gas activities from our Customer Supply operation to our Global Commodities operation. In connection with this change, we began to account for the underlying retail gas contracts as derivative contracts subject to mark-to-market accounting, under which changes in fair value are recorded in revenues as they occur. This activity was previously accounted for on a gross basis and recorded in accrual revenues and fuel and purchased energy expenses. The change to market-to-market accounting for this activity reduced both our accrual revenues and fuel and purchased energy expenses.

Fuel and Purchased Energy Expenses

During the quarter and six months ended June 30, 2008, merchant energy fuel and purchased energy expenses decreased $174.2 million and $639.7 million, respectively, compared to the same periods in 2007 primarily due to the change in gas procurement activities discussed above. This was partially offset by an increase at our Global Commodities and Customer Supply operations of approximately $396 million and $503 million for the quarter and six months ended June 30, 2008, respectively, primarily related to growth in these operations.

The difference between revenues and fuel and purchased energy expenses, including all direct expenses, represents the gross margin of our merchant energy business, and this measure is a useful tool for assessing the profitability of our merchant energy business. Accordingly, we believe it is appropriate to discuss the operating results of our merchant energy business by analyzing the changes in gross margin between periods. In managing our portfolio, we may terminate, restructure, or acquire contracts. Such transactions are within the normal course of managing our portfolio and may materially impact the timing of our recognition of revenues, fuel and purchased energy expenses, and cash flows.

We analyze our merchant energy gross margin in the following categories:

•: Generation—our operation that owns, operates, and maintains fossil, nuclear, and renewable generating facilities and holds interests in qualifying facilities, a fuel processing facility and power projects in the United States. We present the gross margin results of this operation based on a 100% hedged assumption for the portfolio, related to both output from the facilities and the fuel used to generate electricity. The assumption is based on executing hedges at current market prices with the Global Commodities operation at the end of each fiscal year in order to ensure that the Generation operation is fully hedged. Therefore, all commodity price risk is managed by and presented in the results of our Global Commodities operation as discussed on the next page. Changes in gross margin of our Generation operation during the period are due to changes in the level of output from the generating assets, and changes in gross margin between years are a result of changes in prices and expected output.

•: Customer Supply—our load-serving operation that provides energy products and services to wholesale and retail electric and natural gas customers, including distribution utilities, cooperatives, aggregators, and commercial, industrial and governmental customers. We present the gross margin results of this operation based on the gross margin value of new customer supply arrangements at the time of execution assuming an estimated level of customer usage and the impact of any changes in the underlying usage of the customers based on actual energy deliveries. Changes in estimated customer usage result from attrition (customers changing suppliers) or variable load risk (changes in actual usage when compared to expected usage). All commodity price risk is presented in and managed by our Global Commodities operation as discussed below.
•: Global Commodities—our marketing, risk management, and trading operation that manages contractually owned physical assets, including generation facilities, natural gas properties, international coal and freight assets, provides risk management services, and trades energy and energy-related commodities. This operation provides the wholesale risk management function for our Generation and Customer Supply operations and includes our merchant energy business' actual hedged positions with third parties. Therefore, changes in gross margin for this operation result mostly from changes in commodity prices and positions across the various commodities and regions in which we transact.

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

		Quarter Ended June 30,								Six Months Ended June 30,

		2008				2007				2008				2007

		(Dollar amounts in millions)
Gross Margin:
	Generation	$	375	36	%	$	385	57	%	$	873	51	%	$	829	62	%
	Customer Supply		296	28			238	36			395	23			355	26
	Global Commodities		380	36			48	7			431	26			165	12

	Total	$	1,051	100	%	$	671	100	%	$	1,699	100	%	$	1,349	100	%

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

Generation

The $10 million decrease in Generation gross margin during the quarter ended June 30, 2008 compared to the same period of 2007 is primarily due to lower output as a result of the planned refueling outage at the Ginna facility during the second quarter of 2008, which did not occur in the same period of 2007, partially offset by lower forced outages at our nuclear plants and differences in Calvert Cliffs and Nine Mile Point planned refueling outages.

The $44 million increase in Generation gross margin during the six months ended June 30, 2008 compared to the same period of 2007 is primarily due to the following:

•: approximately $26 million increase from higher energy prices for the output of our generating assets in the PJM and New York regions, and
•: higher earnings of approximately $17 million from our investments in power projects.

Customer Supply

The $58 million increase in Customer Supply gross margin during the quarter ended June 30, 2008 compared to the same period of 2007 is primarily due to the following:

•: approximately $56 million of higher gross margin related to our retail gas operation primarily due to the acquisition of Cornerstone Energy on July 1, 2007, and
•: approximately $6 million of higher mark-to-market results in our retail gas business. We discuss this in more detail in the Mark-to-Market section.

These gains were partially offset by approximately $4 million related to lower realization of contracts executed in prior periods and lower new business originated and realized during the quarter.

The $40 million increase in Customer Supply gross margin during the six months ended June 30, 2008 compared to the same period of 2007 is primarily due to the following:

•: approximately $50 million of higher mark-to-market results in our retail gas business. We discuss this in more detail in the Mark-to-Market section.
•: approximately $40 million of higher gross margin at our retail gas operation primarily due to the acquisition of Cornerstone Energy.

These increases were partially offset by approximately $50 million due to lower expected realization of contracts executed in prior periods and lower new business originated and realized during the six months ended June 30, 2008.

Global Commodities

As previously discussed in the Events of 2008 section on page 28, the energy markets were affected by substantially higher commodity prices. These market impacts are reflected in the $332 million increase in gross margin from our Global Commodities activities during the quarter ended June 30, 2008 compared to the same period of 2007. This increase is primarily due to:

•: approximately $242 million related to our portfolio of contracts subject to mark-to-market accounting. We discuss these transactions in more detail in the Mark-to-Market section beginning on page 34,
•: approximately $65 million of higher gross margin related to higher realization from contracts executed in prior periods,
•: approximately $21 million of higher gross margin at our international coal and freight operations, excluding the unfavorable impact of hedge ineffectiveness discussed below, and
•: approximately $19 million related to gains recognized on hedges due to ineffectiveness and certain cash-flow hedges that no longer qualified for hedge accounting during the quarter.

These increases were partially offset by a decrease of approximately $22 million related to a write-down of our emission allowance inventory to reflect current market price deceases. We discuss this in more detail in the Notes to Consolidated Financial Statements on page 13.

The $266 million increase in gross margin from our Global Commodities operation for the six months ended June 30, 2008 compared to the same period in 2007 is primarily due to:

•: approximately $200 million of higher gross margin related to our portfolio of contracts subject to mark-to-market accounting, including higher earnings of approximately $35 million related to increased origination gains primarily associated with nonderivative contracts that were amended to reduce counterparty nonperformance risk, resulting in the contracts becoming derivatives for which mark-to-market accounting is required. We discuss these transactions in more detail in the Mark-to-Market section beginning on page 34,
•: approximately $150 million after tax related to gains recognized as a result of termination and sale of in-the-money energy purchase contracts, coal supply contracts, and freight contracts to eliminate or reduce operation and performance risk with certain counterparties, and
•: approximately $65 million of higher gross margin related to higher expected realization from contracts executed in prior periods.

These increases were partially offset by the following:

•: approximately $55 million related to the bankruptcy of one of our domestic coal suppliers. During the first quarter of 2008, as a result of a default by the supplier, we terminated our derivative contracts with the supplier, reclassified the related asset to accounts receivable and fully reserved the amount. Prior to this default, we had recorded unrealized gains totaling $55 million that remain in "Accumulated other comprehensive loss" and will be reclassified to earnings as the forecasted transactions occur. The majority will be reclassified to earnings during 2008, and the remainder will be fully realized by 2010,
•: approximately $28 million related to lower gross margin at our international coal and freight operations primarily due to rising freight costs, excluding the unfavorable impact of hedge ineffectiveness discussed below,
•: approximately $26 million related to losses recognized on hedges due to ineffectiveness and certain cash-flow hedges that no longer qualified for hedge accounting during the quarter, and
•: approximately $22 million related to the write-down of our emission allowance inventory. We discuss this in more detail in the Notes to Consolidated Financial Statements on page 13.

Mark-to-Market

Mark-to-market results include net gains and losses from origination, trading, and risk management activities for which we use the mark-to-market method of accounting. We discuss these activities and the mark-to-market method of accounting in more detail in the Critical Accounting Policies section of our 2007 Annual Report on Form 10-K.

As a result of the nature of our operations and the use of mark-to-market accounting for certain activities, mark-to-market earnings will fluctuate. We cannot predict these fluctuations, but the impact on our earnings could be material. We discuss our market risk in more detail in the Market Risk section beginning on page 47. The primary factors that cause fluctuations in our mark-to-market results are:

•: changes in the level and volatility of forward commodity prices and interest rates,
•: The number and size of our open derivative positions, and
•: the number, size, and profitability of new transactions, including termination or restructuring of existing contracts.

Mark-to-market results were as follows:

			Quarter Ended June 30,						Six Months Ended June 30,

			2008			2007			2008			2007

			(In millions)
Unrealized mark-to-market results
	Origination gains		$	8.8		$	1.5		$	68.5		$	33.1

	Risk management and trading—mark-to-market
		Unrealized changes in fair value		347.1			105.8			297.5			82.6
		Changes in valuation techniques		—			—			—			—
		Reclassification of settled contracts to realized		(179.5	)		37.2			(146.9	)		50.5

	Total risk management and trading—mark-to-market			167.6			143.0			150.6			133.1

Total unrealized mark-to-market*				176.4			144.5			219.1			166.2
Realized mark-to-market				179.5			(37.2	)		146.9			(50.5	)

Total mark-to-market results			$	355.9			107.3		$	366.0		$	115.7

* Total unrealized mark-to-market is the sum of origination gains and total risk management and trading—mark-to-market.

Origination gains arise primarily from contracts that our Global Commodities operation structures to meet the risk management needs of our customers or relate to our trading activities. Transactions that result in origination gains may be unique and provide the potential for individually significant revenues and gains from a single transaction.

During the six months ended June 30, 2008, our Global Commodities operation amended certain nonderivative contracts to mitigate counterparty performance risk under the existing contracts. As a result of these amendments, the revised contracts are derivatives subject to mark-to-market accounting under Statement of Financial Accounting Standard (SFAS) No. 133, Accounting for Derivative Instruments and Hedging Activities, as amended. The change in accounting for these contracts from nonderivative to derivative resulted in substantially all of the origination gains for 2008 presented in the table above.

During the six months ended June 30, 2007, our Global Commodities operation amended certain nonderivative power sales contracts such that the new contracts are derivatives subject to mark-to-market accounting under SFAS No. 133. Simultaneous with the amending of the nonderivative contracts, we executed at current market prices several new offsetting derivative power purchase contracts subject to mark-to-market accounting. The combination of these transactions resulted in substantially all of the origination gains presented for the first six months of 2007 in the table above, as well as mitigated our risk exposure under the amended contracts. The origination gain from these 2007 transactions was partially offset by approximately $12 million of losses in our accrual portfolio due to the reclassification of losses related to cash-flow hedges previously established for the amended nonderivative contracts from "Accumulated other comprehensive loss" into earnings. In the absence of these transactions, the origination gain and the losses associated with cash-flow hedges would have been recognized over the remaining term of the contracts, which would have extended through the first quarter of 2009.

Risk management and trading—mark-to-market represents both realized and unrealized gains and losses from changes in the value of our portfolio, including the recognition of gains and losses associated with changes in the unobservable input valuation adjustment. In addition, we use derivative contracts subject to mark-to-market accounting to manage our exposure to changes in market prices primarily as a result of our gas transportation and storage activities, while in general the underlying physical transactions related to our gas activities are accounted for on an accrual basis. We use other non-trading derivative transactions subject to mark-to-market accounting to manage our exposure to changes in market prices related to our other activities that are accounted for on an accrual basis. We discuss the changes in mark-to-market results below. We show the relationship between our mark-to-market results and the change in our net mark-to-market energy asset later in this section.

Total mark-to-market results increased $248.6 million during the quarter ended June 30, 2008 compared to the same period of 2007 primarily due to an increase in origination gains of $7.3 million and higher gains from unrealized changes in fair value of $241.3 million. The increase in gains from unrealized changes in fair value was

primarily due to approximately $300 million in higher gains on open positions in our portfolio management and trading business during the quarter ended June 30, 2008 compared to the same period of 2007. These open positions were in the power, gas, and coal markets, all of which benefited from a favorable price environment in the quarter ended June 30, 2008 as compared to the same period in 2007.

The $300 million in higher gains on open positions were offset by approximately $59 million of losses related to the unfavorable impact of certain economic hedges of accrual transactions that do not qualify for or are not designated as cash-flow hedges

Total mark-to-market results increased $250.3 million during the six months ended June 30, 2008 compared to the same period of 2007 primarily due to an increase in origination gains of $35.4 million and higher gains from unrealized changes in fair value of $214.9 million. The increase in gains from unrealized changes in fair value was primarily due to approximately $316 million in higher gains on open positions in our portfolio management and trading business during the first six months of 2008 compared to the same period of 2007. These open positions were in the power, gas, and coal markets, all of which benefited from a favorable price environment in the first half of 2008 as compared to the same period in 2007.

The $316 million in higher gains on open positions was offset by approximately $101 million of losses related to the unfavorable impact of certain economic hedges of accrual transactions that do not qualify for or are not designated as cash-flow hedges.

Derivative Assets and Liabilities

Derivative assets and liabilities consisted of the following:

	June 30, 2008			December 31, 2007


	(In millions)
Current Assets	$	3,714.7		$	760.6
Noncurrent Assets		3,000.2			1,030.2

Total Assets		6,714.9			1,790.8

Current Liabilities		3,349.6			1,134.3
Noncurrent Liabilities		2,566.2			1,118.9

Total Liabilities		5,915.8			2,253.2

Net Derivative Position	$	799.1		$	(462.4	)

Composition of net derivative position:
Hedges	$	349.1		$	(937.6	)
Mark-to-market	$	1,380.1		$	673.0
Net cash collateral included in derivative balances	$	(930.1	)	$	(197.8	)

Net Derivative Position	$	799.1		$	(462.4	)

As discussed in our 2007 Annual Report on Form 10-K, our "Derivative assets and liabilities" include contracts accounted for as hedges and those accounted for on a mark-to-market basis. The amounts are presented in our Consolidated Balance Sheets after the impact of netting as required by FSP FIN 39-1, which is discussed in more detail in the Notes to Consolidated Financial Statements on page 22. Due to the impacts of commodity prices, the number of open positions, master netting arrangements, and offsetting risk positions on the presentation of our derivative assets and liabilities in our Consolidated Balance Sheets, we believe an evaluation of the net position is the most relevant measure, and is discussed in more detail below. However, we present our gross derivatives as required by SFAS No. 157 in the Notes to Consolidated Financial Statements on page 23.

The increase in our net derivative asset subject to hedge accounting since December 31, 2007 of $1,286.7 million was due primarily to increases in power prices that increased the fair value of our cash-flow hedge positions and settlement of out-of-the-money cash-flow hedges during the first half of 2008. The general increase in commodity prices also increased collateral requirements associated with our derivative positions.

The following are the primary sources of the change in the net mark-to-market derivative asset during the quarter and six months ended June 30, 2008:

		Quarter Ended June 30, 2008						Six Months Ended June 30, 2008


		(in millions)
Fair value beginning of period					$	762.7					$	673.0
Changes in fair value recorded in earnings
	Origination gains	$	8.8					$	68.5
	Unrealized changes in fair value		347.1						297.5
	Changes in valuation techniques		—						—
	Reclassification of settled contracts to realized		(179.5	)					(146.9	)

Total changes in fair value						176.4						219.1
Changes in value of exchange-listed futures and options						509.6						543.3
Net change in premiums on options						22.2						7.1
Contracts acquired						—						—
Other changes in fair value						(90.8	)					(62.4	)

Fair value at end of period					$	1,380.1					$	1,380.1

Changes in our net mark-to-market derivative asset that affected earnings were as follows:

•: Origination gains represent the initial unrealized fair value at the time these contracts are executed to the extent permitted by applicable accounting rules.
•: Unrealized changes in fair value represent unrealized changes in commodity prices, the volatility of options on commodities, the time value of options, and other valuation adjustments.
•: Changes in valuation techniques represent improvements in estimation techniques, including modeling and other statistical enhancements used to value our portfolio to more accurately reflect the economic value of our contracts.
•: Reclassification of settled contracts to realized represent the portion of previously unrealized amounts settled during the period and recorded as realized revenues.

The net mark-to-market derivative asset also changed due to the following items recorded in accounts other than in our Consolidated Statements of Income:

•: Changes in value of exchange-listed futures and options are adjustments to remove unrealized revenue from exchange-traded contracts that are included in risk management revenues. The fair value of these contracts is recorded in "Accounts receivable" rather than "Derivative assets" in our Consolidated Balance Sheets because these amounts are settled through our margin account with a third-party broker.
•: Net changes in premiums on options reflects the accounting for premiums on options purchased as an increase in the net derivative asset and premiums on options sold as a decrease in the net derivative asset.
•: Contracts acquired represents the initial fair value of acquired derivative contracts recorded in "Derivative assets and liabilities" in our Consolidated Balance Sheets.
•: Other changes in fair value include transfers of derivative assets and liabilities between accounting methods resulting from the designation and de-designation of cash-flow hedges.

Effective January 1, 2008, we adopted SFAS No. 157, which defines fair value, establishes a framework for measuring fair value, and requires certain disclosures about fair value measurements. Fair value is the price that we would receive to sell an asset or pay to transfer a liability in an orderly transaction between market participants at the measurement date (exit price).

Consistent with the exit price concept, upon adoption we reduced our derivative liabilities to reflect our own credit risk. As a result, during the first quarter of 2008 we recorded a pre-tax reduction in "Accumulated other comprehensive loss" totaling $10 million for the portion related to cash-flow hedges and a pre-tax gain in earnings totaling $3 million for the remainder of our derivative liabilities. All other impacts of adoption were immaterial. We discuss SFAS No. 157 and how we determine fair value in more detail in the Notes to Consolidated Financial Statements beginning on page 22.

The settlement terms of the portion of our net derivative asset subject to mark-to-market accounting and sources of fair value based on the fair value hierarchy established by SFAS No. 157 are as follows as of June 30, 2008:

	Settlement Term


	2008			2009		2010			2011		2012			2013			Thereafter			Fair Value

	(In millions)
Level 1	$	31.3		$	—	$	—		$	—	$	—		$	—		$	—		$	31.3
Level 2		(4.1	)		937.0		(124.0	)		47.4		32.1			(7.9	)		20.4			900.9
Level 3		(183.4	)		220.7		390.6			55.6		(21.7	)		(0.6	)		(13.3	)		447.9

Total net derivative asset subject to mark-to-market accounting	$	(156.2	)	$	1,157.7	$	266.6		$	103.0	$	10.4		$	(8.5	)	$	7.1		$	1,380.1

Management uses its best estimates to determine the fair value of commodity and derivative contracts it holds and sells. These estimates consider various factors including closing exchange and over-the-counter price quotations, time value, volatility factors, and credit exposure. Additionally, because the depth and liquidity of the power markets varies substantially between regions and time periods, the prices used to determine fair value could be affected significantly by the volume of transactions executed. Future market prices and actual quantities will vary from those used in recording mark-to-market energy assets and liabilities, and it is possible that such variations could be material.

We manage our mark-to-market risk on a portfolio basis based upon the delivery period of our contracts and the individual components of the risks within each contract. Accordingly, we manage the energy purchase and sale obligations under our contracts in separate components based upon the commodity (e.g., electricity or gas), the product (e.g., electricity for delivery during peak or off-peak hours), the delivery location (e.g., by region), the risk

profile (e.g., forward or option), and the delivery period (e.g., by month and year).

The electricity, fuel, and other energy contracts we hold have varying terms to maturity, ranging from contracts for delivery the next hour to contracts with terms of ten years or more. Because an active, liquid electricity futures market comparable to that for other commodities has not developed, the majority of contracts are direct contracts between market participants and are not exchange-traded or financially settling contracts that can be readily offset in their entirety through an exchange or other market mechanism. Consequently, we and other market participants generally realize the value of these contracts as cash flows become due or payable under the terms of the contracts rather than through selling or liquidating the contracts themselves.

In order to realize the entire value of a long-term contract in a single transaction, we would need to sell or assign the entire contract. If we were to sell or assign any of our long-term contracts in their entirety, we may not realize the entire value reflected in the preceding table. However, based upon the nature of our Global Commodities operation, we expect to realize the value of these contracts, as well as any contracts we may enter into in the future to manage our risk, over time as the contracts and related hedges settle in accordance with their terms. Generally, we do not expect to realize the value of these contracts and related hedges by selling or assigning the contracts themselves in total.

Operating Expenses

Our merchant energy business operating expenses increased $114.5 million during the quarter ended June 30, 2008 and $124.1 million during the six months ended June 30, 2008 compared to the same periods of 2007 primarily due to higher labor and benefit costs at our merchant energy business of $95.8 million for the quarter ended June 30, 2008 and $87.5 million for the six months ended June 30, 2008. In addition, outage costs at our generating facilities increased $16.4 million for the quarter ended June 30, 2008 and $22.1 million for the six months ended June 30, 2008.

Impairment Losses and Other Costs

During the quarter ended June 30, 2007, our merchant energy business recorded a $20.2 million charge associated with a cancelled wind development project. We did not have such a charge in 2008.

Depreciation, Depletion and Amortization Expense

Our merchant energy business incurred higher depreciation, depletion and amortization expenses of $8.4 million during the six months ended June 30, 2008 compared to the same period of 2007 primarily due to increased depletion expenses related to our upstream natural gas operations as a result of increased drilling and production, partially offset by the cessation of operations at our synfuel facilities in December 2007.

Gains on Sale of Upstream Gas Assets

During the quarter ended June 30, 2008, our merchant energy business sold a portion of its working interests in proved natural gas reserves and unproved properties and recognized a $76.5 million pre-tax gain on this sale. Additionally, we recognized a $14.3 million gain, net of the minority interest gain of $0.7 million, related to the sale of our working interests in oil and natural gas producing wells in Oklahoma to Constellation Energy Partners that was completed in the first quarter of 2008.

Regulated Electric Business

Our regulated electric business is discussed in detail in Item 1. Business—Electric Business section of our 2007 Annual Report on Form 10-K.

Results

	Quarter Ended June 30,						Six Months Ended June 30,

	2008			2007			2008			2007

	(In millions)
Revenues	$	448.7		$	544.3		$	1,158.1		$	1,059.1
Electricity purchased for resale expenses		(404.3	)		(320.9	)		(859.6	)		(595.1	)
Operations and maintenance expenses		(98.2	)		(91.9	)		(192.9	)		(178.2	)
Depreciation and amortization		(47.8	)		(46.8	)		(98.6	)		(93.7	)
Taxes other than income taxes		(31.6	)		(34.5	)		(67.8	)		(69.7	)

(Loss) Income from Operations	$	(133.2	)	$	50.2		$	(60.8	)	$	122.4

Net (Loss) Income	$	(104.2	)	$	19.4		$	(70.5	)	$	51.6

Other Items Included in Operations:
Accrual of Maryland settlement credit	$	(125.3	)	$	—		$	(125.3	)	$	—
Effective tax rate impact of Maryland settlement agreement		2.0			—			5.0			—

Total Other Items	$	(123.3	)	$	—		$	(120.3	)	$	—

Above amounts include intercompany transactions eliminated in our Consolidated Financial Statements. The Information by Operating Segment section within the Notes to Consolidated Financial Statements on page 14 provides a reconciliation of operating results by segment to our Consolidated Financial Statements.

Net income from the regulated electric business decreased $123.6 million during the quarter ended June 30, 2008 and $122.1 million during the six months ended June 30, 2008 compared to the same periods in 2007, mostly due to the impact of the accrual of the Maryland settlement credit of $125.3 million after-tax. This was partially offset by the favorable impact of reduced earnings from the Maryland settlement agreement on our effective tax rate of $2.0 million for the quarter ended June 30, 2008 and $5.0 million for the six months ended June 30, 2008.

Electric Revenues

The changes in electric revenues in 2008 compared to 2007 were caused by:

	Quarter Ended June 30, 2008 vs. 2007			Six Months Ended June 30, 2008 vs. 2007


	(In millions)
Distribution volumes	$	(1.3	)	$	(5.1	)
Maryland settlement credit		(188.2	)		(188.2	)
Revenue decoupling		1.7			7.0
Standard offer service		(6.5	)		(16.9	)
Rate stabilization credits		88.5			280.8
Rate stabilization recovery		10.1			29.1
Financing credits		(3.2	)		(7.8	)
Senate Bill 1 credits		(0.6	)		(6.0	)

Total change in electric revenues from electric system sales		(99.5	)		92.9
Other		3.9			6.1

Total change in electric revenues	$	(95.6	)	$	99.0

Distribution Volumes

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

The percentage changes in our electric distribution volumes, by type of customer, in 2008 compared to 2007 were:




Residential	(3.9	)%	(3.3	)%
Commercial	(4.4	)	(4.4	)
Industrial	(1.0	)	(1.0	)

During the quarter ended June 30, 2008 compared to the same period of 2007, we distributed less electricity to residential customers mostly due to milder weather and decreased usage per customer, partially offset by an increased number of customers. We distributed less electricity to commercial customers due to decreased usage per customer and milder weather, partially offset by an increased number of customers. We distributed less electricity to industrial customers primarily due to decreased usage per customer, partially offset by an increased number of customers.

During the six months ended June 30, 2008 compared to the same period of 2007, we distributed less electricity to residential and commercial customers due to decreased usage per customer and milder weather, partially offset by an increased number of customers. We distributed less electricity to industrial customers primarily due to decreased usage per customer, partially offset by an increased number of customers.

Maryland Settlement Credit

As discussed in more detail in the Notes to Consolidated Financial Statements on page 16, BGE entered into a settlement agreement with the State of Maryland and other parties, which provided residential electric customers a credit totaling $170 per customer. The total estimated settlement of $188.2 million was accrued in the second quarter of 2008 and is expected to be paid in the third quarter of 2008.

Revenue Decoupling

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

Standard Offer Service

BGE provides standard offer service for customers that do not select an alternative supplier. We discuss the provisions of Senate Bill 1 related to residential electric rates in the Item 7. Management's Discussion and Analysis—Business Environment—Regulation—Maryland—Senate Bills 1 and 400 section of our 2007 Annual Report on Form 10-K.

Standard offer service revenues decreased during the quarter and six months ended June 30, 2008 compared to the same periods of 2007, mostly due to lower standard offer service volumes, partially offset by an increase in the standard offer service rates.

Rate Stabilization Credits

As a result of Senate Bill 1, we were required to defer from July 1, 2006 until May 31, 2007 a portion of the full market rate increase resulting from the expiration of the residential rate freeze. In addition, we offered a plan also required under Senate Bill 1 allowing residential customers the option to defer the transition to market rates from June 1, 2007 until January 1, 2008. The decrease in rate stabilization credits during the quarter and six months ended June 30, 2008 compared to the same period in 2007 was primarily due to the expiration of the rate stabilization

plan which began on July 1, 2006 and ended on May 31, 2007.

Rate Stabilization Recovery

In late June 2007, BGE began recovering amounts deferred during the first rate deferral period that ended on May 31, 2007. In April 2008, BGE began recovering amounts deferred during the second rate deferral period that ended on January 1, 2008. The recovery of the second rate deferral will occur over a 21-month period beginning April 1, 2008 and ending on December 31, 2009.

Financing Credits

Concurrent with the recovery of the deferred amounts related to the first rate deferral period, we are providing credits to residential customers to compensate them primarily for income tax benefits associated with the financing of the deferred amounts with rate stabilization bonds.

Senate Bill 1 Credits

As a result of Senate Bill 1, beginning January 1, 2007, we were required to provide to residential electric customers a credit equal to the amount collected from all BGE electric customers for the decommissioning of our Calvert Cliffs nuclear power plant and to suspend collection of the residential return component of the POLR administrative charge collected through residential rates through May 31, 2007. Under an order issued by the Maryland PSC in May 2007, as of June 1, 2007, we were required to reinstate collection of the residential return component of the POLR administration charge in rates and to provide all residential electric customers a credit for the residential return component of the administrative charge. Under the Maryland settlement agreement, which is discussed in more detail on page 16 of Notes to Consolidated Financial Statements, BGE was allowed to resume collection of the residential return portion of the POLR administrative charge from June 1, 2008 through May 31, 2010 without having to rebate it to residential customers.

Electricity Purchased for Resale Expenses

Electricity purchased for resale expenses include the cost of electricity purchased for resale to our standard offer service customers. These costs do not include the cost of electricity purchased by delivery service only customers.

	Quarter Ended June 30,					Six Months Ended June 30,

	2008		2007			2008		2007

	(In millions)
Actual costs	$	393.1	$	404.8		$	834.3	$	871.3
Deferral under rate stabilization plan		—		(88.5	)		—		(280.8	)
Recovery under rate stabilization plan		11.2		4.6			25.3		4.6

Electricity purchased for resale expenses	$	404.3	$	320.9		$	859.6	$	595.1

Actual Costs

BGE's actual costs for electricity purchased for resale decreased $11.7 million during the quarter ended June 30, 2008 and $37.0 million for the six months ended June 30, 2008 compared to the same periods of 2007, primarily due to lower volumes, partially offset by slightly higher contract prices to purchase electricity for our customers.

Deferral under Rate Stabilization Plan

The deferral of the difference between our actual costs of electricity purchased for resale and what we were allowed to bill customers under Senate Bill 1 ended on January 1, 2008. These deferred expenses, plus carrying charges, are included in "Regulatory Assets (net)" in our, and BGE's, Consolidated Balance Sheets.

Recovery under Rate Stabilization Plans

In late June 2007, we began recovering previously deferred amounts from customers. During the quarter and six months ended June 30, 2008, we recovered $11.2 million and $25.3 million, respectively, in deferred electricity purchased for resale expenses. These collections secure the payment of principal and interest and other ongoing costs associated with rate stabilization bonds issued by a subsidiary of BGE in June 2007.

Electric Operations and Maintenance Expenses

Regulated operations and maintenance expenses increased $6.3 million in the quarter ended June 30, 2008 compared to the same period in 2007, due to $3.3 million of incremental distribution service restoration expenses associated with 2008 storms, $1.6 million of higher labor and benefit costs and the impact of inflation on other costs, and increased uncollectible accounts receivable expense of $1.3 million.

Regulated operations and maintenance expenses increased $14.7 million in the six months ended June 30, 2008 compared to the same period in 2007, mostly due to $7.9 million of higher labor and benefit costs and the impact of inflation on other costs, increased uncollectible accounts receivable expense of $3.6 million, and $3.3 million of incremental distribution service restoration expenses associated with 2008 storms.

Electric Depreciation and Amortization

Regulated electric depreciation and amortization expense increased $4.9 million during the six months ended June 30, 2008 compared to the same period in 2007, primarily due to increased amortization expense associated with demand response programs, which are discussed in more detail in Item 1. Business—Baltimore Gas & Electric Company—Electric Load Management section of our 2007 Annual Report on Form 10-K.

As a result of the Maryland settlement agreement, which is discussed in more detail on page 16 of Notes to Consolidated Financial Statements, BGE implemented revised depreciation rates for regulatory and financial reporting purposes effective June 1, 2008 that are expected to reduce annual depreciation expense by approximately $16 to $18 million for its electric business.

Taxes Other Than Income Taxes

Taxes other than income taxes decreased by $2.9 million during the quarter ended June 30, 2008 compared to the same period in 2007, primarily due to the impact of the Maryland settlement agreement on franchise taxes.

Regulated Gas Business

Our regulated gas business is discussed in detail in Item 1. Business—Gas Business section of our 2007 Annual Report on Form 10-K.

Results

	Quarter Ended June 30,						Six Months Ended June 30,

	2008			2007			2008			2007

	(In millions)
Revenues	$	188.1		$	162.8		$	584.5		$	570.1
Gas purchased for resale expenses		(127.7	)		(102.9	)		(397.7	)		(387.0	)
Operations and maintenance expenses		(38.6	)		(39.4	)		(77.5	)		(76.2	)
Depreciation and amortization		(11.2	)		(11.7	)		(23.1	)		(23.7	)
Taxes other than income taxes		(8.4	)		(8.5	)		(18.8	)		(19.1	)

Income from operations	$	2.2		$	0.3		$	67.4		$	64.1

Net (Loss) Income	$	(3.1	)	$	(5.7	)	$	36.3		$	28.0

Other Items Included in Operations:
Effective tax rate impact of Maryland settlement agreement	$	0.1		$	—		$	3.7		$	—

Net income from the regulated gas business increased $8.3 million during the six months ended June 30, 2008 compared to the same period of 2007, primarily due to the impact of reduced earnings from the Maryland settlement agreement on our effective tax rate of $3.7 million and an increase in revenues less gas purchased for resale expenses of $2.5 million after-tax.

Gas Revenues

The changes in gas revenues in 2008 compared to 2007 were caused by:

	Quarter Ended June 30, 2008 vs. 2007			Six Months Ended June 30, 2008 vs. 2007


	(In millions)
Distribution volumes	$	(3.3	)	$	(9.3	)
Base rates		—			(0.1	)
Revenue decoupling		3.8			10.4
Gas cost adjustments		8.5			(16.1	)

Total change in gas revenues from gas system sales		9.0			(15.1	)
Off-system sales		16.2			28.9
Other		0.1			0.6

Total change in gas revenues	$	25.3		$	14.4

Distribution Volumes

The percentage changes in our distribution volumes, by type of customer, in 2008 compared to 2007 were:




Residential	(20.1	)%	(11.2	)%
Commercial	(4.6	)	(3.4	)
Industrial	2.5		12.4

During the quarter ended June 30, 2008 compared to the same period in 2007, we distributed less gas to residential customers due to milder weather and decreased usage per customer, partially offset by an increased number of customers. We distributed less gas to commercial customers compared to the same period of 2007, mostly due to decreased usage per customer and milder weather, partially offset by an increased number of customers. We distributed more gas to industrial customers mostly due to increased usage by customers.

During the six months ended June 30, 2008 compared to the same period in 2007, we distributed less gas to residential customers due to milder weather and decreased usage per customer, partially offset by an increased number of customers. We distributed less gas to commercial customers due to decreased usage per customer and milder weather, partially offset by an increased number of

customers. We distributed more gas to industrial customers mostly due to increased usage per customer.

Base Rates

In December 2005, the Maryland PSC issued an order granting BGE a $35.6 million annual increase in its gas base rates. In December 2006, the Baltimore City Circuit Court upheld the rate order. However, certain parties have filed an appeal with the Court of Special Appeals. We cannot provide assurance that the Maryland PSC's order will not be reversed in whole or in part or that certain issues will not be remanded to the Maryland PSC for reconsideration.

Revenue Decoupling

The Maryland PSC allows us to record a monthly adjustment to our gas distribution revenues to eliminate the effect of abnormal weather and usage patterns on our gas distribution volumes. This means our monthly gas distribution revenues are based on weather and usage that is considered "normal" for the month. Therefore, while these revenues are affected by customer growth, they will not be affected by actual weather or usage conditions.

Gas Cost Adjustments

We charge our gas customers for the natural gas they purchase from us using gas cost adjustment clauses set by the Maryland PSC as described in Note 1 of our 2007 Annual Report on Form 10-K.

Gas cost adjustment revenues increased $8.5 million during the quarter ended June 30, 2008 compared to the same period of 2007, primarily due to higher prices.

Gas cost adjustment revenues decreased $16.1 million during the six months ended June 30, 2008 compared to the same period of 2007 because we sold less gas, partially offset by higher prices.

Off-System Gas Sales

Off-system gas sales are low-margin direct sales of gas to wholesale suppliers of natural gas. Off-system gas sales, which occur after we have satisfied our customers' demand, are not subject to gas cost adjustments. The Maryland PSC approved an arrangement for part of the margin from off-system sales to benefit customers (through reduced costs) and the remainder to be retained by BGE (which benefits shareholders). Changes in off-system sales do not significantly impact earnings.

Revenues from off-system gas sales increased during the quarter and six months ended June 30, 2008 compared to the same period of 2007 because we sold more gas at higher prices.

Gas Purchased For Resale Expenses

Gas purchased for resale expenses include the cost of gas purchased for resale to our customers and for off-system sales. These costs do not include the cost of gas purchased by delivery service only customers.

Gas costs increased $24.8 million during the quarter ended June 30, 2008 compared to the same period of 2007 because we purchased gas at higher prices.

Gas costs increased $10.7 million during the six months ended June 30, 2008 compared to the same period of 2007 because we purchased gas at higher prices, partially offset by lower volumes.

Gas Depreciation and Amortization

As a result of the Maryland settlement agreement, which is discussed in more detail on page 16 of Notes to Consolidated Financial Statements, BGE implemented revised depreciation rates for financial reporting purposes effective June 1, 2008 that are expected to reduce annual depreciation expense by approximately $6 million for its gas business.

Other Nonregulated Businesses

Results

	Quarter Ended June 30,						Six Months Ended June 30,

	2008			2007			2008			2007

	(In millions)
Revenues	$	66.1		$	44.8		$	125.3		$	119.5
Operating expense		(53.6	)		(25.9	)		(99.0	)		(73.1	)
Depreciation and amortization		(14.8	)		(16.4	)		(29.3	)		(27.0	)
Taxes other than income taxes		(0.6	)		(0.7	)		(1.1	)		(1.3	)

(Loss) Income from Operations	$	(2.9	)	$	1.8		$	(4.1	)	$	18.1

Net (Loss) Income	$	(0.9	)	$	0.4		$	(0.5	)	$	10.2

Net income decreased $10.7 million during the six months ended June 30, 2008 compared to the same periods of 2007 primarily because the first quarter of 2007 included a gain related to a sale of a leasing arrangement that did not occur in 2008.

Consolidated Nonoperating Income and Expenses

Gains on Sale of CEP LLC Equity

Gains on sale of CEP LLC Equity decreased $12.9 million for both the quarter and six months ended June 30, 2008 compared to the same periods of 2007 as CEP LLC, an equity investment of Constellation Energy, did not sell additional equity in the second quarter of 2008 as it had in the second quarter of 2007.

Other Income

Other income decreased during the quarter and six months ended June 30, 2008 compared to the same periods of 2007 mostly due to lower interest and investment income as a result of a lower average cash balance.

Other income at BGE increased during the six months ended June 30, 2008 compared to the same period of 2007 primarily due to carrying charges related to rate stabilization credits. We discuss the rate stabilization credits in more detail in the Regulated Electric section on page 38.

Fixed Charges

Our fixed charges decreased during the quarter and six months ended June 30, 2008 compared to the same periods of 2007 mostly due to a higher level of interest capitalized due to higher capital spending on current environmental projects.

Fixed charges at BGE increased during the quarter and six months ended June 30, 2008 compared to the same periods of 2007 mostly due to interest expense recognized on the rate stabilization bonds that were issued in June 2007.

Income Taxes

Our income taxes increased $80.8 million during the quarter ended June 30, 2008 and $88.9 million during the six months ended June 30, 2008 compared to the same periods of 2007 mostly because of the absence of synthetic fuel tax credits, which expired in 2007, and an increase in income before income taxes.

During the quarter and six months ended June 30, 2008, BGE's income tax expense decreased $62.1 million and $70.4 million, respectively, primarily due to lower pre-tax income as a result of the accrual of the $188.2 million Maryland settlement credit in the second quarter of 2008. We discuss the Maryland settlement agreement in more detail on page 16.

Financial Condition

Cash Flows

The following table summarizes our cash flows for 2008 and 2007, excluding the impact of changes in intercompany balances.

		2008 Segment Cash Flows									Consolidated Cash Flows

		Six Months Ended June 30, 2008									Six Months Ended June 30,
		Merchant			Regulated			Other			2008			2007

		(In millions)
Operating Activities
	Net income (loss)	$	351.9		$	(34.2	)	$	(0.5	)	$	317.2		$	312.0
	Non-cash adjustments to net income		(11.4	)		345.3			23.9			357.8			110.9
	Changes in working capital		(158.3	)		145.5			(103.3	)		(116.1	)		66.1
	Defined benefit obligations*		—			—			—			(44.8	)		(73.4	)
	Other		7.5			(18.8	)		30.6			19.3			(5.5	)

Net cash provided by (used in) operating activities			189.7			437.8			(49.3	)		533.4			410.1

Investing Activities
	Investments in property, plant and equipment		(607.3	)		(217.2	)		(45.0	)		(869.5	)		(564.1	)
	Acquisitions, net of cash acquired		(312.4	)		—			—			(312.4	)		(250.6	)
	Contributions to nuclear decommissioning trust funds		(18.7	)		—			—			(18.7	)		(8.8	)
	Sales of investments and other assets		—			—			—			—			4.7
	Sales of property, plant and equipment		204.1			12.9			—			217.0			—
	Contract and portfolio acquisitions		—			—			—			—			(474.2	)
	(Increase) decrease in restricted funds		(0.1	)		(207.7	)		10.9			(196.9	)		(8.4	)
	Other		14.2			—			(1.3	)		12.9			7.8

Net cash used in investing activities			(720.2	)		(412.0	)		(35.4	)		(1,167.6	)		(1,293.6	)

Cash flows from operating activities less cash flows from investing activities		$	(530.5	)	$	25.8		$	(84.7	)		(634.2	)		(883.5	)

Financing Activities*
	Net issuance (repayment) of debt											938.6			(88.5	)
	Debt issuance costs											(15.6	)		—
	Proceeds from issuance of common stock											8.3			39.2
	Common stock dividends paid											(165.0	)		(147.6	)
	Reacquisition of common stock											—			(114.4	)
	Proceeds from contract and portfolio acquisitions											—			847.8
	Other											2.7			25.9

Net cash provided by financing activities												769.0			562.4

Net increase (decrease) in cash and cash equivalents											$	134.8		$	(321.1	)

* Items are not allocated to the business segments because they are managed for the company as a whole.
Certain prior-period amounts have been reclassified to conform to the current period presentation.

Cash Flows from Operating Activities

Cash provided by operating activities was $533.4 million in 2008 compared to $410.1 million in 2007. This $123.3 million increase was primarily due to favorable changes in non-cash adjustments to net income and a $49 million reduction in pension contributions, partially offset by a decrease in changes to working capital in 2008.

Non-cash adjustments to net income had a positive impact of $357.8 million on cash flow from operations in 2008 compared to $110.9 million in 2007. The net increase of $246.9 million was primarily due to a change in deferred fuel costs of $280.2 million related mostly to the expiration of the first BGE rate stabilization plan. We discuss the BGE rate stabilization plan in more detail in the Electric Revenues section beginning on page 38.

The decrease in working capital of $182.2 million in 2008 compared to 2007 is primarily due to the effect of increased commodity prices and increased level of open positions within our merchant energy business during the six months ended June 2008, which increased the value of our derivative assets and liabilities, partially offset by the change in our total cash collateral position.

Cash Flows from Investing Activities

Cash used in investing activities was $1,167.6 million in 2008 compared to $1,293.6 million in 2007. The $126.0 million decrease in cash used in 2008 compared to 2007 was primarily due to a $474.2 million decrease in cash used for contract and portfolio acquisitions in 2007.

This decrease in the use of cash was partially offset by a $305.4 million increase in cash paid for investments in property, plant and equipment, which includes spending related to environmental controls at our generating facilities. We also incurred a $61.8 million increase in cash paid for acquisitions. We discuss our acquisitions in more detail in the Notes to Consolidated Financial Statements on page 12.

Cash Flows from Financing Activities

Cash provided by financing activities was $769.0 million in 2008 compared to $562.4 million in 2007. The increase in cash provided by financing activities of $206.6 million was primarily due to a net increase in proceeds from the issuance of long-term debt and short-term borrowings of $560.5 million and a decrease in cash used for the repayment of long-term debt of $466.6 million. This increase in cash provided by financing activities was partially offset by the absence of cash received from contract and portfolio acquisitions in 2007 of $847.8 million.

Security Ratings

We discuss our security ratings in our 2007 Annual Report on Form 10-K.

In June 2008, Moody's Investors Services (Moody's) affirmed the ratings of both Constellation Energy and BGE and changed the rating outlook for BGE to stable from negative due to better credit metrics for BGE and a more settled legislative and regulatory environment following passage of legislation relating to the Maryland settlement agreement discussed in more detail on page 16. Moody's maintained a negative rating outlook for Constellation Energy.

In April 2008, Fitch Ratings affirmed the ratings of both Constellation Energy and BGE and removed the ratings from Ratings Watch Negative upon the passage of legislation by the Maryland legislature relating to the Maryland settlement agreement discussed in more detail on page 16 of Notes to Consolidated Financial Statements.

We discuss the impact of our security ratings on our liquidity in more detail on page 46.

Available Sources of Funding

We continuously monitor our liquidity requirements and believe that our credit facilities and access to the capital markets provide sufficient liquidity to meet our business requirements. In addition to our cash balance, our existing credit facilities support cash borrowings and commercial paper programs under which we can issue short-term debt to fund our subsidiaries' operations. Our credit facilities also support the issuance of letters of credit. Currently, we use the facilities to issue letters of credit to primarily support our merchant energy business and to support the issuance of commercial paper to manage working capital needs of the business.

Significant changes in the prices of commodities, depending on hedging strategies we have employed, could require us to post additional letters of credit, and thereby reduce the overall amount available under our credit facilities or to post additional cash, and thereby reduce our available cash balance.

We expect to fund future acquisitions with an overall goal of maintaining a strong investment grade credit profile. We discuss our available sources of funding in more detail below.

Constellation Energy

At June 30, 2008, we have the following credit facilities available:

•: $3.85 billion expiring July 2012
•: $250 million expiring December 2008
•: $750 million expiring December 2008
•: $380 million expiring December 2008. This amended and extended a $500 million credit facility that was entered into in January 2008.
•: $150 million expiring December 2009
•: $350 million expiring September 2013

The $750 million, $150 million and $350 million credit facilities were entered into in June 2008. These facilities support the issuance of letters of credit and/or cash borrowings up to $5.7 billion collectively. At June 30, 2008, we had $4.3 billion in letters of credit issued and at the end of July 2008 we estimate that we had $3.6 billion in letters of credit issued under these facilities. In addition, at June 30, 2008, we had $145.7 million in commercial paper outstanding and at the end of July 2008 we had approximately $630 million in commercial paper outstanding under these facilities.

BGE

BGE currently maintains a $400.0 million five-year revolving credit facility expiring in 2011. BGE can borrow directly from the banks, use the facility to allow commercial paper to be issued or issue letters of credit. As of June 30, 2008 and July 31, 2008, BGE had $1.1 million in letters of credit issued under this facility. In addition, at June 30, 2008 BGE had no commercial paper outstanding and at the end of July 2008 BGE had approximately $200 million in commercial paper outstanding.

Capital Resources

Our estimated annual cash requirement amounts for the years 2008 and 2009 are shown in the table below.

We will continue to have cash requirements for:

•: working capital needs,
•: payments of interest, distributions, and dividends,
•: capital expenditures, and
•: the retirement of debt and redemption of preference stock.

Capital requirements for 2008 and 2009 include estimates of spending for existing and anticipated projects. We continuously review and modify those estimates. Actual requirements may vary from the estimates included in the table below because of a number of factors including:

•: regulation, legislation, and competition,
•: BGE load requirements,
•: environmental protection standards,
•: the type and number of projects selected for construction or acquisition,
•: the effect of market conditions on those projects,
•: the cost and availability of capital,
•: the availability of cash from operations, and
•: business decisions to invest in capital projects.

Our estimates are also subject to additional factors. Please see the Forward Looking Statements section on page 53 and Item 1A. Risk Factors section on page 51. We discuss the potential impact of environmental legislation and regulation in more detail in Business Environment section on page 27 and Item 1. Business—Environmental Matters section of our 2007 Annual Report on Form 10-K.

Calendar Year Estimates			2008		2009


			(In millions)
Nonregulated Capital Requirements:
	Merchant energy
		Generation plants	$	735	$	510
		Environmental controls		535		335
		Portfolio acquisitions/investments		170		115
		Technology/other		145		125
		Nuclear Fuel		200		270

	Total merchant energy capital requirements			1,785		1,355
	Other nonregulated capital requirements			135		65

Total nonregulated capital requirements				1,920		1,420

Regulated Capital Requirements:
	Regulated electric			400		465
	Regulated gas			80		95

Total regulated capital requirements				480		560

Total capital requirements			$	2,400	$	1,980

Capital Requirements

Merchant Energy Business

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

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

Regulated Electric and Gas

Regulated electric and gas construction expenditures primarily include new business construction needs and improvements to existing facilities, including projects to improve reliability and support demand response and conservation initiatives.

Funding for Capital Requirements

We discuss our funding for capital requirements in our 2007 Annual Report on Form 10-K.

Contractual Payment Obligations and Committed Amounts

We enter into various agreements that result in contractual payment obligations in connection with our business activities. These obligations primarily relate to our financing arrangements (such as long-term debt, preference stock, and operating leases), purchases of capacity and energy to support the growth in our merchant energy business activities, and purchases of fuel and transportation to satisfy the fuel requirements of our power generating facilities.

We detail our contractual payment obligations at June 30, 2008 in the following table:

			Payments

			2008		2009- 2010		2011- 2012		There- after		Total

			(In millions)
Contractual Payment Obligations
Long-term debt:¹
	Nonregulated
		Principal	$	1.3	$	501.9	$	744.2	$	2,280.9	$	3,528.3
		Interest		98.2		366.5		318.3		3,625.7		4,408.7

	Total			99.5		868.4		1,062.5		5,906.6		7,937.0
	BGE
		Principal		90.5		121.6		254.2		1,889.4		2,355.7
		Interest		69.3		264.6		246.4		1,423.8		2,004.1

	Total			159.8		386.2		500.6		3,313.2		4,359.8
BGE preference stock				—		—		—		190.0		190.0
Maryland settlement agreement				188.2		—		—		—		188.2
Operating leases²				319.2		504.3		324.1		577.5		1,725.1
Purchase obligations:³
	Purchased capacity and energy⁴			283.7		687.0		221.7		280.5		1,472.9
	Fuel and transportation			1,020.8		1,810.2		719.6		988.2		4,538.8
	Other			252.1		49.2		21.9		19.1		342.3
Other noncurrent liabilities:
	FIN 48 tax liability			—		2.4		30.9		13.2		46.5
	Pension benefits⁵			2.8		200.2		162.9		—		365.9
	Postretirement and postemployment benefits⁶			21.2		95.7		111.3		265.4		493.6

Total contractual payment obligations			$	2,347.3	$	4,603.6	$	3,155.5	$	11,553.7	$	21,660.1

1: Amounts in long-term debt reflect the original maturity date. Investors may require us to repay $339.8 million early through put options and remarketing features. Interest on variable rate debt is included based on the forward curve for interest rates.
2: Our operating lease commitments include future payment obligations under certain power purchase agreements as discussed further in Note 11 of our 2007 Annual Report on Form 10-K.
3: Contracts to purchase goods or services that specify all significant terms. Amounts related to certain purchase obligations are based on future purchase expectations which may differ from actual purchases.
4: Our contractual obligations for purchased capacity and energy are shown on a gross basis for certain transactions, including both the fixed payment portions of tolling contracts and estimated variable payments under unit-contingent power purchase agreements.
5: Amounts related to pension benefits reflect our current 5-year forecast of contributions for our qualified pension plans and participant payments for our nonqualified pension plans. Refer to Note 7 of our 2007 Annual Report on Form 10-K for more detail on our pension plans.
6: Amounts related to postretirement and postemployment benefits are for unfunded plans and reflect present value amounts consistent with the determination of the related liabilities recorded in our Consolidated Balance Sheets.

Liquidity Provisions

In many cases, customers of our merchant energy business rely on the creditworthiness of Constellation Energy. A decline below investment grade by Constellation Energy would negatively impact the business prospects of that operation.

We regularly review our liquidity needs to ensure that we have adequate facilities available to meet collateral requirements. This includes having liquidity available to meet margin requirements for our Customer Supply and Global Commodities activities, which can vary significantly due to market price changes, changes in margin requirements, and the level of our positions.

We have certain agreements that contain provisions that would require additional collateral upon significant credit rating decreases in senior unsecured debt of Constellation Energy. Decreases in Constellation Energy's credit ratings would not trigger an early payment on any of our credit facilities.

Under counterparty contracts related to our merchant energy activities, we are obligated to post collateral if Constellation Energy's senior unsecured credit ratings declined below established contractual levels. Based on contractual provisions at June 30, 2008, we estimate that if Constellation Energy's senior unsecured debt were downgraded we would have the following additional collateral obligations:

Credit Ratings Downgraded to	Level Below Current Rating		Incremental Obligations		Cumulative Obligations


	(In millions)
BBB/Baa2		1	$	386	$	386
BBB-/Baa3		2		983		1,369
Below investment grade		3		3,201		4,570

The estimated amounts above have increased compared to those reported in our quarterly report on Form 10-Q for the quarter ended March 31, 2008. This increase is due to significant increases in prices and changes in our positions at June 30, 2008 compared to March 31, 2008 and due to our calculation at March 31, 2008 incorrectly omitting certain contracts with downgrade provisions. Cumulative obligations for March 31, 2008 should have been reported as $129 million for a one-level downgrade, $844 million for a two-level downgrade and $3,234 million for a three-level downgrade, rather than $320 million, $626 million and $1,608 million, respectively. As of July 31, 2008, we estimate the cumulative obligation is $106 million for a one-level downgrade, $681 million for a two-level downgrade and $3,365 million for a three-level downgrade.

Based on market conditions and contractual obligations at the time of a downgrade, we could be required to post collateral in an amount that could exceed the amounts specified above, which could be material. We discuss our credit ratings in the Security Ratings section on page 44 and in our 2007 Annual Report on Form 10-K. We discuss our credit facilities in the Available Sources of Funding section on page 44.

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, 2008, the debt to capitalization ratios as defined in the credit agreements were no greater than 54%.

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, 2008, the debt to capitalization ratio for BGE as defined in this credit agreement was 52%.

Off-Balance Sheet Arrangements

We discuss our off-balance sheet arrangements in our 2007 Annual Report on Form 10-K.

At June 30, 2008, Constellation Energy had a total face amount of $17,264.4 million in guarantees outstanding, of which $15,962.3 million related to our merchant energy business. These amounts generally do not represent incremental consolidated Constellation Energy obligations; rather, they primarily represent parental guarantees of certain subsidiary obligations to third parties in order to allow our subsidiaries the flexibility needed to conduct business with counterparties without having to post other forms of collateral. Our calculated fair value of obligations for commercial transactions covered by these guarantees was $4,950.1 million at June 30, 2008, which represents the total amount the parent company could be required to fund based on June 30, 2008 market prices. For those guarantees related to our derivative liabilities, the fair value of the obligation is recorded in our Consolidated Balance Sheets. We believe it is unlikely that we would be required to perform or incur any losses associated with guarantees of our subsidiaries' obligations.

We discuss our other guarantees in the Notes to Consolidated Financial Statements on page 19.

Market Risk

Commodity Risk

We measure the sensitivity of the value of mark-to-market energy contracts of our Global Commodities operation to potential changes in market prices using value at risk. Value at risk represents the potential pre-tax loss in the fair value of our Global Commodities operation derivative assets and liabilities subject to mark-to-market accounting over one- and ten-day holding periods. We discuss value at risk in more detail in the Market Risk section of our 2007 Annual Report on Form 10-K. The table below is the value at risk associated with our Global Commodities operation's derivative assets and liabilities subject to mark-to-market accounting, including both trading and non-trading activities.

We discuss our mark-to-market results in more detail in the Mark-to-Market section beginning on page 34.

		Quarter Ended June 30, 2008


		(In millions)
99% Confidence Level, One-Day Holding Period
	Average	$	23.4
	High		33.8
95% Confidence Level, One-Day Holding Period
	Average		17.8
	High		25.7
95% Confidence Level, Ten-Day Holding Period
	Average		56.3
	High		81.4

The following table details our value at risk for the trading portion of our Global Commodities operation's derivative assets and liabilities subject to mark-to-market accounting over a one-day holding period at a 99% confidence level for the second quarter of 2008:

	Quarter Ended June 30, 2008


	(In millions)
Average	$	16.3
High		21.6

Due to the inherent limitations of statistical measures such as value at risk and the seasonality of changes in market prices, the value at risk calculation may not reflect the full extent of our commodity price and basis risk exposure. Additionally, actual changes in the value of options may differ from the value at risk calculated using a linear approximation inherent in our calculation method. As a result, actual changes in the fair value of derivative contracts subject to mark-to-market accounting could differ from the calculated value at risk, and such changes could have a material impact on our financial results.

To supplement our value at risk measure for market risk management, other nonstatistical measures of market risk are used. These measures include stress testing, gross and net open positions, position concentrations, and derivative sensitivities.

Wholesale Credit Risk

We actively monitor the credit portfolio of our Global Commodities operation to attempt to reduce the impact of potential counterparty default. The wholesale derivative and nonderivative portfolio of our Global Commodities operation had the following public credit ratings:




Rating
	Investment Grade¹	29	%	44	%
	Non-Investment Grade²	29		7
	Not Rated	42		49

1: Includes counterparties with an investment grade rating by at least one of the major credit rating agencies. If split rating exists, the lower rating is used.
2: The change is primarily due to increased credit exposures from higher commodity prices during the quarter ended June 30, 2008, rather than new business with non-investment grade counterparties.

We utilize internal credit ratings to evaluate the creditworthiness of our wholesale customers, including those companies that do not have public credit ratings. The "Not Rated" category in the table above includes counterparties that do not have public credit ratings for which we determine creditworthiness based on internal credit ratings. These counterparties include governmental entities, municipalities, cooperatives, power pools, and certain load-serving entities, marketers, and coal and freight suppliers.

The following table provides the breakdown of the credit quality of our wholesale business based on our internal credit ratings.




Investment Grade Equivalent	39	%	62	%
Non-Investment Grade	61		38

The decrease in wholesale credit quality during the first half of 2008 primarily reflects the growth of the coal and freight businesses and significantly higher global coal and freight prices, which increased our credit exposure to coal and freight counterparties. We discuss the impact of the commodity price increases, including coal, in more detail on page 28. As a result of the increased credit exposure to these counterparties, the credit quality of our wholesale portfolio declined.

By location, approximately 69% of our wholesale credit risk exposure is with domestic (U.S. and Canada) counterparties, and 31% is with international counterparties, which includes exposure to emerging markets such as Indonesia.

Our total exposure, net of collateral, to counterparties across our entire wholesale portfolio is $5.3 billion as of June 30, 2008. The top ten counterparties account for approximately 53% of our total exposure. As shown in the table on the next page, our largest single counterparty concentration is in the coal sector and grew significantly this quarter solely as a result of increasing price levels rather than the addition of new positions.

If a counterparty were to default on its contractual obligations and we were to liquidate all contracts with that entity, our potential credit loss would include the loss in value of these contracts. This would include contracts accounted for using the mark-to-market, hedge, and accrual accounting methods, the amount owed or due from settled transactions, and a reduction for any collateral held from the counterparty. In addition, if a counterparty were to default under an accrual contract that is currently favorable to us, we may recognize a material adverse impact on our results in the future delivery period to the extent that we are required to replace the contract that is in default with another contract at current market prices. To reduce our credit risk with counterparties, we attempt to enter into agreements that allow us to obtain collateral on a contingent basis, seek third-party guarantees of the counterparty's obligation, and enter into netting agreements that allow us to offset receivables and payables.

Our total exposure of $5.3 billion, net of collateral, includes both accrual positions prior to being settled and recorded in our Consolidated Balance Sheets and derivatives that are recorded at fair value in our Consolidated Balance Sheets. The portion of our wholesale credit risk related to transactions that are recorded in our Consolidated Balance Sheets primarily relates to open energy commodity positions from our Global Commodities operation that are accounted for using mark-to-market accounting, derivatives that qualify for designation as hedges under SFAS No. 133, as well as amounts owed by wholesale counterparties for transactions that settled but have not yet been paid.

The following table highlights the credit quality and exposures related to those activities recorded in our Consolidated Balance Sheets at June 30, 2008:

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


	(In millions)
Investment grade	$	3,204	$	1,558	$	1,646	—	$	—
Split rating		277		8		269	—		—
Non-investment grade		2,230		264		1,966	1		1,759
Internally rated—investment grade		474		68		406	—		—
Internally rated—non-investment grade		1,153		109		1,044	—		—

Total	$	7,338	$	2,007	$	5,331	1	$	1,759

Due to the possibility of extreme volatility in the prices of energy commodities and derivatives, the market value of contractual positions with individual counterparties could exceed established credit limits or collateral provided by those counterparties. If such a counterparty were then to fail to perform its obligations under its contract (for example, fail to deliver the electricity for which our Global Commodities operation had contracted), we could incur a loss that could have a material impact on our financial results. We discuss our actual credit losses in more detail in the Global Commodities section on page 33.

Interest Rate Risk, Retail Credit Risk, Foreign Currency Risk, and Equity Price Risk

We discuss our exposure to interest rate risk, retail credit risk, foreign currency risk, and equity price risk in the Market Risk section of our 2007 Annual Report on Form 10-K.

Item 3. Quantitative and Qualitative Disclosures About Market Risk

We discuss the following information related to our market risk:

•: SFAS No. 133 hedging activities in the Notes to Consolidated Financial Statements beginning on page 21,
•: activities of our Global Commodities operation in the Merchant Energy Business section of Management's Discussion and Analysis on page 33,
•: evaluation of commodity and credit risk in the Market Risk section of Management's Discussion and Analysis beginning on page 47, and
•: changes to our business environment in the Business Environment section of Management's Discussion and Analysis on page 27.

Items 4 and 4(T). Controls and Procedures

A control system, no matter how well conceived and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. Because of the inherent limitations in all control systems, no evaluation of controls can provide absolute assurance that all control issues and instances of fraud, if any, within Constellation Energy or BGE have been detected. These inherent limitations include errors by personnel in executing controls due to faulty judgment or simple mistakes, which could occur in situations such as when personnel performing controls are new to a job function or when inadequate resources are applied to a process. Additionally, controls can be circumvented by the individual acts of some persons or by collusion of two or more people.

The design of any system of controls also is based in part upon certain assumptions about the likelihood of future events, and there can be no absolute assurance that any design will succeed in achieving its stated goals under all potential future conditions; over time, controls may become inadequate because of changes in conditions or personnel, or the degree of compliance with the policies or procedures may deteriorate. Because of the inherent limitations in a cost-effective control system, misstatements due to error or fraud may occur and not be detected.

Evaluation of Disclosure Controls and Procedures

The principal executive officers and principal financial officer of both Constellation Energy and BGE have evaluated the effectiveness of the disclosure controls and procedures (as such term is defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934, as amended (the "Exchange Act")) as of the end of the fiscal quarter covered by this quarterly report (the "Evaluation Date"). Based on such evaluation, such officers have concluded that, as of the Evaluation Date, Constellation Energy's and BGE's disclosure controls and procedures are effective.

Changes in Internal Control over Financial Reporting

During the quarter ended June 30, 2008, there has been no change in either Constellation Energy's or BGE's internal control over financial reporting (as such term is defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act) that has materially affected, or is reasonably likely to materially affect, either Constellation Energy's or BGE's internal control over financial reporting.

PART II. OTHER INFORMATION

Item 1. Legal Proceedings

We discuss our Legal Proceedings in the Notes to Consolidated Financial Statements beginning on page 20.

Item 1A. Risk Factors

You should consider carefully the following risks, along with the risks described under Item 1A. Risk Factors in our 2007 Annual Report on Form 10-K and the other information contained in this Form 10-Q. The risks and uncertainties described below and in our 2007 Annual Report on Form 10-K are not the only ones that may affect us. Additional risks and uncertainties also may adversely affect our business and operations including those discussed in Item 2. Management's Discussion and Analysis. If any of the following events occur, our business and financial results could be materially adversely affected.

We, and BGE in particular, are subject to extensive local, state and federal regulation that could affect our operations and costs.

We are subject to regulation by federal and state governmental entities, including the Federal Energy Regulatory Commission, the Nuclear Regulatory Commission, the Maryland PSC and the utility commissions of other states in which we have operations. In addition, changing governmental policies and regulatory actions can have a significant impact on us. Regulations can affect, for example, allowed rates of return, requirements for plant operations, recovery of costs, limitations on dividend payments and the regulation or reregulation of wholesale and retail competition (including but not limited to retail choice and transmission costs).

BGE's distribution rates are subject to regulation by the Maryland PSC, and such rates are effective until new rates are approved. If the Maryland PSC does not approve new rates, BGE might not be able to recover certain costs it incurs. In addition, limited categories of costs are recovered through adjustment charges that are periodically reset to reflect current and projected costs. Inability to recover material costs not included in rates or adjustment clauses, including increases in uncollectible customer accounts that may result from higher gas and electric costs, could have an adverse effect on our, or BGE's, cash flow and financial position.

Energy legislation enacted in Maryland in June 2006 and April 2007 mandated that the Maryland PSC review Maryland's deregulated electricity market. Although the settlement agreement reached with the State of Maryland terminated certain studies relating to the 1999 deregulation settlement, the State of Maryland and the Maryland PSC is still undertaking a review of the Maryland electric industry and market structure to consider various options for providing standard offer service to residential customers, including reregulation. We cannot at this time predict the final outcome of this review or how such outcome may affect our, or BGE's financial results, but it could be material.

The regulatory process may restrict our ability to grow earnings in certain parts of our business, cause delays in or affect business planning and transactions and increase our, or BGE's, costs.

Changes in the prices of commodities impact our liquidity requirements.

As a result of the nature of our business, we are exposed to the impact of market fluctuations in the price and transportation costs of electricity, natural gas, coal, uranium and other commodities. We seek to mitigate the effect of these fluctuations through various hedging strategies, which may require the posting of collateral by both us and our counterparties. Changes in the prices of commodities and initial margin requirements for exchange-traded contracts can affect the amount of collateral that must be posted, depending on the particular hedge position. As a result, significant changes in the prices of commodities and margin requirements for exchange-traded contracts could require us to post additional collateral from time to time, which could adversely affect our overall liquidity and ability to finance our operations, which, in turn, could adversely affect our credit ratings.

Item 2. Issuer Purchases of Equity Securities

The following table discloses purchases of shares of our common stock made by us or on our behalf for the periods shown below.

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


April 1 – April 30, 2008	320	$	93.01	—	$	750 million
May 1 – May 31, 2008	119		84.93	—		750 million
June 1 – June 30, 2008	48		85.95	—		750 million

Total	487	$	90.34	—		—

1 Represents shares surrendered by employees to satisfy tax withholding obligations on vested restricted stock.

2 In October 2007, our board of directors approved a common share repurchase program for up to $1 billion of our outstanding common shares. The program is expected to be executed over the 24 months following approval in a manner that preserves flexibility to pursue additional strategic investment opportunities.

Item 5. Other Information

Forward Looking Statements

We make statements in this report that are considered forward looking statements within the meaning of the Securities Exchange Act of 1934. Sometimes these statements will contain words such as "believes," "anticipates," "expects," "intends," "plans," and other similar words. We also disclose non-historical information that represents management's expectations, which are based on numerous assumptions. These statements and projections are not guarantees of our future performance and are subject to risks, uncertainties, and other important factors that could cause our actual performance or achievements to be materially different from those we project. These risks, uncertainties, and factors include, but are not limited to:

•: the timing and extent of changes in commodity prices and volatilities for energy and energy related products including coal, natural gas, oil, electricity, nuclear fuel, freight, and emission allowances, and the impact of such changes on our liquidity requirements,
•: the liquidity and competitiveness of wholesale markets for energy commodities,
•: the effect of weather and general economic and business conditions on energy supply, demand, and prices,
•: the ability to attract and retain customers in our Customer Supply activities and to adequately forecast their energy usage,
•: the timing and extent of deregulation of, and competition in, the energy markets, and the rules and regulations adopted in those markets,
•: uncertainties associated with estimating natural gas reserves, developing properties, and extracting natural gas,
•: regulatory or legislative developments federally, in Maryland, or in other states that affect deregulation, the price of energy, transmission or distribution rates and revenues, demand for energy, or increases in costs, including costs related to nuclear power plants, safety, or environmental compliance,
•: the ability of our regulated and nonregulated businesses to comply with complex and/or changing market rules and regulations,
•: the ability of BGE to recover all its costs associated with providing customers service,
•: the conditions of the capital markets, interest rates, foreign exchange rates, availability of credit facilities to support business requirements, liquidity, and general economic conditions, as well as Constellation Energy and BGE's ability to maintain their current credit ratings,
•: the effectiveness of Constellation Energy's and BGE's risk management policies and procedures and the ability and willingness of our counterparties to satisfy their financial and performance commitments,
•: operational factors affecting commercial operations of our generating facilities (including nuclear facilities) and BGE's transmission and distribution facilities, including catastrophic weather-related damages, unscheduled outages or repairs, unanticipated changes in fuel costs or availability, unavailability of coal or gas transportation or electric transmission services, workforce issues, terrorism, liabilities associated with catastrophic events, and other events beyond our control,
•: the actual outcome of uncertainties associated with assumptions and estimates using judgment when applying critical accounting policies and preparing financial statements, including factors that are estimated in determining the fair value of energy contracts, such as the ability to obtain market prices and, in the absence of verifiable market prices, the appropriateness of models and model inputs (including, but not limited to, estimated contractual load obligations, unit availability, forward commodity prices, interest rates, correlation and volatility factors),
•: changes in accounting principles or practices,
•: losses on the sale or write down of assets due to impairment events or changes in management intent with regard to either holding or selling certain assets,
•: the ability to successfully identify and complete acquisitions and sales of businesses and assets, and
•: cost and other effects of legal and administrative proceedings that may not be covered by insurance, including environmental liabilities.

Given these uncertainties, you should not place undue reliance on these forward looking statements. Please see the other sections of this report and our other periodic reports filed with the Securities and Exchange Commission for more information on these factors. These forward looking statements represent our estimates and assumptions only as of the date of this report.

Changes may occur after that date, and neither Constellation Energy nor BGE assume responsibility to update these forward looking statements.

Item 6. Exhibits


Exhibit No. 3(a)		Articles of Amendment to the Charter of Constellation Energy Group, Inc. as of July 21, 2008.
Exhibit No. 3(b)	*	Bylaws of Constellation Energy Group, Inc., as amended to July 18, 2008 (Designated as Exhibit No. 3 to the Current Report on Form 8-K dated July 18, 2008, File No. 1-12869.)
Exhibit No. 4(a)		Indenture dated June 19, 2008, between Constellation Energy Group, Inc. and Deutsche Bank Trust Company Americas, as trustee.
Exhibit No. 4(b)	*	First Supplemental Indenture between Constellation Energy Group, Inc. and Deutsche Bank Trust Company Americas, as trustee, dated as of June 27, 2008 (Designated as Exhibit No. 4(a) to the Current Report on Form 8-K dated June 30, 2008, File No. 12869).
Exhibit No. 4(c)	*	Replacement Capital Covenant dated June 27, 2008 (Designated as Exhibit No. 4(b) to the Current Report on Form 8-K dated June 30, 2008, File No. 1-12869).
Exhibit No. 10(a)		Constellation Energy Group, Inc. Executive Supplemental Benefits Plan, as amended and restated.
Exhibit No. 12(a)		Constellation Energy Group, Inc. Computation of Ratio of Earnings to Fixed Charges.
Exhibit No. 12(b)		Baltimore Gas and Electric Company Computation of Ratio of Earnings to Fixed Charges and Computation of Ratio of Earnings to Combined Fixed Charges and Preferred and Preference Dividend Requirements.
Exhibit No. 31(a)		Certification of Chairman of the Board, President, and Chief Executive Officer of Constellation Energy Group, Inc. pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
Exhibit No. 31(b)		Certification of Executive Vice President and Chief Financial Officer of Constellation Energy Group, Inc. pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
Exhibit No. 31(c)		Certification of President and Chief Executive Officer of Baltimore Gas and Electric Company pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
Exhibit No. 31(d)		Certification of Senior Vice President and Chief Financial Officer of Baltimore Gas and Electric Company pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
Exhibit No. 32(a)		Certification of Chairman of the Board, President, and Chief Executive Officer of Constellation Energy Group, Inc. pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
Exhibit No. 32(b)		Certification of Executive Vice President and Chief Financial Officer of Constellation Energy Group, Inc. pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
Exhibit No. 32(c)		Certification of President and Chief Executive Officer of Baltimore Gas and Electric Company pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
Exhibit No. 32(d)		Certification of Senior Vice President and Chief Financial Officer of Baltimore Gas and Electric Company pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

*: Incorporated by reference

SIGNATURE

Pursuant to the requirements of the Securities Exchange Act of 1934, each registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.


				CONSTELLATION ENERGY GROUP, INC. (Registrant)
				BALTIMORE GAS AND ELECTRIC COMPANY (Registrant)
Date: August 11, 2008				/s/ JOHN R. COLLINS John R. Collins, Executive Vice President of Constellation Energy Group, Inc. and Senior Vice President of Baltimore Gas and Electric Company, and as Principal Financial Officer of each Registrant

QuickLinks

TABLE OF CONTENTS
PART 1—FINANCIAL INFORMATION
Item 1—Financial Statements
CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED)
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)
CONSOLIDATED BALANCE SHEETS
CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)
CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED)
CONSOLIDATED BALANCE SHEETS
CONSOLIDATED BALANCE SHEETS
CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Item 2. Management's Discussion
Introduction and Overview
Strategy
Business Environment
Events of 2008
Asset Sales
Financing Activities
Maryland Settlement Agreement
Commodity Prices
Results of Operations for the Quarter and Six Months Ended June 30, 2008 Compared with the Same Periods of 2007
Financial Condition
Capital Resources
Item 3. Quantitative and Qualitative Disclosures About Market Risk
Items 4 and 4(T). Controls and Procedures
PART II. OTHER INFORMATION
Item 1. Legal Proceedings
Item 1A. Risk Factors
Item 2. Issuer Purchases of Equity Securities
Item 5. Other Information
Item 6. Exhibits
SIGNATURE