10-Q 1 a2140827z10-q.htm 10-Q

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TABLE OF CONTENTS

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

FORM 10-Q

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

For the quarterly period ended June 30, 2004

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)

750 E. PRATT STREET, BALTIMORE, MARYLAND 21202
(Address of principal executive offices) (Zip Code)

410-783-2800

(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 an accelerated filer Yes ý No o

Indicate by check mark whether Baltimore Gas and Electric Company is an accelerated filer Yes o No ý

COMMON STOCK, WITHOUT PAR VALUE 175,463,780 SHARES OUTSTANDING OF
CONSTELLATION ENERGY GROUP, INC. ON JULY 30, 2004.

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


Part I—Financial Information
	Item 1—Financial Statements
		Constellation Energy Group, Inc. and Subsidiaries
		Consolidated Statements of Income
		Consolidated Statements of Comprehensive Income
		Consolidated Balance Sheets
		Consolidated Statements of Cash Flows
		Baltimore Gas and Electric Company and Subsidiaries
		Consolidated Statements of Income
		Consolidated Statements of Comprehensive Income
		Consolidated Balance Sheets
		Consolidated Statements of Cash Flows
		Notes to Consolidated Financial Statements
	Item 2—Management's Discussion and Analysis of Financial Condition and Results of Operations
		Introduction and Overview
		Strategy
		Business Environment
		Critical Accounting Policies
		Events of 2004
		Results of Operations
		Financial Condition
		Capital Resources
		Market Risk
		Other Matters
	Item 3—Quantitative and Qualitative Disclosures About Market Risk
	Item 4—Controls and Procedures
Part II—Other Information
	Item 1—Legal Proceedings
	Item 4—Submission of Matters to a Vote of Security Holders
	Item 5—Other Information
	Item 6—Exhibits and Reports on Form 8-K
	Signature

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,
		2004			2003			2004			2003

		(In millions, except per share amounts)
Revenues
	Nonregulated revenues	$	2,204.3		$	1,692.2		$	4,438.5		$	3,233.8
	Regulated electric revenues		477.2			436.9			961.6			923.2
	Regulated gas revenues		111.5			137.5			429.4			435.7

	Total revenues		2,793.0			2,266.6			5,829.5			4,592.7
Expenses
	Operating expenses		2,393.9			1,845.4			4,997.3			3,821.6
	Impairment losses and other costs		2.6			—			2.6			—
	Workforce reduction costs		—			0.7			—			1.4
	Depreciation and amortization		130.2			116.9			253.2			227.9
	Accretion of asset retirement obligations		12.4			10.7			23.5			21.3
	Taxes other than income taxes		62.4			64.3			127.3			130.0

	Total expenses		2,601.5			2,038.0			5,403.9			4,202.2
Net Gain on Sales of Investments and Other Assets			4.4			0.5			5.9			14.2

Income from Operations			195.9			229.1			431.5			404.7
Other Income			5.5			6.0			10.3			14.9
Fixed Charges
	Interest expense		83.5			83.5			168.3			165.8
	Interest capitalized and allowance for borrowed funds used during construction		(3.2	)		(2.8	)		(5.8	)		(7.2	)
	BGE preference stock dividends		3.3			3.3			6.6			6.6

	Total fixed charges		83.6			84.0			169.1			165.2

Income from Continuing Operations Before Income Taxes			117.8			151.1			272.7			254.4
Income Taxes			(13.1	)		54.3			29.3			90.6

Income from Continuing Operations and Before Cumulative Effects of Changes in Accounting Principles			130.9			96.8			243.4			163.8
	Loss from discontinued operations, net of income taxes of $2.6 and $26.4, respectively		(2.7	)		—			(49.0	)		—
	Cumulative effects of changes in accounting principles, net of income taxes of $119.5		—			—			—			(198.4	)

Net Income (Loss)		$	128.2		$	96.8		$	194.4		$	(34.6	)

Earnings (Loss) Applicable to Common Stock		$	128.2		$	96.8		$	194.4		$	(34.6	)

Average Shares of Common Stock Outstanding—Basic			168.7			165.8			168.4			165.4
Average Shares of Common Stock Outstanding—Diluted			169.6			166.2			169.4			165.5
Earnings Per Common Share from Continuing Operations and Before Cumulative Effects of Changes in Accounting Principles—Basic		$	0.78		$	0.58		$	1.45		$	0.99
	Loss from discontinued operations—Basic		(0.02	)		—			(0.30	)		—
	Cumulative effects of changes in accounting principles—Basic		—			—			—			(1.20	)

Earnings (Loss) Per Common Share—Basic		$	0.76		$	0.58		$	1.15		$	(0.21	)

Earnings Per Common Share—from Continuing Operations and Before Cumulative Effects of Changes in Accounting Principles—Diluted		$	0.77		$	0.58		$	1.44		$	0.99
	Loss from discontinued operations—Diluted		(0.01	)		—			(0.29	)		—
	Cumulative effects of changes in accounting principles—Diluted		—			—			—			(1.20	)

Earnings (Loss) Per Common Share—Diluted		$	0.76		$	0.58		$	1.15		$	(0.21	)

Dividends Declared Per Common Share		$	0.285		$	0.260		$	0.570		$	0.520

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)

Constellation Energy Group, Inc. and Subsidiaries

			Three Months Ended June 30,						Six Months Ended June 30,
			2004			2003			2004			2003

			(In millions)
Net Income (Loss)			$	128.2		$	96.8		$	194.4		$	(34.6	)
	Other comprehensive income (OCI)
		Reclassification of net losses (gains) on sales of securities from OCI to net income, net of taxes		—			2.3			(0.3	)		(0.3	)
		Reclassification of net gains on hedging instruments from OCI to net income, net of taxes		(44.4	)		(3.7	)		(69.2	)		(9.7	)
		Net unrealized gains on hedging instruments, net of taxes		102.5			13.5			198.8			7.5
		Net unrealized (losses) gains on securities, net of taxes		(12.9	)		26.5			14.0			14.8

Comprehensive Income (Loss)			$	173.4		$	135.4		$	337.7		$	(22.3	)

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,* 2004*			December 31, 2003

			(In millions)
Assets
	Current Assets
		Cash and cash equivalents	$	457.0		$	721.3
		Accounts receivable (net of allowance for uncollectibles of $40.7 and $51.7, respectively)		1,206.8			1,563.0
		Mark-to-market energy assets		514.1			488.3
		Risk management assets		588.0			249.5
		Materials and supplies		217.6			203.2
		Fuel stocks		177.4			186.7
		Other		147.6			221.4

		Total current assets		3,308.5			3,633.4

	Investments and Other Assets
		Nuclear decommissioning trust funds		979.8			736.1
		Investments in qualifying facilities and power projects		319.4			332.6
		Mark-to-market energy assets		368.5			261.9
		Risk management assets		274.3			158.4
		Goodwill		142.5			144.0
		Other		318.3			343.8

		Total investments and other assets		2,402.8			1,976.8

	Property, Plant and Equipment
		Nonregulated property, plant and equipment		8,495.2			8,110.0
		Regulated property, plant and equipment		5,340.7			5,266.7
		Nuclear fuel (net of amortization)		229.9			202.9
		Accumulated depreciation		(4,078.5	)		(3,978.1	)

		Net property, plant and equipment		9,987.3			9,601.5

	Deferred Charges
		Regulatory assets (net)		195.9			229.5
		Other		164.6			149.6

		Total deferred charges		360.5			379.1

	Total Assets		$	16,059.1		$	15,590.8

* 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,* 2004*			December 31, 2003

			(In millions)
Liabilities and Equity
	Current Liabilities
		Short-term borrowings	$	4.5		$	9.6
		Current portion of long-term debt		534.5			343.2
		Accounts payable		705.5			1,149.2
		Customer deposits and collateral		318.5			181.7
		Mark-to-market energy liabilities		539.9			474.6
		Risk management liabilities		157.1			134.6
		Other		470.1			542.1

		Total current liabilities		2,730.1			2,835.0

	Deferred Credits and Other Liabilities
		Deferred income taxes		1,474.0			1,384.4
		Asset retirement obligations		794.7			595.9
		Mark-to-market energy liabilities		354.3			258.0
		Risk management liabilities		407.5			170.1
		Postretirement and postemployment benefits		372.6			361.8
		Net pension liability		196.8			225.7
		Deferred investment tax credits		74.8			78.4
		Other		189.7			198.4

		Total deferred credits and other liabilities		3,864.4			3,272.7

	Long-term Debt
		Long-term debt of Constellation Energy		3,350.0			3,350.0
		Long-term debt of nonregulated businesses		383.2			389.2
		First refunding mortgage bonds of BGE		351.1			476.1
		Other long-term debt of BGE		919.6			919.6
		6.20% deferrable interest subordinated debentures due October 15, 2043 to BGE wholly owned BGE Capital Trust II relating to trust preferred securities		257.7			257.7
		Unamortized discount and premium		(12.0	)		(10.2	)
		Current portion of long-term debt		(534.5	)		(343.2	)

		Total long-term debt		4,715.1			5,039.2

	Minority Interests			118.8			113.4
	BGE Preference Stock Not Subject to Mandatory Redemption			190.0			190.0
	Common Shareholders' Equity
		Common stock		2,237.9			2,179.8
		Retained earnings		2,180.7			2,081.9
		Accumulated other comprehensive income (loss)		22.1			(121.2	)

		Total common shareholders' equity		4,440.7			4,140.5

	Commitments, Guarantees, and Contingencies (see Notes)
	Total Liabilities and Equity		$	16,059.1		$	15,590.8

* 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,				2004			2003

				(In millions)
Cash Flows From Operating Activities
	Net income (loss)			$	194.4		$	(34.6	)
	Adjustments to reconcile to net cash provided by operating activities
		Loss from discontinued operations			49.0			—
		Cumulative effects of changes in accounting principles			—			198.4
		Depreciation and amortization			319.5			293.4
		Accretion of asset retirement obligations			23.5			21.3
		Deferred income taxes			56.0			33.6
		Investment tax credit adjustments			(3.6	)		(3.7	)
		Deferred fuel costs			10.9			(4.0	)
		Pension and postemployment benefits			(22.4	)		(86.7	)
		Net gain on sales of investments and other assets			(5.9	)		(14.2	)
		Impairment losses and other costs			2.6			—
		Workforce reduction costs			—			1.4
		Equity in earnings of affiliates less than dividends received			18.2			20.1
		Changes in
			Accounts receivable		374.7			(332.4	)
			Mark-to-market energy assets and liabilities		35.8			101.9
			Risk management assets and liabilities		(0.6	)		(56.7	)
			Materials, supplies and fuel stocks		3.2			(9.5	)
			Other current assets		61.1			(57.9	)
			Accounts payable		(453.5	)		238.5
			Other current liabilities		19.1			123.5
			Other		(20.7	)		(48.1	)

	Net cash provided by operating activities				661.3			384.3

Cash Flows From Investing Activities
	Acquisitions, net of cash acquired				(430.0	)		(517.3	)
	Purchases of property, plant and equipment				(322.0	)		(321.1	)
	Contributions to nuclear decommissioning trust funds				(13.2	)		(8.8	)
	Proceeds from sale of discontinued operations				72.7			—
	Sales of investments and other assets				14.1			102.8
	Other investments				(10.1	)		(60.2	)

	Net cash used in investing activities				(688.5	)		(804.6	)

Cash Flows From Financing Activities
	Net (maturity) issuance of short-term borrowings				(5.1	)		0.9
	Proceeds from issuance of
		Common stock			30.5			49.6
		Long-term debt			—			740.6
	Repayment of long-term debt				(172.4	)		(150.5	)
	Common stock dividends paid				(91.4	)		(82.4	)
	Other				1.3			(1.9	)

	Net cash (used in) provided by financing activities				(237.1	)		556.3

Net (Decrease) Increase in Cash and Cash Equivalents					(264.3	)		136.0
Cash and Cash Equivalents at Beginning of Period					721.3			615.0

Cash and Cash Equivalents at End of Period				$	457.0		$	751.0

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,
			2004			2003			2004			2003

			(In millions)
Revenues
	Electric revenues		$	477.2		$	437.0		$	961.6		$	923.3
	Gas revenues			112.6			140.0			432.1			443.6

	Total revenues			589.8			577.0			1,393.7			1,366.9
Expenses
	Operating expenses
		Electricity purchased for resale		254.3			237.2			494.7			480.8
		Gas purchased for resale		59.5			86.3			275.5			289.4
		Operations and maintenance		109.2			88.7			204.4			168.7
		Workforce reduction costs		—			0.2			—			0.5
	Depreciation and amortization			60.7			56.0			120.6			111.9
	Taxes other than income taxes			40.5			39.4			83.1			81.8

	Total expenses			524.2			507.8			1,178.3			1,133.1

Income from Operations				65.6			69.2			215.4			233.8
Other Income				—			0.7			1.0			1.1
Fixed Charges
	Interest expense			24.3			29.1			49.7			59.1
	Allowance for borrowed funds used during construction			(0.2	)		(0.5	)		(0.5	)		(1.0	)

	Total fixed charges			24.1			28.6			49.2			58.1

Income Before Income Taxes				41.5			41.3			167.2			176.8
Income Taxes				16.3			16.3			66.0			70.0

Net Income				25.2			25.0			101.2			106.8
Preference Stock Dividends				3.3			3.3			6.6			6.6

Earnings Applicable to Common Stock			$	21.9		$	21.7		$	94.6		$	100.2

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)

Baltimore Gas and Electric Company and Subsidiaries

			Three Months Ended June 30,					Six Months Ended June 30,
			2004			2003		2004			2003

			(In millions)
Net Income			$	21.9		$	21.7	$	94.6		$	100.2
	Other comprehensive income
		Reclassification of unrealized gain on hedging instruments from OCI to net income, net of taxes		(0.1	)		—		(0.1	)		—
		Unrealized gain on hedging instruments, net of taxes		—			0.8		—			0.8

Comprehensive Income			$	21.8		$	22.5	$	94.5		$	101.0

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,* 2004*			December 31, 2003

				(In millions)
Assets
	Current Assets
		Cash and cash equivalents		$	8.6		$	11.0
		Accounts receivable (net of allowance for uncollectibles of $12.2 and $10.7, respectively)			327.4			354.8
		Investment in cash pool, affiliated company			247.7			230.2
		Accounts receivable, affiliated companies			1.5			4.5
		Fuel stocks			61.7			62.8
		Materials and supplies			33.4			29.9
		Prepaid taxes other than income taxes			0.2			42.8
		Other			30.3			9.9

		Total current assets			710.8			745.9

	Other Assets
		Receivable, affiliated company			158.3			131.6
		Other			92.9			90.4

		Total other assets			251.2			222.0

	Utility Plant
		Plant in service
			Electric		3,688.3			3,599.3
			Gas		1,075.6			1,064.7
			Common		477.2			467.7

			Total plant in service		5,241.1			5,131.7
		Accumulated depreciation			(1,863.2	)		(1,807.7	)

		Net plant in service			3,377.9			3,324.0
		Construction work in progress			94.4			130.5
		Plant held for future use			5.2			4.5

		Net utility plant			3,477.5			3,459.0

	Deferred Charges
		Regulatory assets (net)			195.9			229.5
		Other			47.8			50.2

		Total deferred charges			243.7			279.7

	Total Assets			$	4,683.2		$	4,706.6

* 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,* 2004*			December 31, 2003

			(In millions)
Liabilities and Equity
	Current Liabilities
		Current portion of long-term debt	$	224.0		$	330.6
		Accounts payable		78.6			111.2
		Accounts payable, affiliated companies		317.3			151.7
		Customer deposits		61.6			59.7
		Accrued taxes		5.4			33.0
		Accrued interest		22.8			22.3
		Other		31.8			43.3

		Total current liabilities		741.5			751.8

	Deferred Credits and Other Liabilities
		Deferred income taxes		595.8			585.8
		Postretirement and postemployment benefits		280.2			279.2
		Other		40.3			49.5

		Total deferred credits and other liabilities		916.3			914.5

	Long-term Debt
		First refunding mortgage bonds of BGE		351.1			476.1
		Other long-term debt of BGE		919.6			919.6
		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		(3.5	)		(4.1	)
		Current portion of long-term debt		(224.0	)		(330.6	)

		Total long-term debt		1,325.9			1,343.7

	Minority Interest			18.7			18.9
	Preference Stock Not Subject to Mandatory Redemption			190.0			190.0
	Common Shareholder's Equity
		Common stock		912.2			912.2
		Retained earnings		577.9			574.7
		Accumulated other comprehensive income		0.7			0.8

		Total common shareholder's equity		1,490.8			1,487.7

	Commitments, Guarantees, and Contingencies (see Notes)
	Total Liabilities and Equity		$	4,683.2		$	4,706.6

* 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)

Baltimore Gas and Electric Company and Subsidiaries

Six Months Ended June 30,				2004			2003

				(In millions)
Cash Flows From Operating Activities
	Net income			$	101.2		$	106.8
	Adjustments to reconcile to net cash provided by operating activities
		Depreciation and amortization			122.2			113.4
		Deferred income taxes			10.7			19.4
		Investment tax credit adjustments			(0.9	)		(0.9	)
		Deferred fuel costs			10.9			(4.0	)
		Pension and postemployment benefits			(24.1	)		(69.7	)
		Workforce reduction costs			—			0.5
		Allowance for equity funds used during construction			(0.9	)		(1.7	)
		Changes in
			Accounts receivable		27.4			34.6
			Receivables, affiliated companies		3.0			107.0
			Materials, supplies, and fuel stocks		(2.4	)		(14.5	)
			Other current assets		22.2			31.6
			Accounts payable		(32.6	)		(20.7	)
			Accounts payable, affiliated companies		165.6			35.7
			Other current liabilities		(36.7	)		(13.5	)
			Other		(7.6	)		7.0

	Net cash provided by operating activities				358.0			331.0

Cash Flows From Investing Activities
	Utility construction expenditures (excluding AFC)				(124.9	)		(100.4	)
	Investment in cash pool at parent				(17.5	)		(236.7	)
	Sales of investments and other assets				4.9			—
	Other				—			0.4

	Net cash used in investing activities				(137.5	)		(336.7	)

Cash Flows From Financing Activities
	Distribution to parent				(91.4	)		(38.1	)
	Proceeds from issuance of long-term debt				—			196.8
	Repayment of long-term debt				(124.9	)		(150.3	)
	Preference stock dividends paid				(6.6	)		(6.6	)
	Other				—			1.2

	Net cash (used in) provided by financing activities				(222.9	)		3.0

Net Decrease in Cash and Cash Equivalents					(2.4	)		(2.7	)
Cash and Cash Equivalents at Beginning of Period					11.0			10.2

Cash and Cash Equivalents at End of Period				$	8.6		$	7.5

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

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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 presentation of the financial position and 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.

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 were 0.9 million consisting of stock options for the quarter ended June 30, 2004. Stock options to purchase approximately 1.5 million shares during the quarter ended June 30, 2004 were not dilutive and were excluded from the computation of diluted EPS for that period. Our dilutive common stock equivalent shares were 0.4 million consisting of stock options for the quarter ended June 30, 2003. Stock options to purchase approximately 1.2 million shares during the quarter ended June 30, 2003 were not dilutive and were excluded from the computation of diluted EPS for that period.

Our dilutive common stock equivalent shares were 1.0 million consisting of stock options for the six months ended June 30, 2004. Stock options to purchase approximately 1.0 million shares during the six months ended June 30, 2004 were not dilutive and were excluded from the computation of diluted EPS for that period. Our dilutive common stock equivalent shares were 0.1 million consisting of stock options for the six months ended June 30, 2003. Stock options to purchase approximately 2.7 million shares during the six months ended June 30, 2003 were not dilutive and were excluded from the computation of diluted EPS for that period.

Stock-Based Compensation

Under our long-term incentive plans, we granted stock options, performance-based stock units, performance-based restricted stock, service-based restricted stock, and equity to officers, key employees, and members of the Board of Directors. As permitted by Statement of Financial Accounting Standards (SFAS) No. 123, Accounting for Stock-Based Compensation, we measure our stock-based compensation using the intrinsic value method in accordance with Accounting Principles Board Opinion (APB) No. 25, Accounting for Stock Issued to Employees, and related interpretations. We discuss these plans and accounting further in Note 14 of our 2003 Annual Report on Form 10-K.

The following table illustrates the effect on net income and earnings per share had we applied the fair value recognition provision of SFAS No. 123 to all outstanding stock options and stock awards in each period.

		Quarter Ended June 30,						Six Months Ended June 30,
		2004			2003			2004			2003

		(In millions, except per share amounts)
Net income (loss), as reported		$	128.2		$	96.8		$	194.4		$	(34.6	)
Add: Stock-based compensation expense determined under intrinsic value method and included in reported net income (loss), net of related tax effects			3.2			3.1			5.3			4.1
Deduct: Stock-based compensation expense determined under fair value based method for all awards, net of related tax effects			(5.3	)		(5.4	)		(8.9	)		(8.5	)

Pro-forma net income (loss)		$	126.1		$	94.5		$	190.8		$	(39.0	)

Earnings (loss) per share:
	Basic – as reported	$	0.76		$	0.58		$	1.15		$	(0.21	)
	Basic – pro forma	$	0.75		$	0.57		$	1.13		$	(0.24	)
	Diluted – as reported	$	0.76		$	0.58		$	1.15		$	(0.21	)
	Diluted – pro forma	$	0.74		$	0.57		$	1.13		$	(0.24	)

Impairment Losses and Other Costs

In the second quarter of 2004, our other nonregulated businesses recognized an impairment loss of $2.6 million pre-tax, or $1.6 million after-tax, related to an other than temporary decline in fair value of one of our financial investments.

Accretion of Asset Retirement Obligations

SFAS No. 143, Accounting for Asset Retirement Obligations, provides the accounting requirements for recognizing an estimated liability for legal obligations associated with the retirement of tangible long-lived assets. We measure the liability at fair value when incurred and capitalize a corresponding amount as part of the book value of the related long-lived assets. The increase in the capitalized cost is included in determining depreciation expense over the estimated useful life of these assets. Since the fair value of the asset retirement obligations is determined using a present value approach, accretion of the liability due to the passage of time is recognized each period to "Accretion of asset retirement obligations" in our Consolidated Statements of Income until the settlement of the liability. We record a gain or loss when the liability is settled after retirement.

The change in our "Asset retirement obligations" liability during 2004 was as follows:


	(In millions)
Liability at January 1, 2004	$	595.9
Accretion expense		23.5
Liabilities incurred		177.3
Other		(2.0	)
Liabilities settled		—
Revisions to cash flows		—

Liability at June 30, 2004	$	794.7

"Liabilities incurred" in the table above reflects the asset retirement obligation recorded in connection with our acquisition of the R.E. Ginna Nuclear Power Plant (Ginna). We discuss the acquisition of Ginna in more detail in the Acquisition of Ginna section on the next page. "Other" in the table above represents the asset retirement obligation associated with our geothermal facility in Hawaii that was sold during the quarter ended June 30, 2004. At the time of the sale, the asset retirement obligation was transferred to the buyer of the geothermal facility. We discuss the sale of the geothermal facility in more detail in the Loss from Discontinued Operations section below.

Net Gain on Sales of Investments and
Other Assets

2004

During the six months ended June 30, 2004, our other nonregulated businesses recognized $5.9 million pre-tax, or $3.7 million after-tax, gains on the sale of non-core assets as follows:

•: a $1.1 million pre-tax gain in the first quarter on an installment sale of real estate,
•: a $0.4 million pre-tax gain in the first quarter on the sale of a financial investment,
•: a $3.3 million pre-tax gain in the second quarter on the sale of a financial investment, and
•: a $1.1 million pre-tax gain in the second quarter on the sale of real estate.

2003

During the six months ended June 30, 2003, our other nonregulated businesses recognized $14.2 million pre-tax, or $8.6 million after-tax, gains on the sale of non-core assets as follows:

•: a $7.2 million pre-tax gain in the first quarter of 2003 on the sale of an oil tanker to the U.S. Navy,
•: a $5.3 million pre-tax gain in the first quarter of 2003 on the favorable settlement of a contingent obligation we had previously reserved relating to the sale of our Guatemalan power plant operation in the fourth quarter of 2001,
•: a $1.2 million pre-tax gain in the first quarter of 2003 on an installment sale of real estate, and
•: a $0.5 million pre-tax gain in the second quarter of 2003 on the sale of financial investments.

Loss from Discontinued Operations

In the fourth quarter of 2003, we began to re-evaluate our strategy regarding our geothermal generating facility in Hawaii. The reevaluation of our strategy included soliciting bids to determine the level of interest in the facility. As of December 31, 2003, management determined that disposal of the facility was more likely than not to occur. As a result, we evaluated the facility for impairment as of December 31, 2003, in accordance with SFAS No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets, and determined that the facility was not impaired primarily due to indicative bids from third parties above the carrying value of the assets.

In March 2004, after reviewing final binding offers, management committed to a plan to sell the facility that met the "held for sale" criteria under SFAS No. 144. Under SFAS No. 144, we record assets and liabilities held for sale at the lesser of the carrying amount or fair value less cost to sell.

We estimated that the fair value of the facility as of March 31, 2004, based on the bids under consideration to be below carrying value; therefore, we recorded a $71.6 million pre-tax, or $47.3 million after-tax, impairment charge during the first quarter of 2004. We reported the after-tax impairment charge as a component of "Loss from discontinued operations" in our Consolidated Statements of Income.

Additionally, we recognized the $1.5 million pre-tax, or $1.0 million after-tax, of earnings from the facility for the quarter ended March 31, 2004 as a component of "Loss from discontinued operations."

During the second quarter of 2004, we completed the sale of the facility. We recognized an additional loss on sale of $5.9 million pre-tax, or $3.0 million after-tax, based on the final sales price, as a component of "Loss from discontinued operations." We also recognized $0.6 million pre-tax, or $0.3 million after-tax, of earnings from the facility for the quarter ended June 30, 2004 as a component of "Loss from discontinued operations."

We have not reclassified the prior year results of operations, which were reported under the equity method as "Nonregulated revenues," because we believe that reclassification of immaterial prior period results would be less useful than consistent reporting of prior year amounts. The facility had a $4.7 million net loss, including a $1.1 million cumulative effect of change in accounting principle for the adoption of SFAS No. 143, during the six months ended June 30, 2003.

Acquisition of Ginna

On June 10, 2004, we completed our purchase of the R.E. Ginna nuclear facility (Ginna), which is located in Ontario, New York from Rochester Gas & Electric (RG&E) Corporation. Ginna consists of a 495 megawatt single-unit pressurized water reactor that entered service in 1970 and is licensed to operate until 2029.

We purchased 100 percent of Ginna for $454.4 million including direct costs associated with the acquisition, of which $430.0 million was paid in cash at closing. We accrued a liability for the remaining $24.4 million which is expected to be paid, subject to any adjustments, in the third quarter of 2004 after the completion of a final valuation of certain assets and liabilities. RG&E also transferred to us $200.5 million in decommissioning funds.

We will sell 90 percent of Ginna's output back to RG&E at an average price of nearly $44 per megawatt-hour for approximately 10 years under a unit contingent power purchase agreement (if the output is not available because the plant is not operating, there is no requirement to provide output from other sources). We expect the acquisition of Ginna to be immediately accretive to earnings.

We accounted for this transaction as an asset acquisition. Our preliminary purchase price allocation for the net assets acquired is as follows:

Ginna Net Assets Acquired

At June 10, 2004

	(In millions)
Current assets	$	27.6
Nuclear decommissioning trust fund		200.5
Nuclear fuel		14.3
Net property, plant and equipment		381.2
Intangible assets (details below)		38.4
Other assets		123.9

Total assets acquired		785.9
Current liabilities		20.9
Asset retirement obligations		177.3
Deferred credits and other liabilities		133.3

Net assets acquired	$	454.4

The intangible assets acquired consist of the following:

Description	Amount		Weighted- Average Useful Life

	(In millions)		(In years)
Operating procedures and manuals	$	25.9	25
Permits and licenses		8.4	25
Software		4.1	5

Total intangible assets	$	38.4

Information by Operating Segment

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

•

Our nonregulated merchant energy business in North America includes:

–

fossil, nuclear, and hydroelectric generating facilities and interests in qualifying facilities, fuel processing facilities, and power projects in the United States,

–

our competitive supply activities which include:

–: origination of structured transactions (such as load-serving and power purchase agreements), and risk management services to various customers (including hedging of output from generating facilities and fuel costs),

–: electric and gas retail energy services to commercial and industrial customers, and

–: generation and consulting services.

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

Our remaining nonregulated businesses:

•: design, construct, and operate heating, cooling, and cogeneration facilities for commercial, industrial, and municipal customers throughout North America, and
•: 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.

In addition, we own several investments that we do not consider to be core operations. These include financial investments, real estate projects, and interests in a Latin American power distribution project and in a fund that holds interests in two South American energy projects.

Our Merchant Energy, Regulated Electric, and Regulated Gas reportable segments are strategic businesses based principally upon regulations, products, and services all of which require different technology 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,
2004
Unaffiliated revenues	$	2,105.4		$	477.2	$	111.5		$	98.9		$	—		$	2,793.0
Intersegment revenues		262.3			—		1.1			—			(263.4	)		—

Total revenues		2,367.7			477.2		112.6			98.9			(263.4	)		2,793.0
Loss from discontinued operations		(2.7	)		—		—			—			—			(2.7	)
Net income (loss)		106.5			25.2		(3.3	)		(0.2	)		—			128.2
2003
Unaffiliated revenues	$	1,549.1		$	436.9	$	137.5		$	143.1		$	—		$	2,266.6
Intersegment revenues		273.5			0.1		2.5			—			(276.1	)		—

Total revenues		1,822.6			437.0		140.0			143.1			(276.1	)		2,266.6
Net income (loss)		75.2			20.8		0.9			(0.1	)		—			96.8
For the six months ended June 30,
2004
Unaffiliated revenues	$	4,235.9		$	961.6	$	429.4		$	202.6		$	—		$	5,829.5
Intersegment revenues		516.6			—		2.7			—			(519.3	)		—

Total revenues		4,752.5			961.6		432.1			202.6			(519.3	)		5,829.5
Loss from discontinued operations		(49.0	)		—		—			—			—			(49.0	)
Net income (loss)		99.7			70.3		24.5			(0.1	)		—			194.4
2003
Unaffiliated revenues	$	2,935.1		$	923.2	$	435.7		$	298.7		$	—		$	4,592.7
Intersegment revenues		560.7			0.1		7.9			—			(568.7	)		—

Total revenues		3,495.8			923.3		443.6			298.7			(568.7	)		4,592.7
Cumulative effects of changes in accounting principles		(198.4	)		—		—			—			—			(198.4	)
Net (loss) income		(143.7	)		71.0		29.5			8.6			—			(34.6	)

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

Pension and Postretirement Benefits

In December 2003, the President signed into law the Medicare Prescription Drug Improvement and Modernization Act of 2003 (the Act). This legislation provides a prescription drug benefit for Medicare beneficiaries, a benefit we provide to our Medicare eligible retirees.

We concluded that prescription drug benefits available under our postretirement health care plan are currently "actuarially equivalent" to Medicare Part D and thus qualify for the subsidy under the Act and the expected subsidy will offset or reduce our share of the cost of the underlying postretirement prescription drug coverage. We believe the impact of this legislation will be to reduce our Accumulated Postretirement Benefit Obligation by $30.5 million and reduce our annual postretirement benefit expense during 2004 by $4.0 million. We will reflect the impact of the Act beginning in the third quarter of 2004 in accordance with Financial Accounting Standards Board (FASB) Staff Position 106-2—Accounting and Disclosure Requirements Related to the Medicare Prescription Drug Improvement and Modernization Act of 2003, as discussed in the Accounting Standards Issued section on page 23.

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

	Quarter Ended June 30,						Six Months Ended June 30,
	2004			2003			2004			2003

	(In millions)
Components of net periodic pension benefit cost
Service cost	$	11.4		$	9.6		$	20.0		$	18.4
Interest cost		21.8			23.0			41.1			44.3
Expected return on plan assets		(26.4	)		(27.0	)		(48.8	)		(51.9	)
Amortization of unrecognized prior service cost		1.6			1.7			2.9			3.2
Recognized net actuarial loss		3.7			1.4			7.2			2.7
Amount capitalized as construction cost		(1.2	)		(0.7	)		(1.9	)		(1.6	)

Net periodic pension benefit cost	$	10.9		$	8.0		$	20.5		$	15.1

We made a $50 million contribution to our qualified pension plans on January 16, 2004 even though there is no IRS required minimum contribution.

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

	Quarter Ended June 30,						Six Months Ended June 30,
	2004			2003			2004			2003

	(In millions)
Components of net periodic postretirement benefit cost
Service cost	$	2.6		$	1.8		$	3.9		$	3.6
Interest cost		7.0			7.8			13.6			15.3
Amortization of transition obligation		0.7			0.6			1.3			1.2
Recognized net actuarial (gain) loss		(0.1	)		1.7			1.9			3.4
Amortization of unrecognized prior service cost		(1.1	)		(1.0	)		(2.1	)		(2.1	)
Amount capitalized as construction cost		(1.6	)		(3.1	)		(4.0	)		(5.2	)

Net periodic postretirement benefit cost	$	7.5		$	7.8		$	14.6		$	16.2

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 $3 million in pension benefit payments for our non-qualified pension plans and approximately $30 million for retiree health and life insurance benefit payments during 2004.

Financing Activities

Constellation Energy

During the first quarter of 2004, we decided to continue our ownership in a synthetic fuel processing facility in South Carolina. We discuss this facility in more detail in the Income Taxes section on the next page. In connection with our decision to continue with our ownership in this facility, we are committed to making fixed payments until the end of 2007. Accordingly, during the first quarter of 2004, we recorded a liability of $39.3 million in "Long-term debt" in our Consolidated Balance Sheets for these fixed payments.

In June 2004, Constellation Energy arranged an $800.0 million three-year revolving credit facility and a $300.0 million five-year revolving credit facility replacing a $447.5 million 364-day revolving credit facility. The facility that was replaced expired in the second quarter of 2004. Constellation Energy also has an existing $640.0 million revolving credit facility expiring in June 2005 and a $447.5 million facility expiring in June 2006.

We use these facilities to ensure adequate liquidity to support our operations. We can borrow directly from the banks or use the facilities to allow the issuance of commercial paper. Additionally, we use the facilities to support letters of credit primarily for our merchant energy business.

These revolving credit facilities allow the issuance of letters of credit up to approximately $2.2 billion. In addition, BGE maintains $200.0 million in credit facilities as discussed below. At June 30, 2004, letters of credit that totaled $860.8 million were issued under our facilities.

Under our continuous offering program, employee benefit plans, and shareholder investment plans we issued $30.5 million of common stock during the six months ended June 30, 2004.

Additionally, on July 1, 2004, we issued 6.0 million shares of common stock for net proceeds of $226.9 million to fund a portion of the acquisition of Ginna.

BGE

During the second quarter of 2004, certain credit facilities expired and BGE renewed those facilities. BGE continues to maintain $200.0 million in annual committed credit facilities, expiring August 2004 through June 2005, to ensure adequate liquidity to support its operations. We can borrow directly from the banks or use the facilities to allow commercial paper to be issued. As of June 30, 2004, BGE had no outstanding commercial paper, which results in $200.0 million in unused credit facilities.

BGE announced in July 2004 a partial call of $4.8 million principal amount of its Remarketed Floating Rate Series due September 1, 2006 First Refunding Mortgage Bonds in connection with its annual sinking fund. The redemption will be made pursuant to the sinking fund provisions of BGE's mortgage. Bonds to be called were randomly selected by lot. Bonds called for the sinking fund will be redeemed in whole or in part on August 25, 2004 at the sinking fund call price of 100% of principal amount, plus accrued interest from June 1, 2004 to, but not including, August 25, 2004.

Income Taxes

Our merchant energy business has investments in facilities that manufacture solid synthetic fuel produced from coal as defined under Section 29 of the Internal Revenue Code for which we claim tax credits on our Federal income tax return. We recognize the tax benefit of these credits in our Consolidated Statements of Income when we believe it is highly probable that the credits will be sustained. The synthetic fuel process involves combining coal material with a chemical reagent to create a significant chemical change. A taxpayer may request a private letter ruling from the Internal Revenue Service (IRS) to support its position that the synthetic fuel produced undergoes a significant chemical change and thus qualifies for Section 29 credits.

As of June 30, 2004, we have recognized cumulative tax benefits associated with Section 29 credits of $158.7 million, of which $58.6 million was recognized during the quarter ended June 30, 2004 and $80.7 million during the six months ended June 30, 2004.

We own a minority ownership in four synthetic fuel facilities located in Ohio, Virginia, and West Virginia. These facilities have received private letter rulings from the IRS. In January 2004, the IRS concluded its examination of the partnership that owns these facilities for the tax years 1998 through 2001 and the IRS did not disallow any of the previously recognized synthetic fuel credits. During the second quarter of 2004, we received final written notice of the resolution of the examination from the IRS.

In 2003, we purchased 99% ownership in a South Carolina facility that produces synthetic fuel. We did not recognize in our Consolidated Statements of Income the tax benefit of $35.9 million for credits claimed on our South Carolina facility in 2003 pending receipt of a favorable private letter ruling. On April 15, 2004, we received a favorable private letter ruling. We believe receipt of the private letter ruling provides assurance that it is highly probable that the credits will be sustained. Therefore, we recognized the tax benefit of $35.9 million in our Consolidated Statements of Income during the quarter ended June 30, 2004.

While we believe the production and sale of synthetic fuel from all of our synthetic fuel facilities meet the conditions to qualify for tax credits under Section 29 of the IRS Code, we cannot predict the timing or outcome of any future challenge by the IRS, legislative or regulatory action, or the ultimate impact of such events on the Section 29 credits that we have claimed to date or expect to claim in the future, but the impact could be material to our financial results.

Our recognition of the Section 29 credits reduced our effective tax rate as detailed in the table below. Total income taxes are different from the amount that would be computed by applying the statutory Federal income tax rate of 35% to book income before income taxes as follows:

		Quarter Ended June 30,						Six Months Ended June 30,
		2004			2003			2004			2003

		(In millions)
Income before income taxes (excluding BGE preference stock dividends)		$	121.1		$	154.4		$	279.3		$	261.0
Statutory federal income tax rate			35	%		35	%		35	%		35	%

Income taxes computed at statutory federal rate			42.4			54.0			97.8			91.4
(Decreases) increases in income taxes due to:
	Synthetic fuel tax credits (2004)		(22.7	)		(9.5	)		(44.8	)		(17.9	)
	Synthetic fuel tax credits (2003)*		(35.9	)		—			(35.9	)		—
	State income taxes, net of federal tax benefit		2.2			9.3			9.5			15.7
	Other		0.9			0.5			2.7			1.4

Total income taxes		$	(13.1	)	$	54.3		$	29.3		$	90.6

Effective tax rate			(10.8	)%		35.2	%		10.5	%		34.7	%

* Credits associated with 2003 production at our South Carolina facility.

Commitments, Guarantees, and Contingencies

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

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

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

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

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.

Corporately, we have committed to long-term service agreements and other obligations related to our information technology systems.

At June 30, 2004, the total amount of commitments was $4,338.7 million, which 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 2012 and provide for the sale of full requirements energy to electricity distribution utilities and certain retail customers. Our power sales contracts associated with our power plants 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. All long-term contracts were executed at pricing that approximated market rates, including profit margin, at the time of execution.

Guarantees

The terms of our guarantees are as follows:

	Expiration
	2004		2005- 2006		2007- 2008		Thereafter		Total

	(In millions)
Competitive Supply	$	3,121.1	$	1,090.5	$	307.0	$	500.3	$	5,018.9
Other		10.4		4.6		—		1,044.6		1,059.6

Total	$	3,131.5	$	1,095.1	$	307.0	$	1,544.9	$	6,078.5

At June 30, 2004, Constellation Energy had a total of $6,078.5 million of guarantees outstanding related to loans, credit facilities, and contractual performance of certain of its subsidiaries as described on the next page. These guarantees do not represent incremental obligations and we do not expect to fund the full amount under these guarantees.

•: Constellation Energy guaranteed $5,018.9 million on behalf of our subsidiaries for competitive supply activities. These guarantees are put into place in order to allow our subsidiaries the flexibility needed to conduct business with counterparties without having to post substantial collateral. While the face amount of these guarantees is $5,018.9 million, our calculated fair value of obligations covered by these guarantees was $1,180.7 million at June 30, 2004. If the parent company was required to fund defaulted subsidiary obligations, the total amount at current market prices is $1,180.7 million. The recorded fair value of obligations in our Consolidated Balance Sheets for these guarantees was $656.2 million at June 30, 2004.
•: Constellation Energy guaranteed $723.3 million primarily on behalf of our nuclear facilities related to nuclear insurance and decommissioning.
•: Constellation Energy guaranteed $42.3 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, 2004.
•: Our merchant energy business guaranteed $18.0 million for loans and other performance guarantees related to certain power projects in which we have an investment.
•: Our other nonregulated business guaranteed $12.7 million for performance bonds.
•: BGE guaranteed two-thirds of certain debt of Safe Harbor Water Power Corporation, an unconsolidated investment. At June 30, 2004, Safe Harbor Water Power Corporation had outstanding debt of $20.0 million. The maximum amount of BGE's guarantee is $13.3 million.
•: BGE guaranteed the Trust Preferred Securities of $250.0 million of BGE Capital Trust II, an unconsolidated investment, as discussed in more detail in Note 9 of our 2003 Annual Report on Form 10-K.

The total recorded fair value of obligations in our Consolidated Balance Sheets was $681.2 million and not the $6.1 billion of total guarantees. We assess the risk of loss from these guarantees to be minimal.

Environmental Matters

We are subject to regulation by various federal, state, and local authorities with regard to:

•: air quality,
•: water quality, and
•: treatment, storage, and disposal of solid and hazardous waste.

Clean Air Act

The Clean Air Act affects both existing generating facilities and new projects. The Clean Air Act and many state laws impose significant requirements relating to emissions of sulfur dioxide (SO₂), nitrogen oxide (NOx), particulate matter, and other pollutants that result from burning fossil fuels. The Clean Air Act also contains other provisions that could materially affect some of our projects. Various provisions may require permits, inspections, or installation of additional pollution control technology or may require the purchase of emission allowances. Certain of these provisions are described in more detail below.

The Environmental Protection Agency (EPA) established new National Ambient Air Quality Standards for very fine particulates and revised standards for ozone. In April 2004, the EPA identified the areas that would be in ozone nonattainment for the new standards. The affected states will be required to submit plans for compliance within three years. The EPA has also proposed a rule to address the interstate transport of SO₂ and NOx emissions from fossil fired power plants located primarily in the Eastern United States. While any new standards may require increased controls at some of our fossil generating plants in the future, planning and implementation of unit specific requirements will likely take place over several years. We are unable to estimate the cost of compliance until the states and the EPA have finalized their plans for meeting the standards or finalized the proposed rule.

We own several generating facilities in currently designated severe ozone nonattainment areas in Maryland and California. The Clean Air Act requires states to assess fees against every major stationary source of NOx and volatile organic chemicals in severe ozone nonattainment areas if national air quality standards are not achieved by a specified deadline. If implemented, the fee would be assessed based on the magnitude of a source's emissions as compared to its emissions when the area failed to meet the deadline. The exact method of computing these fees has not been established and will depend in part on state implementation regulations that have not been finalized.

The current deadline for most severe nonattainment areas is 2005, including those in which our generating facilities are located. Assessment of fees would commence in 2006 if the current effective date is maintained. However, there is significant uncertainty regarding the date when fees would be assessed in light of pending federal legislation and anticipated EPA rulemaking. Currently, we are unable to estimate the ultimate timing or financial impact of the standard in light of the uncertainty surrounding its effective date and the methodology that will be used in calculating the fees.

The EPA and several states filed suits against a number of coal-fired power plants in Mid-Western and Southern states alleging violations of the Prevention of Significant Deterioration and Non-Attainment provisions of the Clean Air Act's new source review requirements. The EPA requested information relating to modifications made to our Brandon Shores, Crane, and Wagner plants in Baltimore, Maryland. The EPA also sent similar, but narrower, information requests to two of our newer Pennsylvania waste-coal burning plants in which we have an ownership interest. We have responded to the EPA, and as of the date of this report the EPA has taken no further action.

Based on the level of emissions control that the EPA and states are seeking in these new source review enforcement actions, we believe that material additional costs and penalties could be incurred, and planned capital expenditures could be accelerated, if the EPA was successful in any future actions regarding our facilities.

On October 27, 2003, the EPA's new source review rule on routine maintenance was published in the Federal Register. The new regulations would establish an equipment replacement cost threshold for determining when major new source review requirements are triggered. Plant owners may spend up to 20% of the replacement value of a generation unit on certain improvements each year without triggering requirements for new pollution controls. Parties had until December 26, 2003, the effective date of the rule, to appeal the agency's decision in court. An appeal was filed with the United States Court of Appeals. The effective date of the rule has been delayed pending review.

The Clean Air Act required the EPA to evaluate the public health impacts of emissions of mercury, a hazardous air pollutant, from coal-fired plants. The EPA decided to control mercury emissions from coal-fired plants. On December 15, 2003, the EPA proposed two alternatives for controlling mercury emissions from generating facilities. The EPA may require the installation of mercury reduction equipment. Alternatively, the EPA may revise standards to allow for the purchase of allowances. Compliance could be required as soon as 2007, or by 2010 depending on which alternative is selected. We believe final regulations could be issued in 2005 and could affect all oil-fired and coal-fired boilers. The cost of compliance with the final regulations could be material.

Future initiatives regarding greenhouse gas emissions and global warming continue to be the subject of much debate. As a result of our diverse fuel portfolio, our contribution to greenhouse gases varies by plant type. Fossil fuel-fired power plants are significant sources of carbon dioxide emissions, a principal greenhouse gas. Our compliance costs with any mandated federal greenhouse gas reductions in the future could be material.

Clean Water Act

Our facilities are subject to a variety of federal and state regulations governing existing and potential water/wastewater and storm water discharges.

In April 2002, the EPA proposed rules under the Clean Water Act that require cooling water intake structures to reflect the best technology available for minimizing adverse environmental impacts. In February 2004, the proposed rules were finalized and published in the Federal Register on July 9, 2004. The final rules require the installation of additional intake screens or other protective measures, as well as extensive site-specific study and monitoring requirements. We currently have six facilities affected by the regulation. The rule allows for a number of compliance options that will be assessed over the next four years. We are currently reviewing the final rules and their potential impact to us. Our compliance costs associated with the final rules could be material.

Under current provisions of the Clean Water Act, existing permits are renewed every five years, at which time permit limits come under extensive review and can be modified to account for more stringent regulations. In addition, the permits can be modified at any time. Changes to the water discharge permits of our coal or other fuel suppliers due to federal or state initiatives may increase the cost of fuel, which in turn could have a significant impact on our operations.

Waste Disposal

The 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 owned and operated by others. We cannot estimate the clean-up costs for all of these sites.

However, based on a Record of Decision (ROD) issued by the EPA in 1997, we can estimate that BGE's current 15.47% share of the reasonably possible clean-up costs at one of these sites, Metal Bank of America, a metal reclaimer in Philadelphia, could be as much as $1.3 million higher than amounts we believe are probable and have recorded as a liability in our Consolidated Balance Sheets. There has been no significant regulatory activity with respect to actual site remediation since the EPA's ROD in 1997. EPA and the potentially responsible parties, including BGE, are currently pursuing claims against Metal Bank of America for an equitable share of expected site remediation costs.

In 1999, the EPA proposed to add the 68^th Street Dump in Baltimore, Maryland to the Comprehensive Environmental Response, Compensation and Liability Act ("Superfund") National Priorities List ("NPL"), 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 68^th Street Dump site. In April 2003, EPA re-proposed the 68^th Street site to the NPL, but decided not to include the site in its September 2003 update. We and other potentially responsible parties formed the 68^th Street Coalition in March 2004 with the intent of entering into consent order negotiations with the EPA to investigate clean-up options for the site. At this stage, it is not possible to predict the outcome of those discussions or our share of the liability. However, the costs could have a material effect on our financial results.

In late December 1996, BGE signed a consent order with the Maryland Department of the Environment that required BGE 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 the remedial action plans, the costs BGE considers to be probable to remedy the contamination are estimated to total $47 million. BGE recorded these costs as a liability in its Consolidated Balance Sheets and deferred these costs, net of accumulated amortization and amounts it recovered from insurance companies, as a regulatory asset. Because of the results of studies at this site, it is reasonably possible that additional costs could exceed the amount BGE recognized by approximately $14 million. Through June 30, 2004, BGE spent approximately $40 million for remediation at this site. BGE also 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.

The EPA issued its ROD for the Kane and Lombard Drum site located in Baltimore, Maryland on September 30, 2003. The ROD specifies the clean-up plan for the site, consisting of enhanced reductive dechlorination, a soil management plan, and institutional controls. The ROD was consistent with the proposed remedy the EPA released in December 2002. On July 1, 2004, the EPA issued a Special Notice/Demand Letter to BGE and three other potentially responsible parties regarding implementation of the remedy. The total clean-up costs are estimated to be $7.3 million. We estimate our current share of site-related costs to be 11.1%. Our share of these future costs has not been determined and it may vary from the current estimate. In December 2002, we recorded a liability in our Consolidated Balance Sheets for our share of the clean-up costs that we believe is probable.

Nuclear Insurance

We maintain nuclear insurance coverage for Calvert Cliffs, Nine Mile Point, and Ginna in four program areas: liability, worker radiation, property, and accidental outage. These policies contain certain industry standard exclusions, including, but not limited to, ordinary wear and tear and war.

In November 2002, the President signed into law the Terrorism Risk Insurance Act ("TRIA") of 2002. Under the TRIA, property and casualty insurance companies are required to offer insurance for losses resulting from Certified acts of terrorism. Certified acts of terrorism are determined by the Secretary of State and Attorney General and primarily are based upon the occurrence of significant acts of international terrorism. Our nuclear property and accidental outage insurance programs, as discussed later in this section, provide coverage for Certified acts of terrorism.

If there were an accident or an extended outage at any unit of Calvert Cliffs, Nine Mile Point, or Ginna, it could have a substantial adverse impact on our financial results.

Nuclear Liability Insurance

Pursuant to the Price-Anderson Act, we are required to insure against public liability claims resulting from nuclear incidents to the full limit of public liability. This limit of liability consists of the maximum available commercial insurance of $300 million and mandatory participation in an industry-wide retrospective premium assessment program. The retrospective premium assessment is $100.6 million per reactor, increasing the total amount of insurance for public liability to approximately $10.8 billion. Under the retrospective assessment program, we can be assessed up to $503 million per incident at any commercial reactor in the country, payable at no more than $50 million per incident per year. This assessment also applies in excess of our worker radiation claims insurance and is subject to inflation and state premium taxes. Claims resulting from non-certified acts of terrorism are limited to the commercial insurance discussed above, regardless of the number of nuclear plants affected. In addition, the U.S. Congress could impose additional revenue-raising measures to pay claims.

Worker Radiation Claims Insurance

We participate in the American Nuclear Insurers Master Worker Program that provides coverage for worker tort claims filed for radiation injuries. Effective January 1, 1998, this program was modified to provide coverage to all workers whose nuclear-related employment began on or after the commencement date of reactor operations. Waiving the right to make additional claims under the old policy was a condition for coverage under the new policy. We describe the old and new policies below:

•: Nuclear worker claims reported on or after January 1, 1998 are covered by a new insurance policy with a single industry aggregate limit of $300 million for radiation injury claims against all those insured by this policy.
•: All nuclear worker claims reported prior to January 1, 1998 are still covered by the old policy. Insureds under the old policies, with no current operations, are not required to purchase the new policy described above, and may still make claims against the old policies through 2007. If radiation injury claims under these old policies exceed the policy reserves, all policyholders could be retroactively assessed, with our share being up to $6.3 million.

The sellers of Nine Mile Point retain the liabilities for existing and potential claims that occurred prior to November 7, 2001. In addition, the Long Island Power Authority, which continues to own 18% of Unit 2 at Nine Mile Point, is obligated to assume its pro rata share of any liabilities for retrospective premiums and other premiums assessments. RG&E, the seller of Ginna, retains the liabilities for existing and potential claims that occurred prior to June 10, 2004. If claims under these policies exceed the coverage limits, the provisions of the Price-Anderson Act would apply.

Nuclear Property Insurance

Our policies provide $500 million in primary coverage at Calvert Cliffs, Nine Mile Point, and Ginna. In addition, we maintain $2.25 billion of excess coverage at Calvert Cliffs and Nine Mile Point and $1.77 billion of excess coverage at Ginna for property damage, decontamination, and premature decommissioning liability. This coverage currently is purchased through an industry mutual insurance company. If accidents at plants insured by the mutual insurance company cause a shortfall of funds, all policyholders could be assessed, with our share being up to $91.8 million.

Losses resulting from non-certified acts of terrorism are covered as a common occurrence, meaning that if non-certified terrorist acts occur against one or more commercial nuclear power plants insured by our nuclear property insurance company within a 12-month period, they would be treated as one event and the owners of the plants would share one full limit of liability (currently $3.24 billion).

Accidental Nuclear Outage Insurance

Our policies provide indemnification on a weekly basis for losses resulting from an accidental outage of a nuclear unit. Coverage begins after a 12-week deductible period and continues at 100% of the weekly indemnity limit for 52 weeks and then 80% of the weekly indemnity limit for the next 110 weeks. Our coverage is up to $490.0 million per unit at Calvert Cliffs and Ginna, $420.0 million for Unit 1 of Nine Mile Point, and $412.6 million for Unit 2 of Nine Mile Point. This amount can be reduced by up to $98.0 million per unit at Calvert Cliffs and $82.5 million for Nine Mile Point if an outage of more than one unit is caused by a single insured physical damage loss.

Non-nuclear Property Insurance

Our conventional property insurance provides coverage of $1.0 billion per occurrence for Certified acts of terrorism as defined under the Terrorism Risk Insurance Act of 2002. Certified acts of terrorism are determined by the Secretary of State and Attorney General of the United States and primarily are based upon the occurrence of significant acts of international terrorism. Our conventional property insurance program also provides coverage for non-certified acts of terrorism up to an annual aggregate limit of $333 million. If a terrorist act occurs at any of our facilities, it could have a significant adverse impact on our financial results.

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 the Market Risk section on page 57.

Interest Rates

We use interest rate swaps to manage our interest rate exposures associated with new debt issuances 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, Accounting for Derivative Instruments and Hedging Activities, as amended, with gains and losses, net of associated deferred income tax effects, recorded in "Accumulated other comprehensive income" in our Consolidated Balance Sheets, in anticipation of planned financing transactions. We reclassify gains and losses on the hedges from "Accumulated other comprehensive income" into "Interest expense" in our Consolidate Statements of Income during the periods in which the interest payments being hedged occur. We record any gains or losses on swaps used to manage our fixed rate debt, 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 "Risk management assets and liabilities" and "Long-term debt" in our Consolidated Balance Sheets. In addition, we record the difference between interest on hedged fixed rate debt and floating rate swaps in "Interest expense" in the periods that the swaps settle.

At June 30, 2004, we have net unrealized pre-tax gains of $19.8 million related to interest rate hedges recorded in "Accumulated other comprehensive income." We expect to reclassify $2.9 million of pre-tax net gains on these swap contracts from "Accumulated other comprehensive income" into "Interest expense" during the next twelve months.

Commodity Prices

At June 30, 2004 our merchant energy business had designated certain purchase and sale contracts as cash-flow hedges of forecasted transactions for the years 2004 through 2011 under SFAS No. 133.

Under the provisions of SFAS No. 133, we record gains and losses on energy derivative contracts designated as cash-flow hedges of forecasted transactions in "Accumulated other comprehensive income" in our Consolidated Balance Sheets prior to the settlement of the anticipated hedged physical transaction. We reclassify these gains or losses into earnings upon settlement of the underlying hedged transaction. We record derivatives used for hedging activities from our merchant energy business in "Risk management assets and liabilities" in our Consolidated Balance Sheets.

At June 30, 2004, our merchant energy business has net unrealized pre-tax gains of $205.4 million on these hedges recorded in "Accumulated other comprehensive income." We expect to reclassify $405.2 million of net pre-tax gains on cash-flow hedges from "Accumulated other comprehensive income" into earnings during the next twelve months based on the market prices at June 30, 2004. However, the actual amount reclassified into earnings could vary from the amounts recorded at June 30, 2004 due to future changes in market prices.

We recognized into earnings a pre-tax loss of $4.9 million for the quarter ended June 30, 2004 and a pre-tax gain of $9.5 million for the quarter ended June 30, 2003 related to the ineffective portion of our hedges.

We recognized into earnings a pre-tax gain of $4.4 million for the six months ended June 30, 2004 and a pre-tax gain of $9.3 million for the six months ended June 30, 2003 related to the ineffective portion of our hedges.

Accounting Standards Issued

FSP 106-2

In May 2004, the FASB issued FASB Staff Position 106-2, which addresses accounting and disclosure requirements pertaining to Medicare Prescription Drug Improvement and Modernization Act of 2003, and is effective July 1, 2004. We discuss the expected impacts of this standard in the Pension and Postretirement Benefits section on page 15.

Accounting Standards Adopted

FIN 46/FIN 46R

In January 2003, the FASB issued Interpretation No. (FIN) 46, Consolidation of Variable Interest Entities, which was subsequently revised in its entirety with the issuance of FIN 46R in December 2003.

FIN 46R establishes conditions under which an entity must be consolidated based upon variable interests rather than voting interests. Variable interests are ownership interests or contractual relationships that enable the holder to share in the financial risks and rewards resulting from the activities of a Variable Interest Entity (VIE). A VIE can be a corporation, partnership, trust, or any other legal structure used for business purposes. An entity is considered a VIE under FIN 46R if it does not have an equity investment sufficient for it to finance its activities without assistance from variable interests or if its equity investors lack any of the following characteristics of a controlling financial interest:

•: control through voting rights,
•: obligation to absorb expected losses or
•: right to receive expected residual returns.

FIN 46R requires us to consolidate VIEs for which we are the primary beneficiary and to disclose certain information about significant variable interests we hold. The primary beneficiary of a VIE is the entity that receives the majority of a VIE's expected losses, expected residual returns, or both.

FIN 46R was effective March 31, 2004 for all VIEs except special purpose entities (SPEs), for which the effective date was December 31, 2003. Therefore, at December 31, 2003, we and BGE deconsolidated BGE Capital Trust II, an SPE established to issue trust preferred securities as described in Note 9 of our 2003 Annual Report on Form 10-K, because BGE is not its primary beneficiary. As a result, we currently record $257.7 million of deferrable interest subordinated debentures due to BGE Capital Trust II, and $7.7 million equity investment in BGE Capital Trust II in "Other investments" in our and BGE's Consolidated Balance Sheets.

As a result of adopting the remainder of the provisions of FIN 46R as of March 31, 2004, we were not required to consolidate or deconsolidate any non-SPE entities with which we are involved through variable interests. We had preliminarily determined that we were the primary beneficiary for an unconsolidated investment in a hydroelectric generating plant located in Pennsylvania because our two-thirds voting interest is disproportionate to our 50% interest in the plant's earnings. However, we subsequently determined that the entity is not a VIE because less than substantially all of the plant's activities are conducted on our behalf, and therefore we do not have to consolidate the entity.

We have a significant interest in the following VIEs for which we are not the primary beneficiary:

VIE	Nature of Involvement	Date of Involvement

Power projects and fuel supply entities	Equity investment and guarantees	Prior to 2003
Natural gas producing facility	Volumetric and price swap	July 2003

The following is summary information about these entities as of June 30, 2004:


	(In millions)
Total assets	$	289
Total liabilities		149
Our ownership interest		41
Other ownership interests		99
Our maximum exposure to loss		108

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, 2004 consists of the following:

•: the carrying amount of our investment totaling $41 million,
•: debt and performance guarantees totaling $13 million, and
•: volumetric and price variability of up to $54 million associated with a natural gas producer swap, based on contract volumes and gas prices as of June 30, 2004.

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

Related Party Transactions—BGE

Income Statement

BGE is providing standard offer service to customers at fixed rates over various time periods during the initial transition period from July 1, 2000 to June 30, 2006, for those customers that do not choose an alternate supplier. Our wholesale marketing and risk management operation is under contract to provide BGE the energy and capacity required to meet its standard offer service obligations for the transition period. The cost of BGE's purchased energy from nonregulated affiliates of Constellation Energy to meet its standard offer service obligation was as follows:

	Quarter Ended June 30,				Six Months Ended June 30,
	2004		2003		2004		2003

	(In millions)
Purchased energy	$	254.1	$	237.2	$	494.5	$	480.8

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. Management believes this method of allocation is reasonable and approximates the cost BGE would have incurred as an unaffiliated entity. These costs were $25.3 million for the quarter ended June 30, 2004 compared to $19.9 million for the same period in June 30, 2003 and $42.9 million for the six months ended June 30, 2004 compared to $34.7 million for the same period in 2003.

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. BGE had invested $247.7 million at June 30, 2004 and $230.2 million at December 31, 2003 under this arrangement.

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 pension plan result in intercompany balances in BGE's Consolidated Balance Sheets.

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 a North American 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 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.

Our merchant energy business is a competitive provider of energy solutions for large customers in North America. It has electric generation assets located in various regions of the United States and provides energy solutions to meet customers' needs. Our merchant energy business focuses on serving the full energy and capacity requirements (load-serving activities) of, and providing other risk management activities for various customers, such as utilities, municipalities, cooperatives, retail aggregators, and commercial and industrial customers. These load-serving activities typically occur in regional markets in which end-use customer electricity rates have been deregulated and thereby separated from the cost of generation supply.

Our wholesale marketing and risk management operation actively uses energy and energy-related commodities in order to manage our portfolio of energy purchases and sales to customers through structured transactions. As part of our risk management activities we trade power and gas to enable price discovery and facilitate the hedging of our load-serving and other risk management products and services. Within our trading function we allow limited risk-taking activities for profit. These activities are actively managed through daily value at risk and liquidity position limits. We discuss value at risk in more detail in the Market Risk section on page 57.

BGE is a regulated electric transmission and distribution and a regulated gas distribution utility company with a service territory that covers the City of Baltimore and all or part of ten counties in central Maryland.

Our other nonregulated businesses:

•: design, construct, and operate heating, cooling, and cogeneration facilities for commercial, industrial, and municipal customers throughout North America, and
•: provide home improvements, service heating, air conditioning, plumbing, electrical, and indoor air quality systems, and provide natural gas retail marketing to residential customers in central Maryland.

In addition, we own several investments that we do not consider to be core operations. These include financial investments, real estate projects, and interests in a Latin American distribution project and in a fund that holds interests in two South American energy projects.

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 future 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, 2004 and 2003. 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:

•: First, we discuss our strategy.
•: We then describe the business environment in which we operate including how regulation, weather, and other factors affect our business.
•: Next, we discuss our critical accounting policies. These are the accounting policies that are most important to both the portrayal of our financial condition and results and require management's most difficult, subjective or complex judgment.
•: We highlight significant events that occurred in 2004 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, security ratings, capital resources, capital requirements, and commitments.

•: We conclude with a discussion of our exposure to various market risks.

Strategy

We are pursuing a balanced strategy to distribute energy through our North American competitive supply activities and our regulated utility located in Maryland, BGE.

Our merchant energy business focuses on long-term, high-value sales of energy, capacity, and related products to large customers, including distribution utilities, municipalities, cooperatives, industrial customers, and commercial customers primarily in the regional markets in which end-use customer electricity rates have been deregulated and thereby separated from the cost of generation supply. These markets include:

•: the New England, New York, and Mid-Atlantic regions,
•: Texas,
•: the Mid-West region,
•: the West region, and
•: certain areas in Canada.

We obtain this energy through both owned and contracted generation. Our generation fleet is strategically located in deregulated markets across the country and is diversified by fuel type, including nuclear, coal, gas, oil, and renewable sources. Where we do not own generation, we contract for power from other merchant providers, typically through power purchase agreements. We intend to remain diversified between regulated transmission and distribution and competitive supply. We will use both our owned generation and our contracted generation to support our competitive supply operation.

We are a leading national competitive supplier of energy in the deregulated markets previously discussed. In our wholesale and commercial and industrial retail marketing activities we are leveraging our recognized expertise in providing full requirements energy and energy related services to enter markets, capture market share, and organically grow these businesses. Through the application of technology, intellectual capital, and increased scale, we are seeking to reduce the cost of delivering full requirements energy and energy related services and managing risk.

We are also responding proactively to customer needs by expanding the variety of products we offer. Our wholesale competitive supply activities include a growing customer products operation that markets physical energy products and risk management and logistics services sold to generators, distributors, producers of coal, natural gas and fuel oil, and other consumers.

Within our retail competitive supply activities, we are marketing a broader array of products and expanding our markets. Over time, we may consider integrating the sale of electricity and natural gas to provide one energy procurement solution for our customers.

Collectively, the integration of owned and contracted electric generation assets with origination, fuel procurement, and risk management expertise allows our merchant energy business to earn incremental margin and more effectively manage energy and commodity price risk over geographic regions and over time. Our focus is on providing solutions to customers' energy needs, and our wholesale marketing and risk management operation adds value to our owned and contracted generation assets by providing national market access, market infrastructure, real-time market intelligence, risk management and arbitrage opportunities, and transmission and transportation expertise. Generation capacity supports our wholesale marketing and risk management operation by providing a source of reliable power supply that provides a physical hedge for some of our load-serving activities.

To achieve our strategic objectives, we expect to continue to pursue opportunities that expand our access to customers and to support our wholesale marketing and risk management operation with generation assets that have diversified geographic, fuel, and dispatch characteristics. We also expect to grow organically through selling a greater number of physical energy products and services to large energy customers. We expect to achieve operating efficiencies within our competitive supply operation and our generation fleet by selling more products through our existing sales force, benefiting from efficiencies of scale, adding to the capacity of existing plants, and making our business processes more efficient.

We expect BGE and our other retail energy service businesses to grow through focused and disciplined expansion primarily from new customers. At BGE, we are also focused on enhancing reliability and customer satisfaction.

Customer choice, regulatory change, and energy market conditions significantly impact our business. In response, we regularly evaluate our strategies with these goals in mind: to improve our competitive position, to anticipate and adapt to the business environment and regulatory changes, and to maintain a strong balance sheet and investment-grade credit quality.

Beginning in the fourth quarter of 2001, we undertook a number of initiatives to reduce our costs towards competitive levels and to ensure that our resources are focused on our core energy businesses. These initiatives included the implementation of workforce reduction programs, the acceleration of our exit strategy for certain non-core assets, and the implementation of productivity initiatives.

We are constantly reevaluating our strategies and might consider:

•: acquiring or developing additional generating facilities to support our merchant energy business,
•: mergers or acquisitions of utility or non-utility businesses or assets, and
•: sale of assets or one or more businesses.

Business Environment

With the shift toward customer choice, 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 63. We discuss our market risks in the Market Risk section on page 57.

In this section, we discuss in more detail several issues that affect our businesses.

Merchant Competition

During the transition of the energy industry to competitive markets, it is difficult for us to assess our overall position versus the position of existing power providers and new entrants because each company may employ widely differing strategies in their fuel supply and power sales contracts with regard to pricing, terms and conditions. Further difficulties in making competitive assessments of our company arise from states considering different types of regulatory initiatives concerning competition in the power industry.

Increased competition that resulted from some of these initiatives in several states contributed in some instances to a reduction in electricity prices and put pressure on electric utilities to lower their costs, including the cost of purchased electricity. Some states that were considering deregulation have slowed their plans or postponed consideration of deregulation, while other states are reconsidering deregulation. In addition, our merchant energy business is also affected by regional regulatory or legislative decisions, which may impact our financial results and our ability to successfully execute our growth strategy.

We believe there is adequate growth potential in the current deregulated market. However, in response to regional market differences and to promote competitive markets, the Federal Energy Regulatory Commission (FERC) proposed initiatives promoting the formation of Regional Transmission Organizations and a standard market design. If approved, these market changes could provide additional opportunities for our merchant energy business. We discuss these initiatives in the FERC Regulation—Regional Transmission Organizations and Standard Market Design section on page 29.

As the economy continues to recover and the market for commercial and industrial supply continues to grow, we have experienced increased competition in our retail commercial and industrial supply activities. The increase in retail competition and the impact of wholesale power prices compared to the rates charged by local utilities may affect the margins that we will realize from our customers. However, we believe that our experience and expertise in assessing and managing risk will help us to remain competitive during volatile or otherwise adverse market circumstances.

Regulated Electric Competition

We are facing competition in the sale of electricity to retail customers.

Maryland

As a result of the deregulation of electric generation in Maryland, the following occurred effective July 1, 2000:

•: All customers can choose their electric energy supplier. BGE provides fixed price standard offer service over various time periods for different classes of customers that do not select an alternative supplier until June 30, 2006.
•: While BGE does not sell electric commodity to all customers in its service territory, BGE does deliver electricity to all customers and provides meter reading, billing, emergency response, regular maintenance, and balancing services.
•: BGE provided a market rate standard offer service for those commercial and industrial customers who were no longer eligible for fixed price standard offer service through June 30, 2004.
•: BGE residential base rates will not change before July 2006. While total residential base rates remain unchanged over the transition period (July 1, 2000 through June 30, 2006), annual standard offer service rate increases are offset by corresponding decreases in the competitive transition charge (CTC) that BGE receives from its customers.

•: Commercial and industrial customers had several service options that fixed electric energy rates through June 30, 2004 and will fix transition charges through June 30, 2006.

Standard Offer Service

Our wholesale marketing and risk management operation provided BGE with 100% of the energy and capacity required to meet its commercial and industrial standard offer service obligations through June 30, 2004, and provides 100% of the energy and capacity required to meet its residential standard offer service obligations through June 30, 2006. BGE obtained its supply for standard offer service to its commercial and industrial customers beginning July 1, 2004, and will obtain its supply for standard offer service to its residential customers beginning July 1, 2006, through a competitive wholesale bidding process as discussed in the Standard Offer Service—Provider of Last Resort (POLR) section below.

Beginning July 1, 2002, the fixed price standard offer service rate ended for certain of our large commercial and industrial customers. As a result, the majority of these customers purchase their electricity from alternate suppliers, including subsidiaries of Constellation Energy. The remaining large commercial and industrial customers that continued to receive their electric supply from BGE were provided market rate standard offer service rates through June 30, 2004.

Beginning July 1, 2004, all commercial and industrial customers that receive their electric supply from BGE are charged market-based standard offer service rates. Beginning July 1, 2006, BGE's current obligation to provide fixed price standard offer service to residential customers ends, and all residential customers that receive their electric supply from BGE will be charged market-based standard offer service rates.

Standard Offer Service—Provider of Last Resort (POLR)

In April 2003, the Maryland Public Service Commission (Maryland PSC) approved a settlement agreement reached by BGE and parties representing customers, industry, utilities, suppliers, the Maryland Energy Administration, the Maryland PSC's Staff, and the Office of People's Counsel which, among other things, extends BGE's obligation to supply standard offer service for a second transition period. Under the settlement agreement, BGE is obligated to provide market-based standard offer service to residential customers until June 30, 2010, and for commercial and industrial customers for one, two or four year periods beyond June 30, 2004, depending on customer load. The POLR rates charged during this time will recover BGE's wholesale power supply costs and include an administrative fee.

In September 2003, the Maryland PSC approved a second settlement agreement. This phase deals with the bid procurement process that utilities must follow to obtain wholesale power supply to serve retail customers on standard offer service during the second transition period. The settlement contained a model request for proposals, a model wholesale power supply contract, and various requirements pertaining to, among other things, bidder qualifications and bid evaluation criteria. Bidding to supply BGE's standard offer service to commercial and industrial customers beyond June 30, 2004 occurred through a multi-round competitive bidding process in February and March 2004. BGE executed one and two-year contracts for commercial and industrial electric power supply totaling approximately 2,300 megawatts.

Regulated Gas Competition

The wholesale price of natural gas is not subject to regulation. All BGE gas customers have the option to purchase gas from alternate suppliers.

Regulation by the Maryland PSC

In addition to electric restructuring, regulation by the Maryland PSC influences BGE's businesses. The Maryland PSC determines the rates that BGE can charge customers for the electric distribution and gas businesses. The Maryland PSC incorporates into BGE's electric rates the transmission rates determined by FERC. The rates for BGE's regulated gas business continue to consist of a "base rate" and a "fuel rate."

BGE may ask the Maryland PSC to increase base rates from time to time. The Maryland PSC historically has allowed BGE to increase base rates to recover increased utility plant asset costs and higher operating costs, plus a profit, beginning at the time of replacement. Generally, rate increases improve our utility earnings because they allow us to collect more revenue. However, rate increases are normally granted based on historical data, and those increases may not always keep pace with increasing costs. Other parties may petition the Maryland PSC to decrease base rates.

Electric Base Rates

BGE's electric rates are unbundled to show separate components for delivery service, competitive transition charges, standard offer services (generation), transmission, universal service, and taxes. As a result of the deregulation of electric generation in Maryland, BGE's residential electric base rates are frozen until June 30, 2006. Electric delivery service rates were frozen until June 30, 2004 for commercial and industrial customers. The generation and transmission components of rates are frozen for different time periods depending on the service options selected by those customers. We discuss the impact on base rates beyond 2004 in the Regulated Electric Competition—Maryland section on page 27.

Gas Base Rate

The base rate is the rate the Maryland PSC allows BGE to charge its customers for the cost of providing them service, plus a profit. Gas base rates are not affected by seasonal changes.

Gas Fuel Rate

BGE charges its gas customers separately for natural gas purchases. The price charged for the natural gas is based on a market-based rates incentive mechanism approved by the Maryland PSC. We discuss market-based rates in more detail in the Gas Cost Adjustments section on page 49 and in Note 1 of our 2003 Annual Report on Form 10-K.

FERC Regulation

Regional Transmission Organizations and StandardMarket Design

In 1997, BGE turned over the operation of its transmission facilities to PJM, a power pool in the Mid-Atlantic region. In December 1999, FERC issued Order 2000, amending its regulations under the Federal Power Act to advance the formation of Regional Transmission Organizations (RTOs) that would allow easier access to transmission. PJM received FERC approval of its RTO status in December 2002 pending certain compliance filings.

On July 31, 2002, the FERC issued a proposed rulemaking regarding implementation of a standard market design (SMD) for wholesale electric markets. The SMD rulemaking is intended to complement FERC's RTO order, and would require RTOs to substantially comply with its provisions. The SMD proposals also required transmission providers to turn over the operation of their facilities to an independent operator that will operate them consistent with a revised market structure proposed by the FERC. According to the FERC, the revised market structure will reduce inefficiencies caused by inconsistent market rules and barriers to transmission access. The FERC proposed that its rule be implemented in stages by October 1, 2004. Comments on the SMD proposal were submitted in February 2003.

In April 2003, the FERC issued a report that indicated its position with respect to the proposed rulemaking and announced that it intends to leave relatively unmodified existing RTO practices, to allow flexibility among regional approaches, to allow phased-in implementation of the final rule, and to provide an increased deference to states' concerns. Concurrently, proposed federal legislation has been introduced that would remand the rulemaking process to FERC, require the issuance of a new notice of proposed rulemaking, and delay the issuance of a final rule until at least January 1, 2007.

We believe that while the original SMD proposal would have led to uniform rules that would have been largely favorable to Constellation Energy and BGE, the revised regional approach should result in improved market operations across various regions. The proposed federal legislation does not appear to exclude a regional approach to market development. Overall, the trend continues to be toward increased competition in the regions. The region where BGE operates is expected to be relatively unaffected by this proceeding, based on current compliance by the PJM with the SMD proposal.

However, there are a number of proceedings at the FERC that may affect the transmission revenues of BGE and other transmission owners in PJM. In addition, there are continued market developments both in PJM and in other regions, such as the Mid-West, New York, and New England that have the potential to impact our financial results. However, at this time, we cannot predict the outcome of these proceedings or the possible effect on our, or BGE's, financial results.

Weather

Merchant Energy Business

Weather conditions in the different regions of North America influence the financial results of our merchant energy business. Weather conditions can affect the supply of and demand for electricity and fuels, and changes in energy supply and demand may impact the price of these energy commodities in both the spot market and the forward market. Typically, demand for electricity and its price are higher in the summer and the winter, when weather is more extreme. Similarly, the demand for and price of natural gas and oil are higher in the winter. However, all regions of North America typically do not experience extreme weather conditions at the same time.

BGE

Weather affects the demand for electricity and gas for our regulated businesses. Very hot summers and very cold winters increase demand. Mild weather reduces demand. Residential sales for our regulated businesses are impacted more by weather than commercial and industrial sales, which are mostly affected by business needs for electricity and gas.

However, the Maryland PSC allows us to record a monthly adjustment to our regulated gas business revenues to eliminate the effect of abnormal weather patterns. We discuss this further in the Weather Normalization section on page 49.

BGE measures the weather's effect using "degree-days." The measure of degree-days for a given day is the difference between the average daily actual temperature and a baseline temperature of 65 degrees. Cooling degree-days result when the average daily actual temperature exceeds the 65 degree baseline, adjusted for humidity levels. Heating degree-days result when the average daily actual temperature is less than the baseline.

During the cooling season, hotter weather is measured by more cooling degree-days and results in greater demand for electricity to operate cooling systems. During the heating season, colder weather is measured by more heating degree-days and results in greater demand for electricity and gas to operate heating systems.

We show the number of heating and cooling degree-days in the quarters and six months ended June 30, 2004 and 2003, and the percentage change in the number of degree-days between these periods in the following table:

	Quarter Ended June 30,		Six Months Ended June 30,
	2004	2003	2004	2003

Heating degree days	458	667	3,062	3,425
Percent change from prior period	(31.3)%		(10.6)%
Cooling degree days	291	153	293	153
Percent change from prior period	90.1%		91.5%

Other Factors

A number of other factors significantly influence the level and volatility of prices for energy commodities and related derivative products for our merchant energy business. These factors include:

•: seasonal daily and hourly changes in demand,
•: number of market participants,
•: extreme peak demands,
•: available supply resources,
•: transportation availability and reliability within and between regions,
•: location of our generating facilities relative to the location of our load-serving obligations,
•: implementation of new market rules governing the operations of regional power pools,
•: procedures used to maintain the integrity of the physical electricity system during extreme conditions, and
•: changes in the nature and extent of federal and state regulations.

Our merchant energy business contracts with rail companies to ensure the delivery of coal to our coal-fired generation facilities. The timely delivery of coal together with the maintenance of appropriate inventory levels is necessary to allow for continued, reliable generation from these facilities. In the second quarter of 2004, we began to experience delays in deliveries from one of the rail companies that supplies coal to our generating facilities. Should we be unable to obtain sufficient coal deliveries to operate our coal-fired plants, we would need to purchase power from an alternative source or procure coal using an alternative delivery method to meet our contractual load obligations, which could have a material impact on our financial results.

These other factors can affect energy commodity and derivative prices in different ways and to different degrees. These effects may vary throughout the country as a result of regional differences in:

•: weather conditions,
•: market liquidity,
•: capability and reliability of the physical electricity and gas systems, and
•: the nature and extent of electricity deregulation.

Other factors, aside from weather, also impact the demand for electricity and gas in our regulated businesses. These factors include the number of customers and usage per customer during a given period. We use these terms later in our discussions of regulated electric and gas operations. In those sections, we discuss how these and other factors affected electric and gas sales during the periods presented.

The number of customers in a given period is affected by new home and apartment construction and by the number of businesses in our service territory.

Usage per customer refers to all other items impacting customer sales that cannot be measured separately. These factors include the strength of the economy in our service territory. When the economy is healthy and expanding, customers tend to consume more electricity and gas. Conversely, during an economic downtrend, our customers tend to consume less electricity and gas.

Accounting Standards Adopted and Issued

We discuss recently adopted and issued accounting standards in the Notes to Consolidated Financial Statements on page 23.

Critical Accounting Policies

Our discussion and analysis of financial condition and results of operations are based on our consolidated financial statements that were prepared in accordance with accounting principles generally accepted in the United States of America. Management makes estimates and assumptions when preparing financial statements. These estimates and assumptions affect various matters, including:

•: our reported amounts of revenues and expenses in our Consolidated Statements of Income,
•: our reported amounts of assets and liabilities in our Consolidated Balance Sheets, and
•: our disclosure of contingent assets and liabilities.

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

The Securities and Exchange Commission (SEC) issued disclosure guidance for accounting policies that management believes are most "critical." The SEC defines these critical accounting policies as those that are both most important to the portrayal of a company's financial condition and results of operations and require management's most difficult, subjective, or complex judgment, often as a result of the need to make estimates about the effect of matters that are inherently uncertain and may change in subsequent periods.

Management believes the following accounting policies represent critical accounting policies as defined by the SEC. We discuss our significant accounting policies, including those that do not require management to make difficult, subjective, or complex judgments or estimates, in Note 1 of our 2003 Annual Report on Form 10-K.

Revenue Recognition—Mark-to-Market Methodof Accounting

Our merchant energy business enters into contracts for energy, other energy-related commodities, and related derivatives. We record merchant energy business revenues using two methods of accounting: accrual accounting and mark-to-market accounting. We describe our use of accrual accounting (including hedge accounting) in more detail in Note 1 of our 2003 Annual Report on Form 10-K.

We record revenues using the mark-to-market method of accounting for derivative contracts for which we are not permitted to use accrual accounting or hedge accounting. These mark-to-market activities include derivative contracts for energy and other energy-related commodities. Under the mark-to-market method of accounting, we record the fair value of these derivatives as mark-to-market energy assets and liabilities at the time of contract execution. We record the changes in mark-to-market energy assets and liabilities on a net basis in "Nonregulated revenues" in our Consolidated Statements of Income.

Mark-to-market energy assets and liabilities consist of a combination of energy and energy-related derivative contracts. While some of these contracts represent commodities or instruments for which prices are available from external sources, other commodities and certain contracts are not actively traded and are valued using modeling techniques to determine expected future market prices, contract quantities, or both. The market prices and quantities used to determine fair value reflect management's best estimate considering various factors. However, 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 record reserves to reflect uncertainties associated with certain estimates inherent in the determination of the fair value of mark-to-market energy assets and liabilities. The effect of these uncertainties is not incorporated in market price information or other market-based estimates used to determine fair value of our mark-to-market energy contracts. To the extent possible, we utilize market-based data together with quantitative methods for both measuring the uncertainties for which we record reserves and determining the level of such reserves and changes in those levels.

We describe below the main types of reserves we record and the process for establishing each. Generally, increases in reserves reduce our earnings, and decreases in reserves increase our earnings. However, all or a portion of the effect on earnings of changes in reserves may be offset by changes in the value of the underlying positions.

•: Close-out reserve—this reserve represents the estimated cost to close out or sell to a third-party open mark-to-market positions. This reserve has the effect of valuing "long" positions at the bid price and "short" positions at the offer price. We compute this reserve using a market-based estimate of the bid/offer spread for each commodity and option price and the absolute quantity of our net open positions for each year. To the extent that we are not able to obtain market information for similar contracts, the close-out reserve is equivalent to the initial contract margin, thereby resulting in no gain or loss at inception. The level of total close-out reserves increases as we have larger unhedged positions, bid-offer spreads increase, or market information is not available, and it decreases as we reduce our unhedged positions, bid-offer spreads decrease, or market information becomes available.
•: Credit-spread adjustment—for risk management purposes, we compute the value of our mark-to-market energy assets and liabilities using a risk-free discount rate. In order to compute fair value for financial reporting purposes, we adjust the value of our mark-to-market energy assets to reflect the credit-worthiness of each counterparty based upon published credit ratings, where available, or equivalent internal credit ratings and associated default probability percentages. We compute this reserve by applying the appropriate default probability percentage to our outstanding credit exposure, net of collateral, for each counterparty. The level of this reserve increases as our credit exposure to counterparties increases, the maturity terms of our transactions increase, or the credit ratings of our counterparties deteriorate, and it decreases when our credit exposure to counterparties decreases, the maturity terms of our transactions decrease, or the credit ratings of our counterparties improve.

Market prices for energy and energy-related commodities vary based upon a number of factors, and changes in market prices affect both the recorded fair value of our mark-to-market energy contracts and the level of future revenues and costs associated with accrual-basis activities. Changes in the value of our mark-to-market energy contracts will affect our earnings in the period of the change, while changes in forward market prices related to accrual-basis revenues and costs will affect our earnings in future periods to the extent those prices are realized. We cannot predict whether, or to what extent, the factors affecting market prices may change, but those changes could be material and could affect us either favorably or unfavorably. We discuss our market risk in more detail in the Market Risk section on page 57.

The impact of derivative contracts on our revenues and costs is affected by many factors, including:

•: our ability to designate and qualify derivative contracts for normal purchase and sale accounting or hedge accounting under Statement of Financial Accounting Standards (SFAS) No. 133, Accounting for Derivative Instruments and Hedging Activities, as amended,
•: potential volatility in earnings from derivative contracts that serve as economic hedges but do not meet the accounting requirements to qualify for normal purchase and sale accounting or hedge accounting,
•: our ability to enter into new mark-to-market derivative origination transactions, and

•: sufficient liquidity and transparency in the energy markets to permit us to record gains at inception of new derivative contracts because fair value is evidenced by quoted market prices, current market transactions, or other observable market information.

We discuss the impact of mark-to-market accounting on our financial results in the Results of Operations—Merchant Energy Business section on page 38.

Evaluation of Assets for Impairment and OtherThan Temporary Decline in Value

Long-Lived Assets

We are required to evaluate certain assets that have long lives (for example, generating property and equipment and real estate) to determine if they are impaired when certain conditions exist. SFAS No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets, provides the accounting for impairments of long-lived assets. We are required to test our long-lived assets for recoverability whenever events or changes in circumstances indicate that their carrying amount may not be recoverable. Examples of such events or changes are:

•: a significant decrease in the market price of a long-lived asset,
•: a significant adverse change in the manner an asset is being used or its physical condition,
•: an adverse action by a regulator or in the business climate,
•: an accumulation of costs significantly in excess of the amount originally expected for the construction or acquisition of an asset,
•: a current-period loss combined with a history of losses or the projection of future losses, or
•: a change in our intent about an asset from an intent to hold to a greater than 50% likelihood that an asset will be sold or disposed of before the end of its previously estimated useful life.

For long-lived assets that are expected to be held and used, SFAS No. 144 provides that an impairment loss shall only be recognized if the carrying amount of an asset is not recoverable and exceeds its fair value. The carrying amount of an asset is not recoverable under SFAS No. 144 if the carrying amount exceeds the sum of the undiscounted future cash flows expected to result from the use and eventual disposition of the asset. Therefore, when we believe an impairment condition may have occurred, we are required to estimate the undiscounted future cash flows associated with a long-lived asset or group of long-lived assets. This necessarily involves judgment surrounding the inherent uncertainty of future cash flows.

In order to estimate an asset's future cash flows, we consider historical cash flows, as well as reflect our understanding of the extent to which future cash flows will be either similar to or different from past experience based on all available evidence. To the extent applicable, the assumptions we use are consistent with forecasts that we are otherwise required to make (for example, in preparing our other earnings forecasts). If we are considering alternative courses of action to recover the carrying amount of a long-lived asset (such as the potential sale of an asset), we probability-weight the alternative courses of action to estimate the cash flows.

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

For long-lived assets that can be classified as assets held for sale under SFAS No. 144, an impairment loss is recognized to the extent their carrying amount exceeds their fair value less costs to sell.

If we determine that the undiscounted cash flows from an asset to be held and used are less than the carrying amount of the asset, or if we have classified an asset as held for sale, we must estimate fair value to determine the amount of any impairment loss. The estimation of fair value under SFAS No. 144, whether in conjunction with an asset to be held and used or with an asset held for sale, also involves judgment. We consider quoted market prices in active markets to the extent they are available. In the absence of such information, we may consider prices of similar assets, consult with brokers, or employ other valuation techniques. Often, we will discount the estimated future cash flows associated with the asset using a single interest rate that is commensurate with the risk involved with such an investment or employ an expected present value method that probability-weights a range of possible outcomes. The use of these methods involves the same inherent uncertainty of future cash flows as discussed above with respect to undiscounted cash flows. Actual future market prices and project costs could vary from those used in our estimates, and the impact of such variations could be material.

We are also required to evaluate our equity-method and cost-method investments (for example, in partnerships that own power projects) to determine whether or not they are impaired. Accounting Principles Board Opinion (APB) No. 18, The Equity Method of Accounting for Investments in Common Stock, provides the accounting for these investments. The standard for determining whether an impairment must be recorded under APB No. 18 is whether the investment has experienced a loss in value that is considered an "other than a temporary" decline in value.

The evaluation and measurement of impairments under the APB No. 18 standard involves the same uncertainties as described above for long-lived assets that we own directly and account for in accordance with SFAS No. 144. Similarly, the estimates that we make with respect to our equity and cost-method investments are subject to variation, and the impact of such variations could be material. Additionally, if the projects in which we hold these investments recognize an impairment under the provisions of SFAS No. 144, we would record our proportionate share of that impairment loss and would evaluate our investment for an other than temporary decline in value under APB No. 18.

Goodwill

Goodwill is the excess of the purchase price of an acquired business over the fair value of the net assets acquired. We do not amortize goodwill and certain other intangibles under the provisions of SFAS No. 142, Goodwill and Other Intangible Assets. SFAS No. 142 requires us to evaluate goodwill for impairment at least annually or more frequently if events and circumstances indicate the business might be impaired. Goodwill is impaired if the carrying value of the business exceeds fair value. Annually, we estimate the fair value of the businesses we have acquired using techniques similar to those used to estimate future cash flows for long-lived assets as discussed above, which involves judgment. If the estimated fair value of the business is less than its carrying value, an impairment loss is required to be recognized to the extent that the carrying value of goodwill is greater than its fair value.

Asset Retirement Obligations

We incur legal obligations associated with the retirement of certain long-lived assets. SFAS No. 143, Accounting for Asset Retirement Obligations, provides the accounting for legal obligations associated with the retirement of long-lived assets. We incur such legal obligations as a result of environmental and other government regulations, contractual agreements, and other factors. The application of this standard requires significant judgment due to the large number and diverse nature of the assets in our various businesses and the estimation of future cash flows required to measure legal obligations associated with the retirement of specific assets.

SFAS No. 143 requires the use of an expected present value methodology in measuring asset retirement obligations that involves judgment surrounding the inherent uncertainty of the probability, amount and timing of payments to settle these obligations, and the appropriate interest rates to discount future cash flows. We use our best estimates in identifying and measuring our asset retirement obligations in accordance with SFAS No. 143.

Our nuclear decommissioning costs represent our largest asset retirement obligation. This obligation primarily results from the requirement to decommission and decontaminate our nuclear generating facilities in connection with their future retirement. We utilize site-specific decommissioning cost estimates to determine our nuclear asset retirement obligations. However, given the magnitude of the amounts involved, complicated and ever-changing technical and regulatory requirements, and the very long time horizons involved, the actual obligation could vary from the assumptions used in our estimates, and the impact of such variations could be material.

Events of 2004

Loss from Discontinued Operations

Acquisition

We purchased 100 percent of Ginna for $454.4 million including direct costs associated with the acquisition, of which $430.0 million was paid in cash at closing. We accrued a liability for the remaining $24.4 million which we expect to pay, subject to any adjustments, in the third quarter of 2004 after the completion of a final valuation of certain assets and liabilities. RG&E also transferred to us $200.5 million in decommissioning funds.

We accounted for this transaction as an asset acquisition. Our preliminary purchase price allocation for the net assets acquired is as follows:

Ginna Net Assets Acquired

At June 10, 2004

	(In millions)
Current assets	$	27.6
Nuclear decommissioning trust fund		200.5
Nuclear fuel		14.3
Net property, plant and equipment		381.2
Intangible assets (details below)		38.4
Other assets		123.9

Total assets acquired		785.9
Current liabilities		20.9
Asset retirement obligations		177.3
Deferred credits and other liabilities		133.3

Net assets acquired	$	454.4

The intangible assets acquired consist of the following:

Description	Amount		Weighted-Average Useful Life

	(In millions)		(In years)
Operating procedures and manuals	$	25.9	25
Permits and licenses		8.4	25
Software		4.1	5

Total intangible assets	$	38.4

Synthetic Fuel Tax Credits

We have investments in facilities that manufacture solid synthetic fuel produced from coal as defined under Section 29 of the Internal Revenue Code for which we claim tax credits on our Federal income tax return. We recognize the tax benefit of these credits in our Consolidated Statements of Income when we believe it is highly probable that the credits will be sustained. The synthetic fuel process involves combining coal material with a chemical reagent to create a significant chemical change. A taxpayer may request a private letter ruling from the Internal Revenue Service (IRS) to support its position that the synthetic fuel produced undergoes a significant chemical change and thus qualifies for Section 29 credits.

On April 15, 2004, we received a favorable private letter ruling. We believe receipt of the private letter ruling provides assurance that it is highly probable that the credits will be sustained. Therefore, we recognized the tax benefit of $35.9 million in our Consolidated Statements of Income during the quarter ended June 30, 2004.

Impairment of Financial Investment

Gains on Sale of Investments and Other Assets

During the six months ended June 30, 2004, our other nonregulated businesses recognized $5.9 million pre-tax, or $3.7 million after-tax, gains on the sale of non-core assets as follows:

•: a $1.1 million pre-tax gain in the first quarter on an installment sale of real estate,
•: a $0.4 million pre-tax gain in the first quarter on the sale of a financial investment,
•: a $3.3 million pre-tax gain in the second quarter on the sale of a financial investment, and
•: a $1.1 million pre-tax gain in the second quarter on the sale of real estate.

Dividend Increase

In January 2004, we announced an increase in our quarterly dividend to 28.5 cents per share on our common stock. This is equivalent to an annual rate of $1.14 per share. Previously, our quarterly dividend on our common stock was 26 cents per share, equivalent to an annual rate of $1.04 per share.

Results of Operations for the Quarter and Six Months Ended June 30, 2004 Compared with the Same Periods of 2003

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 51.

Overview

Results

		Quarter Ended June 30,						Six Months Ended June 30,
		2004			2003			2004			2003

		(In millions, after-tax)
Merchant energy		$	109.2		$	75.2		$	148.7		$	54.7
Regulated electric			25.2			20.8			70.3			71.0
Regulated gas			(3.3	)		0.9			24.5			29.5
Other nonregulated			(0.2	)		(0.1	)		(0.1	)		8.6

Income from Continuing Operations and Before Cumulative Effects of Changes in Accounting Principles			130.9			96.8			243.4			163.8
Loss from Discontinued Operations (see Notes)			(2.7	)		—			(49.0	)		—
Cumulative Effects of Changes in Accounting Principles			—			—			—			(198.4	)

Net Income (Loss)		$	128.2		$	96.8		$	194.4		$	(34.6	)

*Special Items Included in Operations*
	Recognition of 2003 synthetic fuel tax credits	$	35.9		$	—		$	35.9		$	—
	Net gains on sale of investments and other assets		2.7			0.3			3.7			8.6
	Impairment losses and other costs		(1.6	)		—			(1.6	)		—
	Workforce reduction costs		—			(0.4	)		—			(0.8	)

Total Special Items		$	37.0		$	(0.1	)	$	38.0		$	7.8

Quarter Ended June 30, 2004

Our total net income for the quarter ended June 30, 2004 increased $31.4 million, or $0.18 per share, compared to the same period of 2003 mostly because of the following:

•: Our merchant energy business had higher earnings of $47.2 million at our South Carolina synfuel facility primarily due to the recognition of tax credits claimed in 2003 and tax credits associated with 2004 production.
•: Our merchant energy business had higher earnings due to the realization of wholesale contracts originated in prior periods, portfolio management, and a bankruptcy settlement from PG&E at NewEnergy.
•: We had higher earnings from our High Desert power project, which was acquired in late April 2003 and earnings from Ginna, which was acquired in early June 2004.
•: We had higher earnings from our regulated electric business due to warmer weather in the second quarter of 2004 compared to the same period of 2003.

These increases were partially offset by the following:

•: We recognized a gain on the assumption of an agreement from Allegheny Energy Supply Company, LLC (Allegheny) in the second quarter of 2003 that had a positive impact in that period.
•: We had lower earnings from our nuclear generating assets primarily due to our planned refueling outages. Calvert Cliffs' outage days in the second quarter of 2004 exceeded the number of outage days in the second quarter of 2003. Nine Mile Point had lower earnings due to the refueling of the larger unit in 2004 and lower power purchase agreement prices during the second quarter of 2004 compared to the same period in 2003.
•: We had higher Sarbanes-Oxley 404 implementation costs, information technology infrastructure expenditures, and benefit and other inflationary costs.
•: We had lower earnings from our regulated gas business primarily due to higher operating expenses.

Six Months Ended June 30, 2004

Our total net income for the six months ended June 30, 2004 increased $229.0 million, or $1.36 per share, compared to the same period of 2003 mostly because of the following:

•: In 2003, we recorded a $266.1 million after-tax, or $1.61 per share, loss for the cumulative effect of adopting Emerging Issues Task Force (EITF) Issue 02-3, Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities. This was partially offset by a $67.7 million after-tax, or $0.41 per share, gain for the cumulative effect of adopting SFAS No. 143. These items had a combined negative impact during the six months ended June 30, 2003.
•: Our merchant energy business had higher earnings of $54.6 million at our South Carolina synfuel facility primarily due to the recognition of tax credits claimed in 2003 and tax credits associated with 2004 production.
•: We had higher earnings from our nuclear generating assets due to reduced outage days at our Calvert Cliffs nuclear power plant, partially offset by lower earnings at our Nine Mile Point facility primarily associated with our planned outages and lower power prices for our output in 2004 compared to 2003.
•: We had higher earnings from our merchant energy business mostly due to the realization of wholesale contracts originated in prior periods, portfolio management, and a bankruptcy settlement from PG&E at NewEnergy.
•: We had higher earnings due to lower losses associated with economic hedges that did not qualify for cash-flow hedge accounting treatment in 2003.
•: We had higher earnings due to the High Desert Power Project that commenced operations in April 2003.

These increases were partially offset by the following:

•: We recorded a $49.0 million after-tax, or $0.29 per share, loss from discontinued operations.
•: We had higher Sarbanes-Oxley 404 implementation costs, information technology infrastructure expenditures, and benefit and other inflationary costs.
•: We had lower earnings from our regulated gas business mostly because of higher operating expenses in the first six months of 2004.
•: We recognized a gain of $8.6 million after-tax, or $0.05 per share, related to non-core asset sales in the six months ended June 30, 2003 that had a favorable impact in that period.

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 large customers in North America. We discuss the impact of deregulation on our merchant energy business in the Business Environment—Electric Competition section of our 2003 Annual Report on Form 10-K.

We record merchant energy revenues and expenses in our financial results in different periods depending upon which portion of our business they affect. We discuss our revenue recognition policies in the Critical Accounting Policies section on page 31 and in Note 1 of our 2003 Annual Report on Form 10-K. We summarize our 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 the 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 on a net basis in the period in which the change occurs.

Mark-to-market accounting requires us to make estimates and assumptions using judgment in determining the fair value of our contracts and in recording revenues from those contracts. We discuss the effects of mark-to-market accounting on our revenues in the Competitive Supply—Mark-to-Market Revenues section on page 42. We discuss mark-to-market accounting and the accounting policies for the merchant energy business further in the Critical Accounting Policies section on page 31 and in Note 1 of our 2003 Annual Report on Form 10-K.

Results

	Quarter Ended June 30,						Six Months Ended June 30,
	2004			2003			2004			2003

				(In millions)
Revenues	$	2,367.7		$	1,822.6		$	4,752.5		$	3,495.8
Fuel and purchased energy expenses		(1,833.7	)		(1,312.0	)		(3,781.4	)		(2,698.2	)
Operations and maintenance expenses		(318.8	)		(266.8	)		(591.9	)		(479.5	)
Workforce reduction costs		—			(0.4	)		—			(0.8	)
Depreciation and amortization		(61.4	)		(56.6	)		(117.1	)		(107.5	)
Accretion of asset retirement obligations		(12.4	)		(10.7	)		(23.5	)		(21.3	)
Taxes other than income taxes		(21.2	)		(24.1	)		(43.0	)		(46.4	)

Income from Operations	$	120.2		$	152.0		$	195.6		$	142.1

Income from Continuing Operations and Before Cumulative Effects of Changes in Accounting Principles (after-tax)	$	109.2		$	75.2		$	148.7		$	54.7
Loss from Discontinued Operations (after-tax)		(2.7	)		—			(49.0	)		—
Cumulative Effects of Changes in Accounting Principles (after-tax)		—			—			—			(198.4	)

Net Income (Loss)	$	106.5		$	75.2		$	99.7		$	(143.7	)

Special Items Included in Operations (after-tax)
Recognition of 2003 synthetic fuel tax credits	$	35.9		$	—		$	35.9		$	—
Workforce reduction costs		—			(0.3	)		—			(0.5	)

Total Special Items	$	35.9		$	(0.3	)	$	35.9		$	(0.5	)

Above amounts include intercompany transactions eliminated in our Consolidated Financial Statements. The Information by Operating Segment section within the Notes to Consolidated Financial Statements on page 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 our costs of procuring fuel and energy and revenues we realize from the sale of energy to our customers. The difference between revenues and fuel and purchased energy expenses is the primary driver of 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 the relationship between revenues and fuel and purchased energy expenses. In managing our portfolio, we occasionally 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 and fuel and purchased energy expenses.

We analyze our merchant energy revenues and fuel and purchased energy expenses in the following categories because of the risk profile of each category, differences in the revenue sources, and the nature of fuel and purchased energy expenses. With the exception of a portion of our competitive supply activities that we are required to account for using the mark-to-market method of accounting, all of these activities are accounted for on an accrual basis.

•: Mid-Atlantic Fleet—our fossil, nuclear, and hydroelectric generating facilities and load-serving activities in the PJM region for which the output is primarily used to serve BGE. This also includes active portfolio management of the generating assets and associated physical and financial arrangements.
•: Plants with Power Purchase Agreements—our generating facilities outside the Mid-Atlantic region with long-term power purchase agreements, including our Nine Mile Point Nuclear Station (Nine Mile Point), Ginna, Oleander, University Park, and High Desert facilities.
•: Competitive Supply—our wholesale marketing and risk management operation that provides energy products and services to distribution utilities and other wholesale customers. This category includes our remaining generating facilities whose output is primarily used in managing our competitive supply activities outside the PJM region. We also provide electric and gas energy services to retail commercial and industrial customers.
•: Other—our investments in qualifying facilities and domestic power projects and our generation and consulting services.

We provide a summary of our revenues and fuel and purchased energy expenses as follows:

		Quarter Ended June 30,										Six Months Ended June 30,
		2004					2003					2004					2003

		(Dollar amounts in millions)
Revenues:
	Mid-Atlantic Fleet	$	425.4				$	465.3				$	856.7				$	841.0
	Plants with Power Purchase Agreements		158.9					156.8					292.7					266.0
	Competitive Supply		1,774.0					1,193.7					3,573.5					2,366.9
	Other		9.4					6.8					29.6					21.9

	Total	$	2,367.7				$	1,822.6				$	4,752.5				$	3,495.8

Fuel and purchased energy expenses:
	Mid-Atlantic Fleet	$	(172.2	)			$	(188.0	)			$	(399.7	)			$	(393.5	)
	Plants with Power Purchase Agreements		(13.5	)				(11.1	)				(24.0	)				(23.8	)
	Competitive Supply		(1,648.0	)				(1,112.9	)				(3,357.7	)				(2,280.9	)
	Other		—					—					—					—

	Total	$	(1,833.7	)			$	(1,312.0	)			$	(3,781.4	)			$	(2,698.2	)

Revenues less fuel and purchased energy expenses:					% of Total					% of Total					% of Total					% of Total
	Mid-Atlantic Fleet	$	253.2		47	%	$	277.3		54	%	$	457.0		47	%	$	447.5		56	%
	Plants with Power Purchase Agreements		145.4		27			145.7		29			268.7		28			242.2		30
	Competitive Supply		126.0		23			80.8		16			215.8		22			86.0		11
	Other		9.4		3			6.8		1			29.6		3			21.9		3

	Total	$	534.0		100	%	$	510.6		100	%	$	971.1		100	%	$	797.6		100	%

Mid-Atlantic Fleet

	Quarter Ended June 30,						Six Months Ended June 30,
	2004			2003			2004			2003

	(In millions)
Revenues	$	425.4		$	465.3		$	856.7		$	841.0
Fuel and purchased energy expenses		(172.2	)		(188.0	)		(399.7	)		(393.5	)

Revenues less fuel and purchased energy	$	253.2		$	277.3		$	457.0		$	447.5

Revenues

BGE Standard Offer Service

The majority of Mid-Atlantic Fleet revenues arise from supplying BGE's standard offer service requirements. Revenues from supplying BGE's standard offer service requirements, including CTC and decommissioning revenues, increased $19.4 million for the quarter ended June 30, 2004 compared to the same period of 2003 and increased $15.5 million for the six months ended June 30, 2004 compared to the same period of 2003 primarily due to warmer weather during the second quarter of 2004 in the central Maryland region.

CTC revenues are impacted by the CTC rates our merchant energy business receives from BGE customers, as well as the volumes delivered to BGE customers. The CTC rates decline over the transition period as previously discussed in the Regulated Electric Competition—Maryland section on page 27.

During 2003, our merchant energy business provided the energy to meet the requirements of large commercial and industrial customers that had left BGE's standard offer service and elected BGE Home as their electric generation supplier. Revenues from BGE Home were $21.6 million in the second quarter of 2003 and $41.1 million for the six months ended June 30, 2003, which had a positive impact in those periods. As these customer contracts expired during 2003, any renewal was with our commercial and industrial retail marketing operation and the results are included in our Competitive Supply category.

Other Mid-Atlantic Fleet Revenues

Other merchant energy revenues in the PJM region decreased $38.0 million for the second quarter of 2004 compared to the same period of 2003 mostly because of the following:

•: lower revenue due to a reduction in the amount of excess generation available for sale to the market in the PJM region mostly because of load-serving obligations in New Jersey that began in mid-2003 and increased sales to our commercial and industrial retail marketing operation, and
•: the recognition of a gain on the assumption of an agreement from Allegheny in the second quarter of 2003 that had a positive impact in that period.

For the six months ended June 30, 2004, other merchant energy revenues in the PJM region increased $41.3 million compared to the same period of 2003 mostly because of revenues of $97.3 million related to load-serving transactions in New Jersey that began in mid-2003. This increase in revenue was offset in part by lower revenues of $56.0 million primarily related to lower revenue due to a reduction in the amount of excess generation available for sale to the market in the PJM region and the recognition of a gain on the assumption of an agreement from Allegheny in the second quarter of 2003 that had a positive impact in that period.

Fuel and Purchased Energy Expenses

Our merchant energy business had lower fuel and purchased energy expenses in the Mid-Atlantic Fleet during the three months ended June 30, 2004 compared to the same period of 2003 primarily due to a reduction in the amount of excess generation available for sale to the market in the PJM region. This decrease was partially offset by an increase related to our load-serving transactions in New Jersey that began in mid-2003.

Our merchant energy business had higher fuel and purchased energy expenses in the Mid-Atlantic Fleet during the six months ended June 30, 2004 compared to the same period of 2003 primarily because of higher generation at our plants and increased purchased energy and capacity expenses.

Plants with Power Purchase Agreements

	Quarter Ended June 30,						Six Months Ended June 30,
	2004			2003			2004			2003

	(In millions)
Revenues	$	158.9		$	156.8		$	292.7		$	266.0
Fuel and purchased energy expenses		(13.5	)		(11.1	)		(24.0	)		(23.8	)

Revenues less fuel and purchased energy	$	145.4		$	145.7		$	268.7		$	242.2

The increase in revenues for the six months ended June 30, 2004 compared to the same period of 2003 was primarily due to higher revenues of $45.2 million from the High Desert Power Project which commenced operations in the second quarter of 2003 and revenues of $11.0 million from Ginna which was purchased in June 2004. We discuss the acquisition of Ginna in more detail in the Events of 2004 section on page 35. This increase was offset in part by lower revenues of $23.4 million from our Nine Mile Point facility mostly because of lower generation at the plant during the six months ended June 30, 2004 and lower power prices for our output in 2004 compared to 2003.

Competitive Supply

	Quarter Ended June 30,						Six Months Ended June 30,
	2004			2003			2004			2003

	(In millions)
Accrual revenues	$	1,760.4		$	1,192.2		$	3,551.7		$	2,372.5
Mark-to-market revenues		13.6			1.5			21.8			(5.6	)
Fuel and purchased energy expenses		(1,648.0	)		(1,112.9	)		(3,357.7	)		(2,280.9	)

Revenues less fuel and purchased energy	$	126.0		$	80.8		$	215.8		$	86.0

We analyze our accrual and mark-to-market competitive supply activities separately on the next page.

Accrual Revenues and Fuel and Purchased Energy Expenses

Our accrual revenues and fuel and purchased energy expenses increased during the quarter and six months ended June 30, 2004 compared to the same periods of 2003 mostly because of retail sales to commercial and industrial customers. This increase in retail sales is primarily due to:

•: new customer contracts,
•: customer renewals,
•: portfolio acquisitions during 2003,
•: the acquisitions of Blackhawk and Kaztex in October 2003, and
•: the collection of a receivable that was previously reserved due the the financial condition of our customer, PG&E.

Additionally, our wholesale marketing and risk management operation had higher sales primarily in the Texas, New England, Mid-West regions, and Canada. The higher sales in the Texas and New England regions are primarily due to our growth in these regions. The increased sales in the Mid-West are primarily due to the portfolio acquisition from CMS Energy Corp., which occurred in the second quarter of 2003.

Mark-to-Market Revenues

Mark-to-market revenues include net gains and losses from origination 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 on page 31.

As a result of the nature of our operations and the use of mark-to-market accounting for certain activities, mark-to-market revenues and earnings will fluctuate. We cannot predict these fluctuations, but the impact on our revenues and earnings could be material. We discuss our market risk in more detail in the Market Risk section on page 57. The primary factors that cause fluctuations in our mark-to-market revenues and earnings are:

•: the number, size, and profitability of new transactions,
•: the number and size of our open derivative positions, and
•: changes in the level and volatility of forward commodity prices and interest rates.

Mark-to-market revenues were as follows:

			Quarter Ended June 30,						Six Months Ended June 30,
			2004			2003			2004			2003

			(In millions)
Unrealized revenues
	Origination transactions		$	9.6		$	10.9		$	9.6		$	25.1

	Risk management
		Unrealized changes in fair value		4.0			(9.4	)		12.2			(30.7	)
		Changes in valuation techniques		—			—			—			—
		Reclassification of settled contracts to realized		(21.2	)		(79.6	)		(36.2	)		(61.5	)

		Total risk management		(17.2	)		(89.0	)		(24.0	)		(92.2	)

Total unrealized revenues*				(7.6	)		(78.1	)		(14.4	)		(67.1	)
Realized revenues				21.2			79.6			36.2			61.5

Total mark-to-market revenues			$	13.6		$	1.5		$	21.8		$	(5.6	)

* Total unrealized revenues is the sum of origination transactions and total risk management.

Origination gains arise from contracts that our wholesale marketing and risk management operation structure to meet the risk management needs of our customers. Transactions that result in origination gains may be unique and provide the potential for individually significant revenues and gains from a single transaction.

Origination gains represent the initial fair value recognized on these structured transactions. The recognition of origination gains is dependent on the existence of observable market data that validates the initial fair value of the contract. For the quarter and six months ended June 30, 2004, we recognized $9.6 million in origination gains from seven transactions.

As noted above, the recognition of origination gains is dependent on sufficient observable market data. Liquidity and market conditions impact our ability to identify sufficient, objective market-price information to permit recognition of origination gains. As a result, while our strategy and competitive position provide the opportunity to continue to originate such transactions, the level of origination revenue we are able to recognize may vary from year to year as a result of the number, size, and market-price transparency of the individual transactions executed in any period.

Risk management revenues represent both realized and unrealized gains and losses from changes in the value of our entire portfolio, including the recognition of gains associated with decreases in the close-out reserve when we are able to obtain sufficient market price information. We discuss the changes in mark-to-market revenues below. We show the relationship between our revenues and the change in our net mark-to-market energy asset/liability later in this section.

Our mark-to-market revenues are affected by the portion of our activities that are subject to mark-to-market accounting. Beginning January 1, 2003, under EITF 02-3, we do not record non-derivative contracts at fair value. Further, to the extent that we are not able to observe quoted market prices or other current market transactions for derivative contract values determined using models, we record a reserve to adjust such contracts to result in zero gain or loss at inception. We remove the reserve and record such contracts at fair value when we obtain current market information for contracts with similar terms and counterparties.

Mark-to-market revenues increased $12.1 million during the second quarter of 2004 compared to the same period of 2003 mostly because of lower net losses from risk management activities compared to the prior year. The increase in risk management revenues is primarily due to lower mark-to-market losses on hedges that did not qualify for hedge accounting treatment in 2004 compared to 2003 as discussed in more detail below, offset in part by higher origination gains in 2003.

Mark-to-market revenues increased $27.4 million during the six months ended June 30, 2004 compared to the same period of 2003 mostly because of lower net losses from risk management activities compared to the prior year. The increase in risk management revenues is primarily due to lower mark-to-market losses on hedges that did not qualify for hedge accounting treatment in 2004 compared to 2003 as discussed in more detail below, offset in part by higher origination gains in 2003.

With the implementation of EITF 02-3 in the first quarter of 2003, all of our load-serving contracts were converted to accrual accounting. However, several economically effective hedges on these positions did not qualify for hedge accounting treatment under SFAS No. 133 and remained in the mark-to-market portfolio. As a result, we recorded a lower pre-tax loss of $11.2 million on the mark-to-market hedges during the second quarter of 2004 compared to the same period of 2003 and a lower pre-tax loss of $27.7 million during the six months ended June 30, 2004 compared to the same period of 2003. These mark-to-market losses will be offset as we realize the related accrual load-serving position in cash.

Mark-to-Market Energy Assets and Liabilities

Our mark-to-market energy assets and liabilities are comprised of derivative contracts and consisted of the following:

	June 30, 2004			December 31, 2003

	(In millions)
Current Assets	$	514.1		$	488.3
Noncurrent Assets		368.5			261.9

Total Assets		882.6			750.2

Current Liabilities		539.9			474.6
Noncurrent Liabilities		354.3			258.0

Total Liabilities		894.2			732.6

Net mark-to-market energy (liability) asset	$	(11.6	)	$	17.6

The following are the primary sources of the change in net mark-to-market energy asset/liability during the first quarter of 2004:

Change in Net Mark-to-Market Asset/Liability

		Quarter Ended June 30, 2004		Six Months Ended June 30, 2004

		(In millions)
Fair value beginning of period		$ 13.6		$ 17.6
Changes in fair value recorded as revenues
	Origination gains	$ 9.6		$ 9.6
	Unrealized changes in fair value	4.0		12.2
	Changes in valuation techniques	—		—
	Reclassification of settled contracts to realized	(21.2)		(36.2)

Total changes in fair value recorded as revenues		(7.6	)	(14.4	)
Changes in value of exchange-listed futures and options		(25.4	)	(42.0	)
Net change in premiums on options		5.2		15.0
Other changes in fair value		2.6		12.2

Fair value at end of period		$(11.6	)	$(11.6	)

Components of changes in the net mark-to-market energy asset/liability that affected revenues include:

•: Origination gains representing 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 representing unrealized changes in commodity prices, the volatility of options on commodities, the time value of options, and other valuation adjustments.
•: Changes in valuation techniques representing 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 representing the portion of previously unrealized amounts settled during the period and recorded as realized revenues.

The net mark-to-market energy asset also changed due to the following items recorded in accounts other than revenue:

•: 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 "Mark-to-market energy 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 mark-to-market energy asset and premiums on options sold as a decrease in the net mark-to-market energy asset.

The settlement terms of the net mark-to-market energy asset and sources of fair value as of June 30, 2004 are as follows:

	Settlement Term
	Settlement Term																					Fair Value
	2004			2005			2006			2007			2008			2009			Thereafter			Fair Value

	(In millions)
Prices provided by external sources (1)	$	(24.1	)	$	20.4		$	7.1		$	(0.5	)	$	(1.2	)	$	—		$	—		$	1.7
Prices based on models		0.7			(11.3	)		(3.2	)		8.4			(1.8	)		(2.6	)		(3.5	)		(13.3	)

Total net mark-to-market energy (liability)/asset	$	(23.4	)	$	9.1		$	3.9		$	7.9		$	(3.0	)	$	(2.6	)	$	(3.5	)	$	(11.6	)

(1): Includes contracts actively quoted and contracts valued from other external sources.

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 record and 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).

Consistent with our risk management practices, we have presented the information in the table above based upon the ability to obtain reliable prices for components of the risks in our contracts from external sources rather than on a contract-by-contract basis. Thus, the portion of long-term contracts that is valued using external price sources is presented under the caption "prices provided by external sources." This is consistent with how we manage our risk, and we believe it provides the best indication of the basis for the valuation of our portfolio. Since we manage our risk on a portfolio basis rather than contract-by-contract, it is not practicable to determine separately the portion of long-term contracts that is included in each valuation category. We describe the commodities, products, and delivery periods included in each valuation category in detail on the next page.

The amounts for which fair value is determined using prices provided by external sources represent the portion of forward, swap, and option contracts for which price quotations are available through brokers or over-the-counter transactions. The term for which such price information is available varies by commodity, region, and product. The fair values included in this category are the following portions of our contracts:

•: forward purchases and sales of electricity during peak and off-peak hours for delivery terms primarily through 2006, but up to 2008, depending upon the region,
•: options for the purchase and sale of electricity during peak hours for delivery terms through 2005, depending upon the region,
•: forward purchases and sales of electric capacity for delivery terms through 2006,
•: forward purchases and sales of natural gas, coal, and oil for delivery terms through 2006, and
•: options for the purchase and sale of natural gas, coal, and oil for delivery terms through 2006.

The remainder of the net mark-to-market energy asset/liability is valued using models. The portion of contracts for which such techniques are used includes standard products for which external prices are not available and customized products that are valued using modeling techniques to determine expected future market prices, contract quantities, or both.

Modeling techniques include estimating the present value of cash flows based upon underlying contractual terms and incorporate, where appropriate, option pricing models and statistical and simulation procedures. Inputs to the models include:

•: observable market prices,
•: estimated market prices in the absence of quoted market prices,
•: the risk-free market discount rate,
•: volatility factors,
•: estimated correlation of energy commodity prices, and
•: expected generation profiles of specific regions.

Additionally, we incorporate counterparty-specific credit quality and factors for market price and volatility uncertainty and other risks in our valuation. The inputs and factors used to determine fair value reflect management's best estimates.

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 used in our wholesale marketing and risk management operation are direct contracts between market participants and are not exchange-traded or financially settling contracts that can be readily liquidated 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.

Consistent with our risk management practices, the amounts shown in the table on the previous page as being valued using prices from external sources include the portion of long-term contracts for which we can obtain reliable prices from external sources. The remaining portions of these long-term contracts are shown in the table as being valued using models. 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 table. However, based upon the nature of our wholesale marketing and risk management 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. We do not expect to realize the value of these contracts and related hedges by selling or assigning the contracts themselves in total.

The fair values in the table represent expected future cash flows based on the level of forward prices and volatility factors as of June 30, 2004 and could change significantly as a result of future changes in these factors. 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.

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. However, 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.

Other

	Quarter Ended June 30,				Six Months Ended June 30,
	2004		2003		2004		2003

	(In millions)
Revenues	$	9.4	$	6.8	$	29.6	$	21.9

Our merchant energy business holds up to a 50% ownership interest in 25 operating domestic energy projects that consist of electric generation, fuel processing, or fuel handling facilities. Of these 25 projects, 18 are "qualifying facilities" that receive certain exemptions and pricing under the Public Utility Regulatory Policy Act of 1978 based on the facilities' energy source or the use of a cogeneration process. In June 2004, we sold our geothermal generating facility in Hawaii. We discuss the sale of our geothermal facility in more detail in the Events of 2004 section on page 34.

We believe the current market conditions for our equity-method investments that own geothermal, coal, hydroelectric, and fuel processing projects provide sufficient positive cash flows to recover our investments. We continuously monitor issues that potentially could impact future profitability of these investments, including environmental and legislative initiatives. We discuss certain risks and uncertainties in more detail in our Forward Looking Statements section on page 63. However, should future events cause these investments to become uneconomic, our investments in these projects could become impaired under the provisions of APB No. 18.

The ability to recover our costs in our equity-method investments that own biomass and solar projects is partially dependent upon subsidies from the State of California. Under the California Public Utility Act, subsidies currently exist in that the California Public Utilities Commission (CPUC) requires electric corporations to identify a separate rate component to fund the development of renewable resources technologies, including solar, biomass, and wind facilities. In addition, legislation in California requires that each electric corporation increase its total procurement of eligible renewable energy resources by at least one percent per year so that 20% of its retail sales are procured from eligible renewable energy resources by 2017. The legislation also requires the California Energy Commission to award supplemental energy payments to electric corporations to cover above market costs of renewable energy.

Given the need for electric power and the desire for renewable resource technologies, we believe California will continue to subsidize the use of renewable energy to make these projects economical to operate. However, should the California legislation fail to adequately support the renewable energy initiatives, our equity-method investments in these types of projects could become impaired under the provisions of APB No. 18, and any losses recognized could be material.

If our strategy were to change from an intent to hold to an intent to sell for any of our equity-method investments in qualifying facilities or power projects, we would need to adjust their book value to fair value, and that adjustment could be material. If we were to sell these investments in the current market, we may have losses that could be material.

Operations and Maintenance Expenses

Our merchant energy business operations and maintenance expenses increased $52.0 million in the second quarter of 2004 compared to the same period of 2003 mostly due to the following:

•: an increase of $25.1 million at our nuclear generating facilities, including the cost related to the refueling outage for Unit 1 at Calvert Cliffs and the costs associated with Ginna, which was purchased in June 2004,
•: an increase at our wholesale marketing and risk management operation and our retail commercial and industrial operation of $18.1 million due to the growth of these activities, and
•: an increase of $2.9 million due to the operations of the High Desert Power Project that commenced operations in the second quarter of 2003.

Our merchant energy business operations and maintenance expenses increased $112.4 million for the six months ended June 30, 2004 compared to the same period in 2003 mostly due to the following:

•: an increase of $53.5 million at our nuclear generating facilities, including higher costs for outages that occurred during the first half of 2004 and the costs associated with Ginna,
•: an increase at our wholesale marketing and risk management operation and our retail commercial and industrial operation of $39.9 million due to the growth of these activities, and
•: an increase of $7.7 million due to the operations of the High Desert Power Project.

Depreciation and Amortization Expense

Merchant energy depreciation and amortization expense increased $4.8 million in the second quarter of 2004 compared to the same period of 2003 mostly because of higher depreciation associated with our synthetic fuel processing facility in South Carolina which was acquired in May 2003 and Ginna.

Merchant energy depreciation and amortization expense increased $9.6 million for the six months ended June 30, 2004 compared to the same period of 2003 mostly because of the High Desert Power Project, which was placed into service during the second quarter of 2003, and depreciation associated with our synthetic fuel processing facility in South Carolina and Ginna.

Regulated Electric Business

As discussed in the Regulated Electric Competition—Maryland section on page 27, our regulated electric business was significantly impacted by the July 1, 2000 implementation of customer choice.

Effective July 1, 2000, BGE unbundled its rates to show separate components for delivery service, transition charges, standard offer service (generation), transmission, universal service, and taxes. BGE's rates also were frozen in total except for the implementation of a residential base rate reduction totaling approximately $54 million annually. In addition, 90% of the CTC revenues BGE collects and the portion of its revenues providing for decommissioning costs are included in revenues of the merchant energy business.

As part of the deregulation of electric generation, while total rates are frozen over the transition period, the increasing rates received from customers under standard offer service are offset by declining CTC rates.

Results

		Quarter Ended June 30,						Six Months Ended June 30,
		2004			2003			2004			2003

		(In millions)
Revenues		$	477.2		$	437.0		$	961.6		$	923.3
Electricity purchased for resale expenses			(254.3	)		(237.2	)		(494.7	)		(480.8	)
Operations and maintenance expenses			(78.5	)		(63.5	)		(145.4	)		(119.4	)
Workforce reduction costs			—			(0.2	)		—			(0.5	)
Depreciation and amortization			(48.5	)		(44.5	)		(96.3	)		(88.7	)
Taxes other than income taxes			(32.9	)		(31.9	)		(66.4	)		(65.2	)

Income from Operations		$	63.0		$	59.7		$	158.8		$	168.7

Net Income		$	25.2		$	20.8		$	70.3		$	71.0

Special Items Included in Operations (after-tax)
	Workforce reduction costs	$	—		$	(0.1	)	$	—		$	(0.3	)

Net income from the regulated electric business increased during the quarter ended June 30, 2004 compared to the same period of 2003 mostly because of the following:

•: warmer weather and increased usage per customer in the second quarter of 2004 compared to the same period of 2003, and
•: lower interest expense.

These favorable results were partially offset by the following:

•: increased operations and maintenance expenses primarily due to higher benefit and other inflationary costs, higher uncollectible expenses, and increased spending on electric system reliability, and
•: increased depreciation and amortization expense.

Electric Revenues

The changes in electric revenues in 2004 compared to 2003 were caused by:

	Quarter Ended June 30, 2004 vs. 2003		Six Months Ended June 30, 2004 vs. 2003

	(In millions)
Distribution sales volumes	$	16.0	$	16.3
Standard offer service		22.5		22.6

Total change in electric revenues from electric system sales		38.5		38.9
Other		1.7		(0.6	)

Total change in electric revenues	$	40.2	$	38.3

Distribution Sales Volumes

Distribution sales volumes are sales to customers in BGE's service territory at rates set by the Maryland PSC.

The percentage changes in our distribution sales volumes, by type of customer, in 2004 compared to 2003 were:

	Quarter Ended June 30, 2004 vs. 2003		Six Months Ended June 30, 2004 vs. 2003

Residential	13.6	%	5.4	%
Commercial	7.0		2.6
Industrial	1.0		0.1

During the second quarter of 2004, we distributed more electricity to residential customers compared to the same period of 2003 mostly due to warmer weather. We distributed more electricity to commercial and industrial customers mostly due to warmer weather and increased usage per customer.

During the six months ended June 30, 2004, we distributed more electricity to residential customers compared to the same period of 2003 due to increased usage per customer, warmer weather, and an increased number of customers. We distributed more electricity to commercial customers mostly due to warmer weather and increased usage per customer.

Standard Offer Service

BGE provides standard offer service for customers that do not select an alternative generation supplier as discussed in the Regulated Electric Competition—Maryland section on page 27.

Standard offer service revenues increased during the quarter and six months ended June 30, 2004 compared to the same periods of 2003 mostly due to warmer weather in the second quarter of 2004.

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.

During the quarter and six months ended June 30, 2004, our electricity purchased for resale expenses increased compared to the same periods of 2003 mostly due to warmer weather in the second quarter of 2004.

Electric Operations and Maintenance Expenses

Regulated electric operations and maintenance expenses increased $15.0 million for the quarter and $26.0 million for the six months ended June 30, 2004 compared to the same periods of 2003 mostly due to higher benefit and other inflationary costs, higher uncollectible expenses, and increased spending on electric system reliability.

Electric Depreciation and Amortization Expenses

Regulated electric depreciation and amortization expenses increased $4.0 million for the quarter and $7.6 million for the six months ended June 30, 2004 compared to the same periods of 2003 mostly because of increased depreciation expense associated with more property being placed in service and accelerated amortization expense associated with the planned replacement of information technology assets.

Regulated Gas Business

All BGE customers have the option to purchase gas from other suppliers. To date, customer choice has not had a material effect on our, or BGE's, financial results.

Results

	Quarter Ended June 30,						Six Months Ended June 30,
	2004			2003			2004			2003

	(In millions)
Gas revenues	$	112.6		$	140.0		$	432.1		$	443.6
Gas purchased for resale expenses		(59.5	)		(86.3	)		(275.5	)		(289.4	)
Operations and maintenance expenses		(30.7	)		(25.2	)		(59.0	)		(49.3	)
Depreciation and amortization		(12.2	)		(11.5	)		(24.3	)		(23.2	)
Taxes other than income taxes		(7.6	)		(7.5	)		(16.7	)		(16.6	)

Income from operations	$	2.6		$	9.5		$	56.6		$	65.1

Net (Loss) Income	$	(3.3	)	$	0.9		$	24.5		$	29.5

Net income from the regulated gas business for the quarter and six months ended June 30, 2004 decreased compared to the same periods of 2003 mostly because of increased operations and maintenance expenses primarily due to higher uncollectible expenses and higher benefit and other inflationary costs.

Gas Revenues

The changes in gas revenues in 2004 compared to 2003 were caused by:

	Quarter Ended June 30, 2004 vs. 2003			Six Months Ended June 30, 2004 vs. 2003

	(In millions)
Distribution sales volumes	$	(4.4	)	$	(3.3	)
Base rates		—			(0.1	)
Weather normalization		3.9			4.8
Gas cost adjustments		(19.8	)		11.2

Total change in gas revenues from gas system sales		(20.3	)		12.6
Off-system sales		(7.0	)		(24.1	)
Other		(0.1	)		—

Total change in gas revenues	$	(27.4	)	$	(11.5	)

Distribution Sales Volumes

The percentage changes in our distribution sales volumes, by type of customer, in 2004 compared to 2003 were:

	Quarter Ended June 30, 2004 vs. 2003		Six Months Ended June 30, 2004 vs. 2003

Residential	(21.3	)%	(4.8	)%
Commercial	8.7		9.6
Industrial	(26.8	)	(21.3	)

During the quarter and six months ended June 30, 2004, we distributed less gas to residential customers compared to the same periods in 2003 mostly due to milder weather. We distributed more gas to commercial customers mostly due to increased usage per customer partially offset by milder weather. We distributed less gas to industrial customers mostly due to decreased usage per customer.

Weather Normalization

The Maryland PSC allows us to record a monthly adjustment to our gas revenues to eliminate the effect of abnormal weather patterns on our gas distribution sales volumes. This means our monthly gas base rate revenues are based on weather that is considered "normal" for the month and, therefore, are not affected by actual weather 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 2003 Annual Report on Form 10-K. However, under market-based rates, our actual cost of gas is compared to a market index (a measure of the market price of gas in a given period). The difference between our actual cost and the market index is shared equally between shareholders and customers.

Delivery service only customers are not subject to the gas cost adjustment clauses because we are not selling gas to them. We charge these customers fees to recover the fixed costs for the transportation service we provide. These fees are the same as the base rate charged for gas distributed and are included in gas distribution sales volumes.

During the quarter ended June 30, 2004, gas cost adjustment revenues decreased compared to the same period of 2003 mostly because we sold less gas.

During the six months ended June 30, 2004, gas cost adjustment revenues increased compared to the same period of 2003 because we sold gas at a higher price partially offset by less gas sold.

Off-System Gas Sales

Off-system gas sales are low-margin direct sales of gas to wholesale suppliers of natural gas outside our service territory. 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.

During the quarter and six months ended June 30, 2004, revenues from off-system gas sales decreased compared to the same periods of 2003 mostly because we sold less gas.

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.

During the quarter and six months ended June 30, 2004, gas costs decreased compared to the same periods of 2003 mostly because we purchased less gas, primarily due to milder weather, partially offset by higher gas prices.

Gas Operations and Maintenance Expenses

Regulated gas operations and maintenance expenses increased $5.5 million for the quarter and $9.7 million for the six months ended June 30, 2004 compared to the same periods of 2003 mostly due to higher benefit and other inflationary costs and higher uncollectible expenses.

Other Nonregulated Businesses

Results

		Quarter Ended June 30,						Six Months Ended June 30,
		2004			2003			2004			2003

		(In millions)
Revenues		$	98.9		$	143.1		$	202.6		$	298.7
Operating expenses			(81.9	)		(130.5	)		(168.7	)		(273.7	)
Impairment losses and other costs			(2.6	)		—			(2.6	)		—
Workforce reduction costs			—			(0.1	)		—			(0.1	)
Depreciation and amortization			(8.1	)		(4.3	)		(15.5	)		(8.5	)
Taxes other than income taxes			(0.7	)		(0.8	)		(1.2	)		(1.8	)
Net gain on sale of investments and other assets			4.4			0.5			5.9			14.2

Income from Operations		$	10.0		$	7.9		$	20.5		$	28.8

Net (Loss) Income		$	(0.2	)	$	(0.1	)	$	(0.1	)	$	8.6

Special Items Included in Operations (after-tax)
	Net gain on sale of investments and other assets	$	2.7		$	0.3		$	3.7		$	8.6
	Impairment losses and other costs		(1.6	)		—			(1.6	)		—

Total Special Items		$	1.1		$	0.3		$	2.1		$	8.6

During the six months ended June 30, 2004, net income from our other nonregulated businesses decreased compared to the same period of 2003 mostly because we recognized $14.2 million pre-tax, or $8.6 million after-tax, gains on the sale of non-core assets in 2003 that had a positive impact in that period as follows:

•: a $7.2 million pre-tax gain on the sale of an oil tanker to the U.S. Navy,
•: a $5.3 million pre-tax gain on the favorable settlement of a contingent obligation we had previously reserved relating to the sale of our Guatemalan power plant operation in the fourth quarter of 2001,
•: a $1.2 million pre-tax gain in the first quarter on an installment sale of a parcel of real estate, and
•: a $0.5 million pre-tax gain in the second quarter on the sale of financial investments.

As previously discussed in our 2003 Annual Report on Form 10-K, we decided to sell certain non-core assets and accelerate the exit strategies on other assets that we will continue to hold and own over the next several years. While our intent is to dispose of these assets, market conditions and other events beyond our control may affect the actual sale of these assets. In addition, a future decline in the fair value of these assets could result in additional losses.

Consolidated Nonoperating Income and Expenses

Fixed Charges

During the quarter and six months ended June 30, 2004, total fixed charges at BGE decreased compared to the same period of 2003 mostly because of a lower level of debt outstanding.

Income Taxes

		Quarter Ended June 30,						Six Months Ended June 30,
		2004			2003			2004			2003

		(In millions)
Income before income taxes (excluding BGE preference stock dividends)		$	121.1		$	154.4		$	279.3		$	261.0
Statutory federal income tax rate			35	%		35	%		35	%		35	%

Income taxes computed at statutory federal rate			42.4			54.0			97.8			91.4
(Decreases) increases in income taxes due to:
	Synthetic fuel tax credits (2004)		(22.7	)		(9.5	)		(44.8	)		(17.9	)
	Synthetic fuel tax credits (2003)*		(35.9	)		—			(35.9	)		—
	State income taxes, net of federal tax benefit		2.2			9.3			9.5			15.7
	Other		0.9			0.5			2.7			1.4

Total income taxes		$	(13.1	)	$	54.3		$	29.3		$	90.6

Effective tax rate			(10.8	)%		35.2	%		10.5	%		34.7	%

* Credits associated with 2003 production at our South Carolina facility.

During the quarter ended June 30, 2004, our income taxes decreased $67.4 million compared to the same period of 2003 mostly because of the recognition of synthetic fuel tax credits claimed in 2003 related to our investment in a South Carolina synthetic fuel facility, which reduced our effective tax rate and because of lower taxable income.

During the six months ended June 30, 2004, our income taxes decreased $61.3 million compared to the same period of 2003 mostly because of the recognition of synthetic fuel tax credits claimed in 2003 and 2004 related to our investment in a South Carolina synthetic fuel facility, which reduced our effective tax rate. We discuss our synthetic fuel tax credits in more detail in the Events of 2004 section on page 36.

During the six months ended June 30, 2004, income taxes at BGE decreased compared to the same period of 2003 mostly because of lower taxable income.

Financial Condition

Cash Flows

The following table summarizes our 2004 cash flows by business segment, as well as our consolidated cash flows for 2004 and 2003. This table excludes the impact of the refinancing of the High Desert Power Project in 2003 and the impact of changes in intercompany balances. We exclude the impact of the High Desert refinancing in 2003 due to the fact that there was no net impact on cash. The financing source of cash we received from the issuance of debt was offset by the investing use of cash we incurred from terminating the lease. We discuss the refinancing of High Desert in more detail in Note 15 of our 2003 Annual Report on Form 10-K.

		2004 Segment Cash Flows									Consolidated Cash Flows
		Six Months Ended June 30, 2004									Six Months Ended June 30,
		Merchant			Regulated			Other			2004			2003

		(In millions)
Operating Activities
	Net income (loss)	$	99.7		$	94.8		$	(0.1	)	$	194.4		$	(34.6	)
	Non-cash adjustments to net income		314.0			142.3			13.9			470.2			546.3
	Changes in working capital		43.6			(27.1	)		23.3			39.8			7.4
	Pension and postemployment benefits*		—			—			—			(22.4	)		(86.7	)
	Other		(31.2	)		(3.6	)		14.1			(20.7	)		(48.1	)

Net cash provided by operating activities			426.1			206.4			51.2			661.3			384.3

Investing Activities (excluding $514.1 million related to the refinancing of the High Desert lease in 2003)
	Acquisitions, net of cash acquired (excluding High Desert)		(430.0	)		—			—			(430.0	)		(3.2	)
	Investments in property, plant and equipment		(182.8	)		(120.4	)		(18.8	)		(322.0	)		(321.1	)
	Contributions to nuclear decommissioning trust funds		(13.2	)		—			—			(13.2	)		(8.8	)
	Proceeds from sale of discontinued operations		72.7			—			—			72.7			—
	Sale of investments and other assets		—			4.9			9.2			14.1			102.8
	Other investments		(6.9	)		—			(3.2	)		(10.1	)		(60.2	)

Net cash used in investing activities (excluding High Desert)			(560.2	)		(115.5	)		(12.8	)		(688.5	)		(290.5	)

Cash flows from operating activities less cash flows from investing activities (excluding High Desert)		$	(134.1	)	$	90.9		$	38.4			(27.2	)		93.8

Financing Activities (excluding $514.1 million related to the refinancing of the High Desert lease in 2003)
	Net (repayment) issuance of debt (excluding High Desert) *											(177.5	)		76.9
	Proceeds from issuance of common stock*											30.5			49.6
	Common stock dividends paid*											(91.4	)		(82.4	)
	Other*											1.3			(1.9	)

Net cash (used in) provided by financing activities (excluding High Desert) *												(237.1	)		42.2

Net (Decrease) Increase in Cash and Cash Equivalents*											$	(264.3	)	$	136.0

*Items are not allocated to the business segments because they are managed for the company as a whole.

Overview—2004 Compared to 2003

Cash flows from operating activities less cash flows from investing activities were a use of cash of $27.2 million in 2004 compared to cash provided of $93.8 million in 2003. The $121.0 million decrease in cash flows in 2004 compared to 2003 is primarily due to an increase in cash paid for acquisitions due to the acquisition of Ginna for $430.0 million in 2004, lower non-cash adjustments to net income of $76.1, and a $16.0 million decrease in cash provided from the sale of discontinued operations, investments, and other assets. These decreases were partially offset by higher net income of $229.0 million, a source of cash from working capital and other of $59.8 million, a decrease in the pension contribution of approximately $60 million, and a $50.1 million decrease in other investing activities.

Cash Flows from Operating Activities

Cash provided by operating activities was $661.3 million in 2004 compared to $384.3 million in 2003. Net income was $229.0 million higher in 2004 compared to 2003. This was partially offset by a decrease in non-cash adjustments to net income of $76.1 million in 2004 compared to 2003. The net decrease in non-cash adjustments to net income was primarily due to cumulative effects of changes in accounting principles of $198.4 million as a result of the adoption of SFAS No. 143 and EITF 02-3 in 2003, which had the effect of reducing net income but were non-cash transactions. This decrease in non-cash adjustments to net income was partially offset by the following increases:

•: a loss from discontinued operations of $49.0 million in 2004;
•: an increase in depreciation and amortization of $26.1 million in 2004 compared to 2003;
•: an increase in deferred income taxes of $22.4 million in 2004 compared to 2003; and
•: an increase in deferred fuel costs of $14.9 million in 2004 compared to 2003.

Changes in working capital had a positive impact of $39.8 million on cash flow from operations in 2004 compared to $7.4 million in 2003, a net increase of $32.4 million. Pension and postemployment benefits were a use of cash of $22.4 million in 2004 compared to a use of $86.7 million in 2003. This primarily reflects a $60 million lower contribution to the pension plan in 2004 compared to 2003.

Cash Flows from Investing Activities

Cash used in investing activities was $688.5 million in 2004 compared to $290.5 million in 2003 excluding High Desert. The increase in cash used was primarily due to a $426.8 million increase in cash paid for acquisitions in 2004 compared to 2003 primarily due to the acquisition of Ginna in 2004 for $430.0 million.

Cash Flows from Financing Activities

Cash used in financing activities was $237.1 million in 2004 compared to cash provided by financing activities of $42.2 million in 2003 excluding High Desert. The $279.3 million decrease in cash was primarily due to net debt issuances of $76.9 million in 2003 as compared to a $177.5 million net repayment of debt in 2004.

Security Ratings

Independent credit-rating agencies rate Constellation Energy's and BGE's fixed-income securities. The ratings indicate the agencies' assessment of each company's ability to pay interest, distributions, dividends, and principal on these securities. These ratings affect how much it will cost each company to sell these securities. The better the rating, the lower the cost of the securities to each company when they sell them.

The factors that credit rating agencies consider in establishing Constellation Energy's and BGE's credit ratings include, but are not limited to, cash flows, liquidity, and the amount of debt as a component of total capitalization. In March 2004, Standard & Poors rating group reduced Constellation Energy's and BGE's corporate credit rating from A- to BBB+ and reduced certain other ratings as noted in the table below. All Constellation Energy and BGE credit ratings have stable outlooks. At the date of this report, our credit ratings were as follows:

		Standard & Poors Rating Group	Moody's Investors Service	Fitch- Ratings

Constellation Energy
	Commercial Paper	A-2	P-2	F-2
	Senior Unsecured Debt*	BBB	Baa1	A-
BGE
	Commercial Paper	A-2	P-1	F-1
	Mortgage Bonds	A	A1	A+
	Senior Unsecured Debt	BBB+	A2	A
	Trust Preferred Securities*	BBB-	A3	A-
	Preference Stock*	BBB-	Baa1	A-

* In March 2004, Standard & Poors rating group reduced the rating one level to this current rating.

Available Sources of Funding

We continuously monitor our liquidity requirements and believe that our facilities and access to the capital markets provide sufficient liquidity to meet our business requirements. We discuss our available sources of funding in more detail below.

Constellation Energy

In addition to our cash balance, we have a commercial paper program under which we can issue short-term notes to fund our subsidiaries. At June 30, 2004, we had approximately $2.2 billion of credit under several facilities.

We use these facilities to ensure adequate liquidity to support our operations. We can borrow directly from the banks or use the facilities to allow the issuance of commercial paper. Additionally, we use the multi-year facilities to support letters of credit primarily for our merchant energy business.

BGE

During the second quarter of 2004, certain credit facilities expired and BGE renewed these facilities. BGE continues to maintain $200.0 million in annual committed credit facilities, expiring August 2004 through June 2005, to ensure adequate liquidity to support its operations. We can borrow directly from the banks or use the facilities to allow commercial paper to be issued. As of June 30, 2004, BGE had no outstanding commercial paper, which results in $200.0 million in unused credit facilities.

Other Nonregulated Businesses

BGE Home Products & Services' program to sell up to $50 million of receivables was not extended beyond its March 2004 expiration date. We expect to fully liquidate this receivables program by the end of 2004.

If we can get a reasonable value for our remaining real estate projects and other investments, additional cash may be obtained by selling them. Our ability to sell or liquidate assets will depend on market conditions, and we cannot give assurances that these sales or liquidations could be made.

Capital Resources

Our estimated annual amounts of capital requirements for the years 2004 and 2005 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 2004 and 2005 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 63.

Calendar Year Estimates			2004		2005

			(In millions)
Nonregulated Capital Requirements:
	Merchant energy
		Generation plants	$	180	$	170
		Nuclear fuel		125		85
		Portfolio acquisitions		55		60
		Technology/other		115		85

	Total merchant energy capital requirements			475		400
	Other nonregulated capital requirements			45		50

	Total nonregulated capital requirements			520		450

Regulated Capital Requirements:
	Regulated electric			215		250
	Regulated gas			60		55

	Total regulated capital requirements			275		305

Total capital requirements			$	795	$	755

Above amounts include capital requirements for Ginna. We discuss the acquisition of Ginna in more detail in the Events of 2004 section on page 35.

Capital Requirements

Merchant Energy Business

Our merchant energy business' capital requirements consist of its continuing requirements, including construction expenditures for improvements to generating plants, nuclear fuel costs, costs of complying with the Environmental Protection Agency (EPA), Maryland, and Pennsylvania nitrogen oxides (NOx) emissions regulations, and enhancements to our information technology infrastructure. We discuss the NOx regulations and timing of expenditures in Note 12 of our 2003 Annual Report on Form 10-K.

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.

Funding for Capital Requirements

Merchant Energy Business

Funding for the expansion of our merchant energy business is expected from internally generated funds. We also have available sources from commercial paper issuances, issuances of long-term debt and equity, leases, and other financing activities.

The projects that our merchant energy business develops typically require substantial capital investment. Most of the projects recently constructed were funded through corporate borrowings by Constellation Energy. Many of the qualifying facilities and independent power projects that we have an interest in are financed primarily with non-recourse debt that is repaid from the project's cash flows. This debt is collateralized by interests in the physical assets, major project contracts and agreements, cash accounts and, in some cases, the ownership interest in that project.

We expect to fund acquisitions with an overall goal of maintaining a strong investment grade credit profile. We funded our June 2004 acquisition of Ginna with a mix of cash and equity. On July 1, 2004, we issued 6.0 million shares of common stock for net proceeds of $226.9 million to fund a portion of the acquisition of Ginna. We discuss our acquisition of Ginna in more detail in the Events of 2004 section on page 35.

Regulated Electric and Gas

Funding for our regulated electric and gas capital expenditures is expected from internally generated funds. During 2004, we expect our regulated businesses to generate sufficient cash flows from operations to meet BGE's operating requirements. If necessary, additional funding may be obtained from commercial paper issuances, available capacity under credit facilities, the issuance of long-term debt, trust securities, or preference stock, and/or from time to time equity contributions from Constellation Energy. BGE also participates in a cash pool administered by Constellation Energy as discussed in the Notes to Consolidated Financial Statements section on page 24.

Other Nonregulated Businesses

Funding for our other nonregulated businesses is expected from internally generated funds, commercial paper issuances, issuances of long-term debt of Constellation Energy, sales of securities and assets, and/or from time to time, equity contributions from Constellation Energy.

Our ability to sell or liquidate securities and non-core assets will depend on market conditions, and we cannot give assurances that these sales or liquidations could be made.

Contractual Payment Obligations and
Committed Amounts

Our total contractual payment obligations as of June 30, 2004 are shown in the following table:

			Payments
			2004		2005- 2006		2007- 2008		Thereafter		Total

			(In millions)
Contractual Payment Obligations
Long-term debt:¹
	Nonregulated
		Principal	$	8.0	$	343.8	$	636.4	$	2,745.0	$	3,733.2
		Interest		117.4		430.9		363.8		1,741.7		2,653.8

	Total			125.4		774.7		1,000.2		4,486.7		6,387.0
	BGE
		Principal		26.6		482.7		418.4		600.7		1,528.4
		Interest		44.2		169.8		96.7		824.0		1,134.7

	Total			70.8		652.5		515.1		1,424.7		2,663.1
BGE preference stock				—		—		—		190.0		190.0
Operating leases				14.9		47.4		30.1		124.5		216.9
Purchase obligations:²
	Purchased capacity and energy³			702.1		1,231.1		420.8		219.0		2,573.0
	Fuel and transportation⁴			426.5		680.5		152.6		67.3		1,326.9
	Other			36.8		78.9		33.7		289.4		438.8
Other noncurrent liabilities:
	Postretirement and postemployment benefits⁵			17.5		74.6		77.3		203.2		372.6
	Other			1.9		4.2		1.2		—		7.3

Total contractual payment obligations			$	1,395.9	$	3,543.9	$	2,231.0	$	7,004.8	$	14,175.6

1 Amounts in long-term debt reflect the original maturity date. Investors may require us to repay $327.0 million early through put options and remarketing features.

2 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.

3 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. We have recorded $24.7 million of liabilities related to purchased capacity and energy obligations at June 30, 2004 in our Consolidated Balance Sheets.

4 We have recorded liabilities of $47.4 million related to fuel and transportation obligations at June 30, 2004 in our Consolidated Balance Sheets.

5 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 on the Consolidated Balance Sheets.

The table below presents our contingent obligations. Our contingent obligations increased $1.9 billion during the first six months of 2004, primarily due to the issuance of additional guarantees and letters of credit by the parent company for subsidiary obligations to third parties in support of the growth of our merchant energy business. These amounts do not represent incremental consolidated Constellation Energy obligations; rather they primarily represent parent company guarantees of certain subsidiary obligations to third parties. Our calculation of the fair value of subsidiary obligations covered by the $5,018.9 million of parent company guarantees was $1,180.7 million at June 30, 2004. Accordingly, if the parent company was required to fund defaulted subsidiary obligations, the total amount at current market prices is $1,180.7 million.

	Expiration
	2004		2005- 2006		2007- 2008		Thereafter		Total

	(In millions)
Contingent Obligations
Letters of credit	$	749.9	$	110.9	$	—	$	—	$	860.8
Guarantees—competitive supply¹		3,121.1		1,090.5		307.0		500.3		5,018.9
Other guarantees, net²		10.4		4.6		—		1,019.6		1,034.6

Total contingent obligations	$	3,881.4	$	1,206.0	$	307.0	$	1,519.9	$	6,914.3

1 While the face amount of these guarantees is $5,018.9 million, the parent company would only fund the fair value of any defaulted subsidiary obligations. Our calculation of the fair value of obligations covered by these guarantees was $1,180.7 million at June 30, 2004.

2 Other guarantees in the above table are shown net of liabilities of $25.0 million recorded at June 30, 2004 in our Consolidated Balance Sheets.

Liquidity Provisions

We have certain agreements that contain provisions that require additional collateral upon significant credit rating decreases in the 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 certain counterparty contracts related to our wholesale marketing and risk management operation, we are obligated to post collateral if Constellation Energy's senior, unsecured credit ratings decline below established contractual levels. As a result of the ratings action taken by Standard & Poors rating agency in March 2004, we posted approximately $40 million in additional collateral during the first quarter of 2004 to support our wholesale marketing and risk management operational requirements. We discuss the Standard & Poors ratings action in more detail in the Financial Condition section on page 53.

Based on contractual provisions, we estimate that we would have additional collateral obligations based on downgrades to the following credit ratings for our senior unsecured debt:

Credit Ratings Downgraded	Level Below Current Rating	Incremental Obligations		Cumulative Obligations

		(In millions)
BBB-/Baa3	1	$	134	$	134
Below investment grade	2		652		786

At June 30, 2004 we had approximately $1.5 billion of unused credit facilities and $457.0 million of cash available to meet these potential requirements. However, based on market conditions and contractual obligations at the time of such a downgrade, we could be required to post collateral in an amount that could exceed the amounts specified above, and which could be material.

We consistently review our liquidity needs to ensure that we have adequate facilities available to meet these requirements. This includes having liquidity available to meet margin requirements for our wholesale marketing and risk management operation and our retail competitive supply activities.

In many cases, customers of our wholesale marketing and risk management operation rely on the creditworthiness of Constellation Energy. A decline below investment grade of Constellation Energy would negatively impact the business prospects of that operation. The credit facilities of Constellation Energy and BGE have limited material adverse change clauses that only consider a material change in financial condition and are not directly affected by decreases in credit ratings. If these clauses are violated, the lending institutions can decline making new advances or issuing new letters of credit, but cannot accelerate existing amounts outstanding. The long-term debt indentures of Constellation Energy and BGE do not contain material adverse change clauses or financial covenants.

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, 2004, the debt to capitalization ratios as defined in the credit agreements were no greater than 53%. Certain credit facilities of BGE contain provisions requiring BGE to maintain a ratio of debt to capitalization equal to or less than 65%. At June 30, 2004, the debt to capitalization ratio for BGE as defined in these credit agreements was 48%. At June 30, 2004, no amount is outstanding under these facilities.

Failure by Constellation Energy, or BGE, to comply with these covenants could result in the maturity of the debt outstanding under these facilities being accelerated. The credit facilities of Constellation Energy contain usual and customary cross-default provisions that apply to defaults on debt by Constellation Energy and certain subsidiaries over a specified threshold. Certain BGE credit facilities also contain usual and customary cross-default provisions that apply to defaults on debt by BGE over a specified threshold. The indentures pursuant to which BGE has issued and outstanding mortgage bonds and subordinated debentures provide that a default under any debt instrument issued under the relevant indenture may cause a default of all debt outstanding under such indenture.

Constellation Energy also provides credit support to Calvert Cliffs, Nine Mile Point, and Ginna to ensure these plants have funds to meet expenses and obligations to safely operate and maintain the plants.

Market Risk

Commodity Risk

During the first six months of 2004, the energy markets continued to be highly volatile with significant changes in fuel prices, primarily natural gas and coal, and power prices, as well as periods of reduced liquidity in the marketplace.

We measure the sensitivity of our wholesale marketing and risk management mark-to-market energy contracts 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 wholesale marketing and risk management mark-to-market energy assets and liabilities over one and ten-day holding periods. We discuss value at risk in more detail in the Market Risk section of our 2003 Annual Report on Form 10-K. The table below is the value at risk associated with our wholesale marketing and risk management operation's mark-to-market energy assets and liabilities, including both trading and non-trading activities.

		Six Months Ended June 30, 2004

		(In millions)
99% Confidence Level, One-Day Holding Period
	Average	$	4.4
	High		7.8
95% Confidence Level, One-Day Holding Period
	Average		3.4
	High		5.9
95% Confidence Level, Ten-Day Holding Period
	Average		10.6
	High		18.7

The following table details our value at risk for the trading portion of our wholesale marketing and risk management mark-to-market energy assets and liabilities over a one-day holding period at a 99% confidence level for the first six months of 2004:

	Six Months Ended June 30, 2004

	(In millions)
Average	$	3.2
High		14.8

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 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 mark-to-market energy assets and liabilities could differ from the calculated value at risk, and such changes could have a material impact on our financial results.

Wholesale Credit Risk

We continue to actively manage the credit portfolio of our wholesale marketing and risk management operation to attempt to reduce the impact of the general decline in the overall credit quality of the energy industry and the impact of a potential counterparty default. As of June 30, 2004 and December 31, 2003, the credit portfolio of our wholesale marketing and risk management operation had the following public credit ratings:

		June 30, 2004		December 31, 2003

Rating
	Investment Grade¹	67	%	75	%
	Non-Investment Grade	8		4
	Not Rated	25		21

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.

In addition to the credit ratings provided by the major credit rating agencies, 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 and includes governmental entities, municipalities, cooperatives, power pools, and other load-serving entities, and marketers for which we determine creditworthiness based on internal credit ratings.

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

	June 30, 2004		December 31, 2003

Investment Grade Equivalent	79	%	91	%
Non-Investment Grade	21		9

Compared to December 31, 2003, we have experienced deterioration in the credit quality of our wholesale marketing and risk management portfolio measured using both public credit ratings and our internal credit ratings. The decline in investment grade equivalent counterparties is primarily due to increased exposure to lower credit quality fuel and power supply counterparties, most notably coal suppliers who tend to be smaller and of lower credit quality. A portion of our wholesale credit risk is related to transactions that are recorded in our Consolidated Balance Sheets. These transactions primarily consist of open positions from our wholesale marketing and risk management operation that are accounted for using mark-to-market accounting, 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 these activities at June 30, 2004:

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

	(Dollars in millions)
Investment grade	$	761	$	69	$	692	1	$	153
Split rating		4		—		4	—		—
Non-investment grade		228		171		57	—		—
Internally rated—investment grade		165		9		156	—		—
Internally rated—non- investment grade		36		11		25	—		—

Total	$	1,194	$	260	$	934	1	$	153

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 our wholesale marketing and risk management operation had contracted for), we could incur a loss that could have a material impact on our financial results.

Additionally, if a counterparty were to default and we were to liquidate all contracts with that entity, our credit loss would include the loss in value of mark-to-market contracts, the amount owed for settled transactions, and additional payments, if any, we would have to make to settle unrealized losses on accrual contracts.

We continue to examine plans to achieve our strategies and to further strengthen our balance sheet and enhance our liquidity. We discuss our liquidity in the Financial Condition section on page 56.

Interest Rate Risk

In July 2004, to optimize the mix of fixed and floating rate debt, we entered into interest rate swaps relating to $450 million of our long-term debt. These fair value hedges will convert our current fixed rate debt to a floating rate instrument tied to the three month London Inter-Bank Offered Rate. Including the $450 million in interest rate swaps, approximately 15% of our long-term debt is floating rate.

Retail Credit Risk and Equity Price Risk

We discuss our exposure to retail credit risk and equity price risk in the Market Risk section of our 2003 Annual Report on Form 10-K.

Other Matters

Environmental Matters

We are subject to federal, state, and local laws and regulations that work to improve or maintain the quality of the environment. If certain substances were disposed of, or released at any of our properties, whether currently operating or not, these laws and regulations require us to remove or remedy the effect on the environment. This includes Environmental Protection Agency Superfund sites.

You will find details of our environmental matters in the Environmental Matters section of the Notes to Consolidated Financial Statements beginning on page 18 and in our 2003 Annual Report on Form 10-K in Item 1. Business—Environmental Matters. These details include financial information. Some of the information is about costs that may be material.

Accounting Standards Adopted and Issued

We discuss recently adopted and issued accounting standards in the Accounting Standards Issued and Accounting Standards Adopted sections of the Notes to Consolidated Financial Statements beginning on page 23.

Item 3. Quantitative and Qualitative Disclosures About Market Risk

We discuss the following information related to our market risk:

•: financing activities and SFAS No. 133 hedging activities section in the Notes to Consolidated Financial Statements beginning on page 15,
•: activities of our wholesale marketing and risk management operation in the Merchant Energy Business section of Management's Discussion and Analysis beginning on page 38,
•: evaluation of commodity and wholesale credit risk in the Market Risk section of Management's Discussion and Analysis beginning on page 57, and
•: changes to our business environment in the Business Environment section of Management's Discussion and Analysis beginning on page 27.

Item 4. 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 the realities that judgments in decision-making can be faulty, and that breakdowns can occur because of simple error or mistake. 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 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.

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, in that they provide reasonable assurance that such officers are alerted on a timely basis to material information relating to Constellation Energy and BGE that is required to be included in Constellation Energy's and BGE's periodic filings under the Exchange Act. During the fiscal quarter covered by this quarterly report, 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

Western Power Markets

Baldwin Associates, Inc. v. Gray Davis, Governor of California and 22 other defendants (including Constellation Power Development, Inc., a subsidiary of Constellation Power, Inc.)—This class action lawsuit was filed on October 5, 2001 in the Superior Court, County of San Francisco. The action seeks damages of $43 billion, recession and reformation of approximately 38 long-term power purchase contracts, and an injunction against improper spending by the state of California.

Constellation Power Development, Inc. is named as a defendant but has never been served with process in this case and does not have a power purchase agreement with the State of California. However, our High Desert Power Project does have a power purchase agreement with the California Department of Water Resources. The court issued an order to the plaintiff asking that he show cause why he had not yet served any of the defendants with process. A hearing is scheduled on August 23, 2004 on the court's show cause order.

James M. Millar v. Allegheny Energy Supply, Constellation Power Source, Inc., High Desert Power Project, LLC, et al.,—On December 19, 2003, plaintiffs filed an amended complaint in Superior Court of California, County of San Francisco, naming for the first time, Constellation Power Source, Inc. (CPS) and High Desert Power Project, LLC (High Desert), two of our subsidiaries, as additional defendants. The complaint is a putative class action on behalf of California electricity consumers and alleges that the defendant power suppliers, including CPS and High Desert, violated California's Unfair Competition Law in connection with certain long-term power contracts that the defendants negotiated with the California Department of Water Resources in 2001 and 2002. Notwithstanding the amended long-term power contracts and the releases and settlement agreements negotiated at the time of such amendments, the plaintiff seeks to have the Court certify the case as a class action and to order the repayment of any monies that were acquired by the defendants under the long-term contracts or the amended long-term contracts by means of unfair competition in violation of California law. The amended complaint was removed to federal court by one of the defendants and a motion to remand the case back to the state court is pending before the federal court. We believe that we have meritorious defenses to this action and intend to defend against it vigorously. However, we cannot predict the timing, or outcome, of this case, or its possible effect on our results.

City of Tacoma v. AEP, et al.,—The City of Tacoma, on June 7, 2004, in the U.S. District Court, Western District of Washington, filed a complaint against over 60 companies, including CPS. The complaint alleges that the defendants engaged in manipulation of electricity markets resulting in prices for power in the western power markets that were substantially above what market prices would have been in the absence of the alleged unlawful contracts, combinations and conspiracy in violation of Section 1 of the Sherman Act. The complaint further alleges that the total amount of damages is unknown, but is estimated to exceed $175 million. We believe that we have meritorious defenses to this action and intend to defend against it vigorously. However, we cannot predict the timing, or outcome, of this case, or its possible effect on our results.

NewEnergy

Constellation NewEnergy, Inc. v. PowerWeb Technology, Inc. —Prior to our acquisition, NewEnergy filed a complaint on May 9, 2002 in the U.S. District Court of Eastern Pennsylvania seeking approximately $100,000 in direct damages relating to a contract previously entered into with PowerWeb. PowerWeb Technology has counter-claimed seeking $100 million in damages against NewEnergy alleging a breach of a non-disclosure agreement by misappropriation of trade secrets and tortious interference claims. Discovery is ongoing in the matter. We cannot predict the timing, or outcome, of the action or its possible effect on our financial results. However, based on the information available to Constellation Energy at this time, we believe NewEnergy has meritorious defenses to the PowerWeb Technology counterclaim.

Mercury Poisoning

Beginning in 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 50 cases have been filed to date, with each case seeking $90 million in damages from the group of defendants.

In a ruling applicable to all but several of the cases, the Circuit Court for Baltimore City dismissed with prejudice all claims against BGE and Constellation Energy and entered into a stay of the proceedings as they relate to other defendants. The several cases that were not dismissed were filed subsequent to the ruling by the Circuit Court. Plaintiffs may attempt to pursue appeals of the rulings in favor of BGE and Constellation Energy

once the cases are finally concluded as to all defendants. We believe that we have meritorious defenses and intend to defend the actions vigorously. However, we cannot predict the timing, or outcome, of these cases, or their possible effect on our, or BGE's, financial results.

Employment Discrimination

Miller, et. al., v. Baltimore Gas and Electric Company, et al.,—This action was filed on September 20, 2000 in the U.S. District Court for the District of Maryland. Besides BGE, Constellation Energy Group, Constellation Nuclear, and Calvert Cliffs Nuclear Power Plant are also named defendants. The action seeks class certification for approximately 150 past and present employees and alleges racial discrimination at Calvert Cliffs Nuclear Power Plant. The amount of damages is unspecified, however the plaintiffs seek back and front pay, along with compensatory and punitive damages. The Court scheduled a briefing process for the motion to certify the case as a class action suit. The briefing process concluded and oral argument on the class certification motion was held on April 16, 2004, and the parties are awaiting the court's decision. We do not believe class certification is appropriate and we further believe that we have meritorious defenses to the underlying claims and intend to defend the action vigorously. However, we cannot predict the timing, or outcome, of the action or its possible effect on our, or BGE's, financial results.

Asbestos

Since 1993, BGE has been involved in several actions concerning asbestos. The actions are based upon the theory of "premises liability," alleging that BGE knew of and exposed individuals to an asbestos hazard. The actions relate to two types of claims.

The first type is direct claims by individuals exposed to asbestos. BGE is involved in these claims with approximately 70 other defendants. Approximately 545 individuals that were never employees of BGE each claim $6 million in damages ($2 million compensatory and $4 million punitive). These claims are currently pending in state courts in Maryland and Pennsylvania. BGE does not know the specific facts necessary to estimate its potential liability for these claims. The specific facts BGE does not know include:

•: the identity of BGE's facilities at which the plaintiffs allegedly worked as contractors,
•: the names of the plaintiff's employers,
•: the date on which the exposure allegedly occurred, and
•: the facts and circumstances relating to the alleged exposure.

To date, 299 asbestos cases were dismissed or resolved for amounts that were not significant. Approximately 30 cases are currently scheduled for trial through the end of 2006.

The second type is claims by one manufacturer—Pittsburgh Corning Corp. (PCC)—against BGE and approximately eight others, as third-party defendants. On April 17, 2000, PCC declared bankruptcy.

These claims relate to approximately 1,500 individual plaintiffs and were filed in the Circuit Court for Baltimore City, Maryland in the fall of 1993. To date, about 375 cases have been resolved, all without any payment by BGE. BGE does not know the specific facts necessary to estimate its potential liability for these claims. The specific facts we do not know include:

•: the identity of BGE facilities containing asbestos manufactured by the manufacturer,
•: the relationship (if any) of each of the individual plaintiffs to BGE,
•: the settlement amounts for any individual plaintiffs who are shown to have had a relationship to BGE,
•: the dates on which/places at which the exposure allegedly occurred, and
•: the facts and circumstances relating to the alleged exposure.

Until the relevant facts for both types of claims 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.

Item 4. Submission of Matters to a Vote of Security Holders

On May 21, 2004, we held our annual meeting of shareholders. At that meeting, the following matters were voted upon:

1.: All of the Directors nominated by Constellation Energy Group were elected as follows:

	COMMON SHARES CAST:
	For	Against	Abstain
James T. Brady	139,953,759	2,147,332	13
James R. Curtiss	140,002,065	2,099,028	11
Edward J. Kelly, III	139,959,883	2,141,209	12
Robert J. Lawless	139,993,805	2,107,287	12

All other directors whose term of office continued after the date of this meeting are:

Douglas L. Becker
Frank P. Bramble
Edward C. Crooke
Yves C. de Balmann
Roger W. Gale

Freeman A. Hrabowski, III
Nancy Lampton
Lynn M. Martin
Mayo A. Shattuck III
Michael D. Sullivan

2.: The ratification of PricewaterhouseCoopers LLP as independent auditors was approved. With respect to holders of common stock, the number of affirmative votes cast was 136,601,423, the number of votes cast against was 4,270,924, and the number of abstentions was 1,228,740.

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, and emission allowances,
•: the timing and extent of deregulation of, and competition in, the energy markets in North America, and the rules and regulations adopted on a transitional basis in those markets,
•: the conditions of the capital markets, interest rates, availability of credit, liquidity, and general economic conditions, as well as Constellation Energy Group's (Constellation Energy) and Baltimore Gas and Electric Company's (BGE) ability to maintain their current credit ratings,
•: the effectiveness of Constellation Energy's and BGE's risk management policies and procedures and the ability and willingness of our counterparties to satisfy their financial and performance commitments,
•: the liquidity and competitiveness of wholesale markets for energy commodities,
•: 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 gas transportation or electric transmission services, workforce issues, terrorism, liabilities associated with catastrophic events, and other events beyond our control,
•: the inability of BGE to recover all its costs associated with providing electric retail customers service during the electric rate freeze period,
•: the effect of weather and general economic and business conditions on energy supply, demand, and prices,
•: regulatory or legislative developments that affect deregulation, 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 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,
•: the ability to attract and retain customers in our competitive supply activities and to adequately forecast their energy usage,
•: 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, and
•: cost and other effects of legal and administrative proceedings that may not be covered by insurance, including environmental liabilities.

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

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

Item 6. Exhibits and Reports on Form 8-K

(a)	Exhibit No. 10(a)	Grantor Trust Agreement Dated as of February 27, 2004 between Constellation Energy Group, Inc. and Citibank, N.A.
	Exhibit No. 10(b)	Grantor Trust Agreement Dated as of February 27, 2004 between Constellation Energy Group, Inc. and T. Rowe Price Trust Company.
	Exhibit No. 10(c)	Compensation Agreements between Constellation Energy Group, Inc. and E. Follin Smith (Attachment 1—Employment Agreement; Attachment 2—Severance Agreement).
	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 18 U.S.C. Section 1350, as adopted 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 18 U.S.C. Section 1350, as adopted 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 18 U.S.C. Section 1350, as adopted 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 18 U.S.C. Section 1350, as adopted 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.

(b) Reports on Form 8-K for the quarter ended June 30, 2004:

Date		Item Reported
April 28, 2004		Item 7. Financial Statements and Exhibits
		Item 12. Results of Operations and Financial Condition

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 6, 2004			/s/ E. FOLLIN SMITH E. Follin Smith, *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*