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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 September 30, 2003

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)

410-234-5000

(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 167,271,886 SHARES OUTSTANDING OF
CONSTELLATION ENERGY GROUP, INC. ON OCTOBER 31, 2003.

         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
		Critical Accounting Policies
		Events of 2003
		Strategy
		Business Environment
		Results of Operations
		Financial Condition
		Capital Resources
		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 5—Other Information
	Item 6—Exhibits and Reports on Form 8-K
	Signature

2

PART 1—FINANCIAL INFORMATION

Item 1—Financial Statements

CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED)

Constellation Energy Group, Inc. and Subsidiaries

		Three Months Ended September 30,						Nine Months Ended September 30,
		2003			2002			2003			2002
		(In millions, except per share amounts)
Revenues
	Nonregulated revenues	$	1,943.8		$	605.8		$	5,186.0		$	1,437.2
	Regulated electric revenues		582.3			596.1			1,505.5			1,536.8
	Regulated gas revenues		78.3			67.7			514.0			379.1
	Total revenues		2,604.4			1,269.6			7,205.5			3,353.1
Expenses
	Operating expenses		2,010.2			732.2			5,827.8			2,063.8
	Workforce reduction costs		0.7			12.5			2.1			51.7
	Impairment losses and other costs		—			24.6			—			24.6
	Depreciation and amortization		127.7			125.8			355.6			360.1
	Accretion of asset retirement obligations		10.7			—			32.0			—
	Taxes other than income taxes		68.0			66.5			210.2			195.7
	Total expenses		2,217.3			961.6			6,427.7			2,695.9
Net Gain on Sales of Investments and Other Assets			2.1			—			16.3			254.3
Income from Operations			389.2			308.0			794.1			911.5
Other Income			4.5			8.3			19.3			21.1
Fixed Charges
	Interest expense		85.3			78.4			251.2			228.9
	Interest capitalized and allowance for borrowed funds used during construction		(2.3	)		(8.5	)		(9.5	)		(40.4	)
	BGE preference stock dividends		3.3			3.3			9.9			9.9
	Total fixed charges		86.3			73.2			251.6			198.4
Income Before Income Taxes			307.4			243.1			561.8			734.2
Income Taxes			114.5			92.4			205.1			273.6
Income Before Cumulative Effects of Changes in Accounting Principles			192.9			150.7			356.7			460.6
Cumulative Effects of Changes in Accounting Principles, Net of Income Taxes of $119.5			—			—			(198.4	)		—
Net Income		$	192.9		$	150.7		$	158.3		$	460.6
Earnings Applicable to Common Stock		$	192.9		$	150.7		$	158.3		$	460.6
Average Shares of Common Stock Outstanding—Basic			167.0			164.4			165.9			164.0
Average Shares of Common Stock Outstanding—Assuming Dilution			167.7			164.4			166.2			164.0
Earnings Per Common Share Before Cumulative Effects of Changes in Accounting Principles—Basic		$	1.16		$	0.92		$	2.15		$	2.81
Cumulative Effects of Changes in Accounting Principles			—			—			(1.20	)		—
Earnings Per Common Share—Basic		$	1.16		$	0.92		$	0.95		$	2.81
Earnings Per Common Share Before Cumulative Effects of Changes in Accounting Principles—Assuming Dilution		$	1.15		$	0.92		$	2.15		$	2.81
Cumulative Effects of Changes in Accounting Principles			—			—			(1.20	)		—
Earnings Per Common Share—Assuming Dilution		$	1.15		$	0.92		$	0.95		$	2.81
Dividends Declared Per Common Share		$	0.26		$	0.24		$	0.78		$	0.72

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)

Constellation Energy Group, Inc. and Subsidiaries

			Three Months Ended September 30,						Nine Months Ended September 30,
			2003			2002			2003			2002
			(In millions)
Net Income			$	192.9		$	150.7		$	158.3		$	460.6
	Other comprehensive income (OCI)
		Reclassification of net losses (gains) on sales of securities from OCI to net income, net of taxes		0.8			(0.7	)		0.5			(155.4	)
		Reclassification of net gains on hedging instruments from OCI to net income, net of taxes		(15.2	)		(0.9	)		(24.9	)		(7.4	)
		Net unrealized loss on hedging instruments, net of taxes		(48.3	)		(33.0	)		(40.8	)		(32.9	)
		Net unrealized gain (loss) on securities, net of taxes		6.9			(35.8	)		21.7			(46.7	)
Comprehensive Income			$	137.1		$	80.3		$	114.8		$	218.2

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

3

CONSOLIDATED BALANCE SHEETS

Constellation Energy Group, Inc. and Subsidiaries

			September 30, 2003*			December 31, 2002
			(In millions)
Assets
	Current Assets
		Cash and cash equivalents	$	423.1		$	615.0
		Accounts receivable (net of allowance for uncollectibles of $50.0 and $41.9, respectively)		1,796.5			1,244.1
		Trading securities		—			77.1
		Mark-to-market energy assets		506.9			759.4
		Risk management assets		162.8			72.3
		Fuel stocks		160.4			126.5
		Materials and supplies		209.9			208.6
		Prepaid taxes other than income taxes		102.5			57.1
		Other		175.7			157.1
		Total current assets		3,537.8			3,317.2
	Investments and Other Assets
		Real estate projects and investments		58.4			86.1
		Investments in qualifying facilities and power projects		439.0			439.2
		Nuclear decommissioning trust funds		704.7			645.4
		Mark-to-market energy assets		342.5			926.8
		Risk management assets		27.3			88.8
		Goodwill		120.6			115.9
		Other		250.7			204.7
		Total investments and other assets		1,943.2			2,506.9
	Property, Plant and Equipment
		Regulated property, plant and equipment		5,203.2			5,075.2
		Nonregulated generation property, plant and equipment		7,552.4			6,811.9
		Other nonregulated property, plant and equipment		323.5			242.0
		Nuclear fuel (net of amortization)		215.3			224.8
		Accumulated depreciation		(3,874.2	)		(4,396.8	)
		Net property, plant and equipment		9,420.2			7,957.1
	Deferred Charges
		Regulatory assets (net)		245.6			405.7
		Other		159.0			136.0
		Total deferred charges		404.6			541.7
	Total Assets		$	15,305.8		$	14,322.9

* Unaudited

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

4

CONSOLIDATED BALANCE SHEETS

Constellation Energy Group, Inc. and Subsidiaries

			September 30, 2003*			December 31, 2002
			(In millions)
Liabilities and Equity
	Current Liabilities
		Short-term borrowings	$	10.4		$	10.5
		Current portion of long-term debt		314.0			426.2
		Accounts payable		1,201.1			943.4
		Customer deposits and collateral		160.9			102.8
		Mark-to-market energy liabilities		530.1			709.6
		Risk management liabilities		197.7			20.1
		Accrued interest		132.1			95.5
		Accrued taxes		125.9			15.0
		Dividends declared		46.7			42.8
		Other		337.9			322.1
		Total current liabilities		3,056.8			2,688.0
	Deferred Credits and Other Liabilities
		Deferred income taxes		1,244.9			1,330.7
		Mark-to-market energy liabilities		254.8			460.0
		Risk management liabilities		98.1			149.5
		Asset retirement obligations		583.2			—
		Net pension liability		246.1			334.6
		Postretirement and postemployment benefits		362.9			352.8
		Deferred investment tax credits		80.3			85.7
		Other		139.6			150.1
		Total deferred credits and other liabilities		3,009.9			2,863.4
	Long-term Debt
		Long-term debt of Constellation Energy		3,350.0			2,800.0
		Long-term debt of nonregulated businesses		345.4			349.8
		First refunding mortgage bonds of BGE		476.0			904.9
		Other long-term debt of BGE		919.6			745.1
		Company obligated mandatorily redeemable trust preferred securities of subsidiary trust holding solely 7.16% debentures of BGE due June 30, 2038		250.0			250.0
		Unamortized discount and premium		(10.7	)		(9.7	)
		Current portion of long-term debt		(314.0	)		(426.2	)
		Total long-term debt		5,016.3			4,613.9
	Minority Interests			111.1			105.3
	BGE Preference Stock Not Subject to Mandatory Redemption			190.0			190.0
	Common Shareholders' Equity
		Common stock		2,153.0			2,078.9
		Retained earnings		2,006.4			1,977.6
		Accumulated other comprehensive loss		(237.7	)		(194.2	)
		Total common shareholders' equity		3,921.7			3,862.3
	Commitments, Guarantees, and Contingencies (see Notes)
	Total Liabilities and Equity		$	15,305.8		$	14,322.9

* Unaudited

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

5

CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)

Constellation Energy Group, Inc. and Subsidiaries

Nine Months Ended September 30,				2003			2002
				(In millions)
Cash Flows From Operating Activities
	Net income			$	158.3		$	460.6
	Adjustments to reconcile to net cash provided by operating activities
		Cumulative effects of changes in accounting principles			198.4			—
		Depreciation and amortization			446.6			403.6
		Accretion of asset retirement obligations			32.0			—
		Deferred income taxes			70.6			25.9
		Investment tax credit adjustments			(5.5	)		(6.0	)
		Deferred fuel costs			(10.9	)		24.4
		Pension and postemployment benefits			(76.0	)		(120.1	)
		Net gain on sales of investments and other assets			(16.3	)		(254.3	)
		Workforce reduction costs			2.1			51.7
		Impairment losses and other costs			—			24.6
		Equity in earnings of affiliates less than dividends received			24.5			47.7
		Changes in
			Accounts receivable		(544.6	)		114.0
			Mark-to-market energy assets and liabilities		21.8			(77.1	)
			Risk management assets and liabilities		(23.7	)		15.2
			Materials, supplies, and fuel stocks		(42.3	)		(34.6	)
			Other current assets		(56.3	)		50.7
			Accounts payable		292.6			(147.4	)
			Other current liabilities		154.8			121.7
			Other		(46.8	)		(44.9	)
	Net cash provided by operating activities				579.3			655.7
Cash Flows From Investing Activities
	Investments in property, plant and equipment				(483.2	)		(621.6	)
	Contributions to nuclear decommissioning trust funds				(13.2	)		(13.2	)
	Acquisitions, net of cash acquired				(517.3	)		(207.8	)
	Sales of investments and other assets				124.3			753.3
	Other investments				(91.4	)		(26.9	)
	Net cash used in investing activities				(980.8	)		(116.2	)
Cash Flows From Financing Activities
	Net maturity of short-term borrowings				(0.1	)		(956.4	)
	Proceeds from issuance of
		Long-term debt			740.6			2,302.7
		Common stock			62.0			19.6
	Repayment of long-term debt				(456.1	)		(1,431.3	)
	Common stock dividends paid				(125.7	)		(98.4	)
	Other				(11.1	)		10.2
	Net cash provided by (used in) financing activities				209.6			(153.6	)
Net (Decrease) Increase in Cash and Cash Equivalents					(191.9	)		385.9
Cash and Cash Equivalents at Beginning of Period					615.0			72.4
Cash and Cash Equivalents at End of Period				$	423.1		$	458.3

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

6

CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED)

Baltimore Gas and Electric Company and Subsidiaries

			Three Months Ended September 30,						Nine Months Ended September 30,
			2003			2002			2003			2002
			(In millions)
Revenues
	Electric revenues		$	582.3		$	596.3		$	1,505.6		$	1,537.1
	Gas revenues			81.0			72.2			524.5			388.1
	Total revenues			663.3			668.5			2,030.1			1,925.2
Expenses
	Operating expenses
		Electricity purchased for resale		345.7			358.6			826.5			872.9
		Gas purchased for resale		30.1			28.3			319.5			191.3
		Operations and maintenance		127.9			92.9			291.3			259.1
		Workforce reduction costs		0.2			3.3			0.7			32.1
	Depreciation and amortization			57.5			55.1			169.3			167.4
	Taxes other than income taxes			39.1			43.0			126.2			129.1
	Total expenses			600.5			581.2			1,733.5			1,651.9
Income from Operations				62.8			87.3			296.6			273.3
Other Income				1.2			3.0			2.2			7.9
Fixed Charges
	Interest expense			26.6			34.2			85.6			108.4
	Allowance for borrowed funds used during construction			(0.3	)		(0.3	)		(1.3	)		(1.1	)
	Total fixed charges			26.3			33.9			84.3			107.3
Income Before Income Taxes				37.7			56.4			214.5			173.9
Income Taxes				13.8			22.5			83.8			69.2
Net Income				23.9			33.9			130.7			104.7
Preference Stock Dividends				3.3			3.3			9.9			9.9
Earnings Applicable to Common Stock			$	20.6		$	30.6		$	120.8		$	94.8

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)

Baltimore Gas and Electric Company and Subsidiaries

			Three Months Ended September 30,				Nine Months Ended September 30,
			2003		2002		2003		2002
			(In millions)
Net Income			$	20.6	$	30.6	$	120.8	$	94.8
	Other comprehensive income
		Unrealized gain on hedging instruments, net of taxes		—		—		0.8		—
Comprehensive Income			$	20.6	$	30.6	$	121.6	$	94.8

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

7

CONSOLIDATED BALANCE SHEETS

Baltimore Gas and Electric Company and Subsidiaries

				September 30, 2003*			December 31, 2002
				(In millions)
Assets
	Current Assets
		Cash and cash equivalents		$	10.6		$	10.2
		Accounts receivable (net of allowance for uncollectibles of $11.5 and $11.5, respectively)			341.2			357.5
		Investment in cash pool, affiliated company			203.5			338.1
		Accounts receivable, affiliated companies			2.4			131.2
		Fuel stocks			91.0			40.6
		Materials and supplies			31.5			31.8
		Prepaid taxes other than income taxes			70.6			42.0
		Other			9.3			10.3
		Total current assets			760.1			961.7
	Other Assets
		Receivable, affiliated company			132.4			63.3
		Other			85.5			85.9
		Total other assets			217.9			149.2
	Utility Plant
		Plant in service
			Electric		3,520.7			3,422.3
			Gas		1,057.5			1,041.0
			Common		471.8			489.1
			Total plant in service		5,050.0			4,952.4
		Accumulated depreciation			(1,784.4	)		(1,851.4	)
		Net plant in service			3,265.6			3,101.0
		Construction work in progress			148.7			118.3
		Plant held for future use			4.5			4.5
		Net utility plant			3,418.8			3,223.8
	Deferred Charges
		Regulatory assets (net)			245.6			405.7
		Other			52.8			39.5
		Total deferred charges			298.4			445.2
	Total Assets			$	4,695.2		$	4,779.9

* Unaudited

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

8

CONSOLIDATED BALANCE SHEETS

Baltimore Gas and Electric Company and Subsidiaries

			September 30, 2003*			December 31, 2002
			(In millions)
Liabilities and Equity
	Current Liabilities
		Current portion of long-term debt	$	310.9		$	420.7
		Accounts payable		78.8			103.2
		Accounts payable, affiliated companies		142.0			85.6
		Customer deposits		59.0			54.2
		Accrued taxes		14.0			9.0
		Accrued interest		31.1			31.4
		Other		101.1			49.7
		Total current liabilities		736.9			753.8
	Deferred Credits and Other Liabilities
		Deferred income taxes		562.3			528.9
		Postretirement and postemployment benefits		283.4			278.0
		Deferred investment tax credits		19.2			20.5
		Decommissioning of federal uranium enrichment facilities		14.6			14.6
		Other		12.3			13.9
		Total deferred credits and other liabilities		891.8			855.9
	Long-term Debt
		First refunding mortgage bonds of BGE		476.0			904.9
		Other long-term debt of BGE		919.6			745.1
		Company obligated mandatorily redeemable trust preferred securities of subsidiary trust holding solely 7.16% debentures of BGE due June 30, 2038		250.0			250.0
		Long-term debt of nonregulated businesses		25.0			25.0
		Unamortized discount and premium		(4.3	)		(5.2	)
		Current portion of long-term debt		(310.9	)		(420.7	)
		Total long-term debt		1,355.4			1,499.1
	Minority Interest			19.1			19.4
	Preference Stock Not Subject to Mandatory Redemption			190.0			190.0
	Common Shareholder's Equity
		Common stock		912.2			912.2
		Retained earnings		589.0			549.5
		Accumulated other comprehensive income		0.8			—
		Total common shareholder's equity		1,502.0			1,461.7
	Commitments, Guarantees, and Contingencies (see Notes)
	Total Liabilities and Equity		$	4,695.2		$	4,779.9

* Unaudited

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

9

CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)

Baltimore Gas and Electric Company and Subsidiaries

Nine Months Ended September 30,				2003			2002
				(In millions)
Cash Flows From Operating Activities
	Net income			$	130.7		$	104.7
	Adjustments to reconcile to net cash provided by operating activities
		Depreciation and amortization			171.7			169.6
		Deferred income taxes			33.9			(3.1	)
		Investment tax credit adjustments			(1.4	)		(1.6	)
		Deferred fuel costs			(10.9	)		24.4
		Pension and postemployment benefits			(61.3	)		(42.0	)
		Workforce reduction costs			0.7			32.1
		Allowance for equity funds used during construction			(2.3	)		(2.1	)
		Changes in
			Accounts receivable		16.3			(26.7	)
			Receivables, affiliated companies		59.7			11.0
			Materials, supplies, and fuel stocks		(50.1	)		(2.2	)
			Other current assets		(27.6	)		1.3
			Accounts payable		(24.4	)		5.1
			Accounts payable, affiliated companies		56.4			(14.9	)
			Other current liabilities		60.9			10.8
			Other		72.3			12.0
	Net cash provided by operating activities				424.6			278.4
Cash Flows From Investing Activities
	Utility construction expenditures (excluding AFC)				(204.3	)		(136.1	)
	Investment in cash pool at parent				134.6			55.4
	Other				(0.9	)		(22.0	)
	Net cash used in investing activities				(70.6	)		(102.7	)
Cash Flows From Financing Activities
	Proceeds from issuance of long-term debt				196.8			—
	Repayment of long-term debt				(460.4	)		(393.4	)
	Distribution (to) from parent				(81.3	)		200.0
	Preference stock dividends paid				(9.9	)		(9.9	)
	Other				1.2			—
	Net cash used in financing activities				(353.6	)		(203.3	)
Net Increase (Decrease) in Cash and Cash Equivalents					0.4			(27.6	)
Cash and Cash Equivalents at Beginning of Period					10.2			37.4
Cash and Cash Equivalents at End of Period				$	10.6		$	9.8

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

10

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 "utility business" 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 consist of stock options of 0.7 million for the quarter and 0.3 million for the nine months ended September 30, 2003.

        There were no stock options excluded from the computation of diluted EPS for the quarter ended September 30, 2003. Stock options to purchase approximately 4.9 million shares were excluded from the computation of diluted EPS during the quarter ended September 30, 2002 because they were not dilutive.

        Stock options to purchase approximately 2.8 million shares during the nine months ended September 30, 2003 and approximately 2.2 million shares during the nine months ended September 30, 2002 were not dilutive and were excluded from the computation of diluted EPS for those periods.

Stock-Based Compensation

Under our long-term incentive plans, we granted stock options, performance and 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 13 of our 2002 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 September 30,						Nine Months Ended September 30,
		2003			2002			2003			2002
		(In millions, except per share amounts)
Net income, as reported		$	192.9		$	150.7		$	158.3		$	460.6
Add: Stock-based compensation expense determined under intrinsic value method and included in reported net income, net of related tax effects			3.8			2.4			7.9			4.7
Deduct: Stock-based compensation expense determined under fair value based method for all awards, net of related tax effects			(5.9	)		(5.9	)		(14.4	)		(11.4	)
Pro-forma net income		$	190.8		$	147.2		$	151.8		$	453.9
Earnings per common share:
	Basic – as reported	$	1.16		$	0.92		$	0.95		$	2.81
	Basic – pro forma	$	1.14		$	0.90		$	0.91		$	2.77
	Diluted – as reported	$	1.15		$	0.92		$	0.95		$	2.81
	Diluted – pro forma	$	1.14		$	0.90		$	0.91		$	2.77

11

Workforce Reduction Costs

We incurred costs related to workforce reduction efforts initiated in previous years. We discuss these costs in more detail below and in Note 2 of our 2002 Annual Report on Form 10-K.

2003

During the quarter ended September 30, 2003, we recorded $0.7 million in expense, of which BGE recorded $0.2 million, associated with deferred payments to employees eligible for the 2001 Voluntary Special Early Retirement Program.

        During the nine months ended September 30, 2003, we recorded $2.1 million in expense, of which BGE recorded $0.7 million, associated with deferred payments to employees eligible for the 2001 Voluntary Special Early Retirement Program.

        In 2002, we recorded $14.9 million of expenses for anticipated involuntary severance costs in accordance with Emerging Issues Task Force (EITF) 94-3, Liability Recognition for Certain Employee Termination Benefits and Other Costs to Exit an Activity (including Certain Costs Incurred in a Restructuring), associated with new workforce reduction initiatives in 2002. The following table summarizes the status of the involuntary severance liability recorded under EITF 94-3.

	(In millions)
Severance liability balance at December 31, 2002	$	14.9
Cash severance payments in first quarter		(10.5	)
Cash severance payments in second quarter		(1.3	)
Cash severance payments in third quarter		(0.7	)
Severance costs recorded as postretirement benefit liability		(0.8	)
Severance liability balance at September 30, 2003	$	1.6

2002

In the first quarter of 2002, we recorded $35.1 million of net workforce reduction costs associated with our 2001 workforce reduction initiatives. The $35.1 million of net workforce reduction costs recorded during the first quarter of 2002 consisted of $25.9 million recognized as expense, of which BGE recognized $20.9 million. The remaining $9.2 million was recognized by BGE as a regulatory asset related to its gas business.

        In the second quarter of 2002, we recorded $16.3 million of net workforce reduction costs. The $16.3 million of net workforce reduction costs recorded in the second quarter of 2002 consisted of $13.3 million recognized as expense, of which BGE recognized $7.9 million. The remaining $3.0 million was recognized by BGE as a regulatory asset related to its gas business.

        In the third quarter of 2002, we recorded $6.0 million of additional costs associated with our 2001 workforce reduction initiatives. The $6.0 million, included $5.3 million recognized as expense, of which BGE recognized $3.3 million. The remaining $0.7 million was recognized by BGE as a regulatory asset related to its gas business.

        Additionally, in the third quarter of 2002, we recorded approximately $7.2 million of workforce reduction costs associated with new initiatives at our Calvert Cliffs Nuclear Power Plant (Calvert Cliffs) and in our information technology organization. BGE recorded $0.6 million of this amount associated with the information technology organization.

        We also recorded $2.7 million of workforce reduction costs as a result of the closing of our BGE Home retail merchandise stores during the third quarter of 2002. These costs are included in "Impairment losses and other costs" in our Consolidated Statements of Income.

        In 2002, we completed involuntary severances under our 2001 workforce reduction programs. Accordingly, no involuntary severance liability recorded under EITF 94-3 remained at December 31, 2002.

Impairment Losses and Other Costs

Investments in Qualifying Facilities and Power Projects

In the third quarter of 2002, we recorded impairment losses totaling $14.4 million pre-tax, or $9.9 million after-tax, under the provisions of APB No. 18, The Equity Method of Accounting for Investments in Common Stock.

        We concluded that declines in the value of our investment in certain qualifying facilities and power projects were other than temporary in nature under the provisions of APB No. 18 and we recognized the following losses in the third quarter of 2002:

•

We recognized a $5.2 million pre-tax, or $3.4 million after-tax, other than temporary decline in value of our investment in a partnership that owns a geothermal project in Nevada.

•

We recognized a $2.6 million pre-tax, or $1.7 million after-tax, other than temporary decline in value of our investment in a fuel processing site in Pennsylvania.

•

We recognized a $6.6 million pre-tax, or $4.8 million after-tax, other than temporary decline in value of our investment in a partnership that owns a waste burning power project in Michigan.

12

Closing of BGE Home Retail Merchandise Stores

In September 2002, we announced our decision to close our BGE Home retail merchandise stores. In connection with that decision, we recognized approximately $9.3 million in exit costs, of which $0.9 million is included in "Operating expenses" in our Consolidated Statements of Income.

Real Estate and International Investments

As discussed in Note 2 of our 2002 Annual Report on Form 10-K, in the fourth quarter of 2001 we changed our strategy from an intent to hold to an intent to sell for certain of our non-core assets. During the third quarter of 2002, we determined that the fair value of several real estate projects and our investment in an international power project declined below their respective book values due to deteriorating market conditions for these projects. Accordingly, we recorded losses that totaled $1.8 million for these projects in accordance with SFAS No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets, and APB No. 18.

Net Gain on Sales of Investments and Other Assets

2003

During the nine months ended September 30, 2003, our other nonregulated businesses recognized $16.3 million pre-tax, or $9.9 million after-tax, gains on the sale of non-core assets as follows:

•

a $7.2 million pre-tax gain during the first quarter on the sale of an oil tanker to the U.S. Navy,

•

a $5.3 million pre-tax gain during the first quarter 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 during the first quarter on an installment sale of a parcel of real estate,

•

a $0.5 million pre-tax gain during the second quarter on the sale of financial investments as we continued to liquidate this operation,

•

a $1.5 million pre-tax gain during the third quarter from the sale of two parcels of real estate, and

•

a $0.6 million pre-tax gain during the third quarter on the sale of financial investments as we continued to liquidate this operation.

2002

During the nine months ended September 30, 2002, our nonregulated businesses recognized $254.3 million net pre-tax gains on the sale of financial investments and other non-core assets, including the gain on the sale of our investment in Orion Power Holdings, Inc. (Orion).

        In February 2002, Reliant Resources, Inc. acquired all of the outstanding shares of Orion for $26.80 per share, including the shares of Orion we owned. We received cash proceeds of $454.1 million and recognized a gain of $255.5 million pre-tax, or $163.3 million after-tax, on the sale of our investment.

        During the second quarter of 2002, our merchant energy business sold a turbine-generator set for $6.0 million below its book value.

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,

–

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 single-site heating, cooling, and cogeneration facilities for commercial and industrial customers throughout North America,

•

provide home improvements, service gas and electric appliances, service heating, air conditioning, plumbing, electrical, and indoor air quality systems, and provide electric and natural gas retail marketing in central Maryland, and

•

own and operate a district cooling system for commercial customers in the City of Baltimore, 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.

        These reportable segments are strategic businesses based principally upon regulations, products, and services that 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 on the next page.

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	Merchant Energy Business			Regulated Electric Business		Regulated Gas Business			Other Nonregulated Businesses			Eliminations			Consolidated
For the three months ended September 30,	(In millions)
2003
Unaffiliated revenues	$	1,799.5		$	582.3	$	78.3		$	144.3		$	—		$	2,604.4
Intersegment revenues		377.8			—		2.7			0.2			(380.7	)		—
Total revenues		2,177.3			582.3		81.0			144.5			(380.7	)		2,604.4
Income from operations		316.0			51.7		11.1			10.4			—			389.2
Net income		171.6			18.2		2.4			0.7			—			192.9
2002
Unaffiliated revenues	$	472.3		$	596.1	$	67.7		$	133.5		$	—		$	1,269.6
Intersegment revenues		380.7			0.2		4.5			—			(385.4	)		—
Total revenues		853.0			596.3		72.2			133.5			(385.4	)		1,269.6
Income from operations		229.8			87.7		(0.4	)		(9.1	)		—			308.0
Net income (loss)		130.3			35.0		(4.1	)		(10.5	)		—			150.7
For the nine months ended September 30,
2003
Unaffiliated revenues	$	4,742.9		$	1,505.5	$	514.0		$	443.1		$	—		$	7,205.5
Intersegment revenues		938.5			0.1		10.5			0.2			(949.3	)		—
Total revenues		5,681.4			1,505.6		524.5			443.3			(949.3	)		7,205.5
Income from operations		457.7			220.4		76.2			39.8			—			794.1
Cumulative effects of changes in accounting principles		(198.4	)		—		—			—			—			(198.4	)
Net income		27.5			89.3		31.9			9.6			—			158.3
2002
Unaffiliated revenues	$	1,051.6		$	1,536.8	$	379.1		$	385.6		$	—		$	3,353.1
Intersegment revenues		898.0			0.3		9.0			—			(907.3	)		—
Total revenues		1,949.6			1,537.1		388.1			385.6			(907.3	)		3,353.1
Income from operations		378.4			208.4		64.9			259.8			—			911.5
Net income		213.7			68.8		26.6			151.5			—			460.6

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

14

Financing Activity

Constellation Energy

Constellation Energy issued the following notes during the period from January 1, 2003 through the date of this report:

	Principal	Date Issued	Maturity and Repayment Date	Net Proceeds
	(In millions)
4.55% Fixed Rate Notes; semi-annual interest payments	$550.0	6/03	6/15	$543.8

         We used the net proceeds from this issuance to refinance the debt associated with the High Desert Power Project that we acquired and consolidated at June 30, 2003. We discuss the acquisition of the High Desert Power Project in more detail in the Acquisitions section on page 21.

        In June 2003, Constellation Energy arranged a $447.5 million 364-day revolving credit facility and a $447.5 million three-year revolving credit facility replacing a $640.0 million 364-day revolving credit facility and a $188.5 million three-year revolving credit facility. Both of the facilities that were replaced expired in the second quarter of 2003. Constellation Energy also has a $640.0 million revolving credit facility that expires in June 2005.

        We use these three 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 the issuance of letters of credit primarily for our merchant energy business.

        These revolving credit facilities allow the issuance of letters of credit up to approximately $1.1 billion. At September 30, 2003, letters of credit that totaled $412.1 million were issued under all of our facilities.

        Additionally, under our continuous offering program, employee savings plans, dividend reinvestment plans, and shareholder investment plans we issued $62.0 million of common stock during the nine months ended September 30, 2003.

BGE

BGE issued the following notes during the period from January 1, 2003 through the date of this report:

	Principal	Date Issued	Maturity and Repayment Date	Net Proceeds
	(In millions)
5.20% Fixed Rate Notes; semi-annual interest payments	$200.0	6/03	6/33	$196.8

        In June 2003, BGE announced that it would redeem prior to maturity approximately $98.0 million principal amount outstanding of its 7¹/2% Series due March 1, 2023 First Refunding Mortgage Bonds, which were redeemed on July 21, 2003 at the regular redemption price of 103.32% of principal plus accrued interest from March 1, 2003 to July 20, 2003. BGE also announced that it would redeem prior to maturity approximately $72.3 million principal amount outstanding of its 7¹/2% Series due April 15, 2023 First Refunding Mortgage Bonds, which were redeemed on July 21, 2003 at the regular redemption price of 103.53% of principal plus accrued interest from April 15, 2003 to July 20, 2003.

        During 2003, certain credit facilities expired and BGE renewed those facilities. BGE continues to maintain $200.0 million in committed credit facilities, expiring May 2004 through November 2004. BGE can borrow directly from the banks or use the facilities to allow the issuance of commercial paper. As of September 30, 2003, BGE had no outstanding commercial paper, which results in $200.0 million in unused credit facilities.

        In the future, BGE may purchase some of its long-term debt or preference stock in the market depending on market conditions and BGE's capital structure.

Income Taxes

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 change agent to create a significant chemical change. To qualify for the Section 29 tax credits, the synthetic fuel must meet three primary conditions:

•

there must be a significant chemical change in the coal,

•

the product must be sold to an unaffiliated entity, and

•

the production facility must have been originally placed in service before July 1, 1998.

        As of September 30, 2003, we have recognized cumulative tax benefits associated with Section 29 credits of $69.7 million, of which $26.7 million was recognized during the nine months ended September 30, 2003 and $8.8 million was recognized during the quarter ended September 30, 2003.

15

        In June 2003, the Internal Revenue Service (IRS) issued Announcement 2003-46 which indicated they were suspending the issuance of private letter rulings regarding Section 29 tax credits until the IRS completed a review of the scientific validity of certain test procedures and results presented as evidence to prove a significant chemical change had occurred.

        Certain facilities in which we have an investment received private letter rulings from the IRS stating that the synthetic fuel produced undergoes a significant chemical change and thus qualifies for Section 29 credits. These private letter rulings were based, in part, on tests performed by independent scientific laboratories that were disclosed to the IRS as part of the ruling request process. The partnership that owns these facilities is currently under examination by the IRS. As part of their examination, the IRS engaged two third-party chemists to perform tests of the synthetic fuel. In October 2003, these chemists issued reports indicating that the synthetic fuel produced does not undergo a significant chemical change.

        There have been two favorable developments since the second quarter of 2003. First, an owner of a similar synthetic fuel facility that was under examination by the IRS on the chemical change issue recently disclosed that they were informed by the IRS National Office that the private letter ruling for their facility would not be revoked.

        Second, on October 29, 2003, the IRS issued Announcement 2003-70 indicating that it had completed the review started with Announcement 2003-46 and would resume issuing private letter rulings on significant chemical change. Announcement 2003-70 also specified that taxpayers would be required to maintain appropriate procedures and periodic reports from independent laboratories documenting significant chemical change and that these requirements would be extended to taxpayers already holding private letter rulings. We are still evaluating the impact of these requirements.

        As a result of these favorable developments and our belief that the chemical testing procedures and results presented by the independent scientific laboratories in the ruling requests were properly disclosed to the IRS, we believe that the private letter rulings held by the partnership in which we have an interest will not be revoked and that the IRS will favorably conclude their examination of the partnership.

        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 the review by the IRS or its ultimate impact 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.

Commitments, Guarantees, and Contingencies

Our merchant energy business enters into long-term contracts for:

•

the purchase of electric generating capacity and energy,

•

the procurement and delivery of fuels to supply our generating plant requirements,

•

the capacity and transmission and transportation rights for the physical delivery of energy to meet our obligations to our customers, and

•

other capital requirements.

        Our regulated gas business enters into various long-term contracts for the procurement, transportation, and storage of gas. In the third quarter of 2003, our regulated gas business renegotiated certain gas transportation and storage contracts that were set to expire in 2004 which now expire between 2009 and 2019. These contracts are recoverable under BGE's gas cost adjustment clause as discussed in more detail in Note 1 of our 2002 Annual Report on Form 10-K.

        BGE Home Products & Services also has gas and electric purchase commitments related to sales programs. The electric commitments expire in 2004 and the gas commitments expire in 2003.

        At September 30, 2003, the total amount of commitments was $3,583.2 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 2011 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
	2003		2004- 2005		2006- 2007		Thereafter		Total
	(In millions)
Competitive Supply	$	2,142.8	$	1,034.4	$	50.8	$	313.7	$	3,541.7
Other		6.7		7.7		3.0		508.4		525.8
Total	$	2,149.5	$	1,042.1	$	53.8	$	822.1	$	4,067.5

16

        At September 30, 2003, Constellation Energy had a total of $4,067.5 million in guarantees outstanding related to loans, credit facilities, and contractual performance of certain of our subsidiaries as described below. These guarantees do not represent incremental consolidated Constellation Energy obligations; rather, they primarily represent parental guarantees of certain subsidiary obligations. We do not expect to fund the full amount under these guarantees.

•

Constellation Energy guaranteed $3,541.7 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 cash collateral. While the face amount of these guarantees is $3,541.7 million, our calculated fair value of obligations covered by these guarantees was $714.9 million at September 30, 2003. We do not expect to fund the full amount under these guarantees. The recorded fair value of obligations in our Consolidated Balance Sheets for these guarantees was $541.3 million at September 30, 2003.

•

Constellation Energy guaranteed $195.0 million primarily on behalf of Nine Mile Point related to nuclear decommissioning.

•

Constellation Energy guaranteed $60.2 million on behalf of our other nonregulated businesses primarily for loans and performance bonds of which $25.6 million was recorded in our Consolidated Balance Sheets at September 30, 2003.

•

Our merchant energy business guaranteed $7.3 million for loans related to certain power projects in which we have an investment.

•

BGE guaranteed two-thirds of certain debt of Safe Harbor Water Power Corporation. At September 30, 2003, 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 Originated Preferred Securities (TOPrS) of $250.0 million. We discuss TOPrS in more detail in Note 8 of our 2002 Annual Report on Form 10-K.

        As discussed in Note 11 of our 2002 Annual Report on Form 10-K, Constellation Energy guaranteed up to $600.0 million relating to the High Desert Power Project. The guarantee ended when we paid off the High Desert lease on June 27, 2003 as discussed in the Acquisitions section on page 21. Constellation Energy still has a guarantee in place to cover any indemnification to the previous financiers of the High Desert Power Trust for legal matters that may arise in the future. However, no amount has been recorded as there is no litigation currently pending that this guarantee would cover.

        The total fair value of the obligations for our guarantees recorded in our Consolidated Balance Sheets was $816.9 million and not the $4,067.5 million 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

•

disposal of hazardous substances.

        As new laws or regulations are promulgated, we assess their applicability and implement the necessary modifications to our facilities or their operation, as required.

        We discuss the significant matters below.

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 SO₂ (sulfur dioxide), NOx (nitrogen oxide), 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.

        On October 27, 1998, the Environmental Protection Agency (EPA) issued a rule requiring 22 Eastern states and the District of Columbia to reduce emissions of NOx. The EPA rule requires states to implement controls sufficient to meet their NOx budget by May 30, 2004. However, the Northeast states decided to require compliance in 2003. Coal-fired power plants are a principal target of NOx reductions under this initiative.

17

        Many of our generation facilities are subject to NOx reduction requirements under the EPA rule, including those located in Maryland and Pennsylvania. At the Brandon Shores and Wagner facilities, we installed emission reduction equipment for our coal-fired units to meet Maryland regulations issued pursuant to the EPA's rule. The owners of the Keystone plant in Pennsylvania completed the installation of emissions reduction equipment by July 2003 to meet Pennsylvania regulations issued pursuant to the EPA's rule. The total cost of the emissions reduction equipment was approximately $37 million.

        The EPA established new National Ambient Air Quality Standards for very fine particulates and revised standards for ozone attainment that were upheld after various court appeals. While these standards may require increased controls at some of our fossil generating plants in the future, implementation could be delayed for several years. We cannot estimate the cost of these increased controls at this time because the states, including Maryland, Pennsylvania, and California, still need to determine what reductions in pollutants will be necessary to meet the EPA standards.

        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. We have responded to the EPA, and as of the date of this report the EPA has taken no further action.

        On October 27, 2003, the EPA's new source review rule on routine maintenance was published in the Federal Register. The new regulations address an equipment replacement cost threshold for determining when major new source review requirements are triggered. Plant owners may spend up to 20% of the value of a facility on improvements each year without triggering requirements for new pollution controls. Parties have until December 26, 2003, the effective date of the rule, to appeal the agency's decision in court.

        Based on the levels 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 is successful in any future actions regarding our facilities.

        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. Compliance could be required by approximately 2007. We believe final regulations could be issued in 2004 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 stormwater discharges.

        In April 2002, the EPA proposed rules under the Clean Water Act that require that cooling water intake structures reflect the best technology available for minimizing adverse environmental impacts. A final action on the proposed rules is expected by February 2004. The proposed rules may require the installation of additional intake screens or other protective measures, as well as extensive site-specific study and monitoring requirements. There is also the possibility that the proposed rules may lead to the installation of cooling towers on four of our fossil and both of our nuclear facilities. Our compliance costs associated with the final rules could be material.

Waste Disposal

The EPA and several state agencies have notified us that we are considered a potentially responsible party with respect to the cleanup of certain environmentally contaminated sites owned and operated by others. We cannot estimate the cleanup 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 cleanup 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. The 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.

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        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 cleanup 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, the EPA re-proposed the 68^th Street site to the NPL, but decided not to include the site in its September 2003 update. BGE and other potentially responsible parties are pursuing alternatives to the NPL listing for the site, but at this stage, it is not possible to predict the outcome of those discussions, the cleanup cost of the site, or BGE's share of the liability. However, the costs could have a material effect on our, or BGE's, financial results.

        In late December 1996, BGE signed a consent order with the Maryland Department of the Environment that required it to implement remedial action plans for contamination at and around the Spring Gardens site, located in Baltimore, Maryland. The Spring Gardens site was once used to manufacture gas from coal and oil. Based on 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 September 30, 2003, BGE spent approximately $39 million for remediation at this site. BGE also investigated other small sites where gas was manufactured in the past. We do not expect the cleanup costs of the remaining smaller sites to have a material effect on our financial results.

        On September 30, 2003, the EPA issued its ROD for the Kane and Lombard Drum site located in Baltimore, Maryland. 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. We expect the EPA to approach the potentially responsible parties regarding implementation of the plan in late 2003 or early 2004. The total clean-up costs are estimated to be $7.3 million of which we estimate our current share of site-related costs to be 11.1%. In December 2002, we recorded a liability in our Consolidated Balance Sheets for our estimated share of the clean up costs that we believe is probable. However, our share of these future costs has not been determined and it may vary from the current estimate.

Nuclear Insurance

We maintain nuclear insurance coverage for Calvert Cliffs and Nine Mile Point 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.

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. Effective August 20, 2003, the retrospective premium assessment has been increased to $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 $402.4 million per incident at any commercial reactor in the country, payable at no more than $40 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. 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 an annual 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.

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        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 premium assessments. 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 and an additional $2.25 billion in excess coverage for property damage, decontamination, and premature decommissioning liability for Calvert Cliffs or Nine Mile Point. 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 $68.6 million.

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, $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 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. Effective August 21, 2003, our conventional property insurance program also provides coverage of $333.0 million per occurrence (subject to a $333.0 million annual aggregate) for losses resulting from non-certified acts of terrorism, retroactive to July 1, 2003. If a terrorist act occurs at any of our facilities, it could have a significant adverse impact on our financial results.

California Power Agreements

Our merchant energy business has $255.4 million invested in operating power projects of which our ownership percentage represents 140 megawatts of electricity that are sold to Pacific Gas & Electric (PGE) and to Southern California Edison (SCE) in California under power purchase agreements.

        As a result of ongoing litigation before the Federal Energy Regulatory Commission (FERC) regarding sales into the spot markets of the California Independent System Operator (ISO) and Power Exchange (PX), we currently estimate that we may be required to pay refunds of between $2 million and $6 million for transactions that we entered into with these entities for the period between October 2000 and June 2001. However, we cannot determine the actual amount we could be required to pay because litigation is ongoing and new events could occur that may cause the actual amount, if any, to be materially different from our estimate.

SFAS No. 133 Hedging Activities

We are exposed to market risk, including changes in interest rates and the impact of market fluctuations in the price and transportation costs of electricity, natural gas, and other commodities. We discuss our market risk in more detail in our 2002 Annual Report on Form 10-K.

Interest Rates

We use interest rate swaps to manage our interest rate exposure associated with new debt issuances. These swaps are designated as cash-flow hedges in anticipation of planned financing transactions under SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities, with gains and losses, net of associated deferred income tax effects, recorded in "Accumulated other comprehensive income" in our Consolidated Balance Sheets. We reclassify gains and losses on the hedges from "Accumulated other comprehensive income" into "Interest expense" during the periods in which the interest payments being hedged occur.

        During the second quarter of 2003, we entered into various forward starting interest rate swaps to manage our interest rate exposure for the issuances of $550.0 million of Constellation Energy debt and $200.0 million of BGE debt. All of these swap contracts expired in the second quarter of 2003 resulting in a pre-tax net loss of $8.7 million that was recorded in "Accumulated other comprehensive income" in our Consolidated Balance Sheets. Of this amount, BGE recorded a pre-tax gain of $1.2 million in "Accumulated other comprehensive income" in its Consolidated Balance Sheets.

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        At September 30, 2003, we have net unrealized pre-tax gains of $21.9 million on interest rate cash-flow hedges, net of associated deferred income tax effects, recorded in "Accumulated other comprehensive income." We expect to reclassify $2.9 million of pre-tax net gains on these cash-flow hedges from "Accumulated other comprehensive income" into "Interest expense" during the next twelve months.

Commodity Prices

At September 30, 2003, our merchant energy business had designated certain fixed-price forward purchase and sale contracts as cash-flow hedges of forecasted transactions for the years 2003 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 transaction. We reclassify these gains or losses into earnings upon settlement of the underlying hedged transaction. We record derivatives used for hedging activities in "Risk management assets and liabilities" in our Consolidated Balance Sheets.

        At September 30, 2003, our merchant energy business had net unrealized pre-tax losses of $129.2 million on these hedges, net of associated deferred income tax effects, recorded in "Accumulated other comprehensive income." We expect to reclassify $32.6 million of net pre-tax losses on cash-flow hedges from "Accumulated other comprehensive income" into earnings during the next twelve months based on the market prices at September 30, 2003. However, the actual amount reclassified into earnings could vary from the amounts recorded at September 30, 2003 due to future changes in market prices. We recognized into earnings a pre-tax net loss of $6.5 million for the quarter ended September 30, 2003 and a pre-tax net gain of $2.8 million for the nine months ended September 30, 2003 related to the ineffective portion of our hedges.

Acquisitions

High Desert Power Project

In April 2003, our High Desert Power Project in Victorville, California, an 830 megawatt (MW) gas-fired combined cycle facility, commenced operations. The project has a long-term power sales agreement with the California Department of Water Resources (CDWR). The contract is a "tolling" structure, under which the CDWR pays a fixed amount of $12.1 million per month and provides CDWR the right, but not the obligation, to purchase power from the project at a price linked to the variable cost of production. During the term of the contract, which runs for seven years and nine months from the April 2003 commercial operation date of the plant, the project will provide energy exclusively to the CDWR.

        Prior to June 2003, we accounted for this project as an operating lease. In June 2003, we elected to refinance the lease to extend the tenor of the financing at attractive interest rates. Accordingly, we exercised our option under the lease associated with the High Desert Power Project, paid off the lease, and acquired the assets from the lessor. At June 30, 2003 the assets and liabilities associated with the High Desert Power Project were included in our Consolidated Balance Sheets.

        Our preliminary purchase price allocation for the net assets acquired is as follows:

At June 27, 2003	(In millions)
Cash	$	4.3
Other Current Assets		1.6
Other Noncurrent Assets		1.7
Net Property, Plant and Equipment		528.3
Total Assets Acquired		535.9
Accounts Payable		(17.5	)
Net Assets Acquired	$	518.4

        Currently we have not finalized the valuation of any potential intangible assets that could impact our purchase price allocation.

Blackhawk Energy Services and Kaztex Energy Management

On October 22, 2003, we purchased Blackhawk Energy Services (Blackhawk) and Kaztex Energy Management (Kaztex). Blackhawk and Kaztex are providers of natural gas and electricity products, serving approximately 1,100 customers representing approximately 70 billion cubic feet of natural gas and 0.9 million megawatt hours of electricity throughout Illinois and Wisconsin. We acquired 100% ownership of both companies for $26.9 million.

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Accounting Standards Issued

SFAS No. 133—DIG Issue No. C20

In June 2003, the Financial Accounting Standards Board (FASB) cleared Derivatives Implementation Group Statement 133 Implementation Issue No. C20, Interpretation of the Meaning of Not Clearly and Closely Related in Paragraph 10(b) regarding Contracts with a Price Adjustment Feature (DIG C20). The scope of DIG C20 includes power and gas contracts that meet the definition of a derivative under SFAS No. 133. The provisions of DIG C20 provide guidance on determining whether any such contracts that include a price adjustment mechanism are eligible for accrual accounting under the normal purchase and normal sale exception to SFAS No. 133.

        DIG C20 requires all entities to evaluate any derivatives previously designated as normal purchases or normal sales under this exception to determine whether they previously should have been marked-to-market, and to record the fair value of any such contracts as a cumulative effect adjustment to earnings at the time of adoption. The provisions of DIG C20 must be adopted no later than October 1, 2003. We are still evaluating whether we have any contracts that are subject to DIG C20. The effect of applying its provisions could be material to our financial results.

FIN 46

In January 2003, the FASB issued Interpretation No. (FIN) 46, Consolidation of Variable Interest Entities, that addresses conditions when an entity should 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 46 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 do not have voting rights.

        FIN 46 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 the entity's expected losses, residual returns, or both.

        FIN 46 applied immediately to all VIEs created after January 31, 2003. In October 2003, the FASB deferred implementation of FIN 46 to December 31, 2003 for public entities with interests in VIEs or potential VIEs created before February 1, 2003. The FASB deferred the implementation date in order to issue additional implementation guidance and to permit more time to complete the evaluation of existing VIEs. As a result, we have not completed our review of these entities. Upon completion of our review, the specific entities for which we are required to apply the provisions of FIN 46, as well as the required application of those provisions, could differ from the results of our initial review, which are discussed below.

        Based on our initial review of entities with which we are involved through variable interests, we believe that the VIEs for which we are the primary beneficiary include a geothermal power project, the Safe Harbor Water Power Corporation, and an office building in Annapolis, Maryland, that we partially occupy. The other VIEs in which we have a significant interest include certain other power projects, fuel processing facilities, and a natural gas producing facility. We believe that we will not be required to consolidate these entities because we are not the primary beneficiary.

        When we consolidate those VIEs for which we are the primary beneficiary we will remove from our Consolidated Balance Sheets our previously recorded investment and record in our Consolidated Balance Sheets the total assets, liabilities and other ownership interests as reflected in the financial statements of those entities. We estimate that the net amount we will add to our Consolidated Balance Sheets will equal our recorded investment. As a result, we do not expect to record a cumulative effect of change in accounting principle upon adoption of FIN 46 in the fourth quarter of 2003. Upon adoption of FIN 46, we will discontinue applying the equity method of accounting and begin recording in our Consolidated Statements of Income the revenues and expenses of those VIEs for which we are the primary beneficiary. This change will not affect our earnings.

        The variable interests in entities in which we are involved generally consist of equity investments, guarantees of the entities' debt, and in one instance, beginning in the third quarter of 2003, a natural gas producer swap with volumetric and price variability. The following is summary information about these entities as of September 30, 2003:

	Primary Beneficiary		Significant Interest		Total
	(In millions)
Total assets	$	322	$	630	$	952
Total liabilities		149		528		677
Our ownership interest		134		23		157
Other ownership interests		39		79		118
Our maximum exposure to loss		160		170		330

        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

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guarantees associated with these entities. Our maximum exposure to loss as of September 30, 2003 consists of the following:

•

our recorded investment in these VIEs totaling $203 million,

•

guarantees of $27 million of the debt of these VIEs and,

•

volumetric and price variability of up to $100 million associated with a natural gas producer swap, based on contract volumes and gas prices as of September 30, 2003.

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

Accounting Standards Adopted

SFAS No. 150

In May 2003, the FASB issued SFAS No. 150, Accounting for Certain Financial Instruments with Characteristics of Both Liabilities and Equity. The statement establishes standards for how an issuer classifies and measures certain financial instruments with characteristics of both liabilities and equity. However, in October 2003, the FASB deferred indefinitely the statement's provisions related to redeemable minority interests. SFAS No. 150 is effective for interim periods beginning after June 15, 2003, for financial instruments entered into or modified after May 31, 2003. Adoption of the provisions of this statement did not have a material impact on our financial results.

SFAS No. 149

In April 2003, the FASB issued SFAS No. 149, Amendment of Statement 133 on Derivative Instruments and Hedging Activities. The statement amends and clarifies SFAS No. 133 for certain interpretive guidance issued by the Derivatives Implementation Group. SFAS No. 149 was effective after June 30, 2003, for contracts entered into or modified and for hedges designated after the effective date. The adoption of this standard did not have a material impact on our financial results.

SFAS No. 143

In 2001, the FASB issued SFAS No. 143, Accounting for Asset Retirement Obligations. SFAS No. 143 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.

        In the first quarter of 2003, we adopted this statement and recognized a $112.1 million pre-tax, or $67.7 million after-tax, gain as a cumulative effect of change in accounting principle.

        Substantially all of this net gain relates to the impact of adopting SFAS No. 143 on the measurement of the liability for the decommissioning of our Calvert Cliffs nuclear power plant. Losses on the adoption of SFAS No. 143 in other areas of our business are offset by a gain relating to the liability for the decommissioning of our Nine Mile Point nuclear power plant. The Calvert Cliffs' gain is primarily due to using a longer discount period as a result of license extension. The previous liability for the decommissioning of Calvert Cliffs was determined in accordance with ratemaking treatment established by the Maryland Public Service Commission (Maryland PSC) based on a prior decommissioning cost estimate that contemplated decommissioning being completed at a point in time much closer to the expiration of the plant's original operating license.

        As discussed in Note 1 of our 2002 Annual Report on Form 10-K, we use the composite depreciation method for certain generating facilities and for our utility business. This method is an acceptable method of accounting under generally accepted accounting principles and is widely used in the energy, transportation, and telecommunication industries.

        Historically, under the composite depreciation method, the anticipated costs of removing assets upon retirement are provided for over the life of those assets as a component of depreciation expense. However, SFAS No. 143 precludes the recognition of expected net future costs of removal as a component of depreciation expense or accumulated depreciation unless they are legal obligations under SFAS No. 143. Instead, we must recognize these costs as incurred, unless the entity is rate regulated under SFAS No. 71, Accounting for the Effects of Certain Types of Regulation.

        For our merchant energy business, the elimination of net cost of removal from accumulated depreciation did not have a material impact on our financial results. However, we expect depreciation expense for 2003 and future years to be lower than prior years since depreciation expense will no longer include a component for anticipated cost of removal in excess of salvage. Also, effective January 1, 2003, we only record those asset removal costs that represent legal obligations under SFAS No. 143 prior to their being incurred.

        The adoption of SFAS No. 143 did not have a material impact on BGE's financial results. BGE is required by the Maryland PSC to use the composite depreciation method under regulatory accounting. As a

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result, BGE reclassified $108.4 million of net cost of removal from accumulated depreciation to a regulatory liability in the first quarter of 2003. In accordance with SFAS No. 71, BGE continues to accrue for the future cost of removal for its rate regulated gas and electric utility assets.

        The change in our "Asset retirement obligations" liability during the first nine months of 2003 was as follows:

	(In millions)
Liability at January 1, 2003	$	570.6
Liabilities incurred		1.2
Liabilities settled		(20.6	)
Accretion expense		32.0
Revisions to cash flows		—
Liability at September 30, 2003	$	583.2

        The pro-forma asset retirement obligation we would have recognized as of January 1, 2002, had we implemented SFAS No. 143 as of that date, was approximately $530 million based on the information, assumptions, and interest rates as of January 1, 2003 used to determine the $570.6 million liability recognized upon the adoption of SFAS No. 143.

        The fair value of our nuclear decommissioning trust funds for Calvert Cliffs and Nine Mile Point are reported in "Nuclear decommissioning trust funds" in our Consolidated Balance Sheets. These amounts are legally restricted for funding the costs of nuclear decommissioning.

FIN 45

In November 2002, the FASB issued FIN 45, Guarantor's Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others. This Interpretation provides the disclosures to be made by a guarantor in interim and annual financial statements about obligations under certain guarantees. The Interpretation also clarifies that a guarantor is required to recognize, at the inception of a guarantee, a liability for the fair value of the obligation. The adoption of this standard did not have a material impact on our financial results.

EITF 03-11

In August 2003, the EITF reached a consensus on Issue 03-11, Reporting Gains and Losses on Derivative Instruments That Are Subject to FASB Statement No. 133, Accounting for Derivative Instruments and Hedging Activities, and Not Held for Trading Purposes, that reaffirmed existing revenue recognition requirements applicable to derivatives not designated as held for trading purposes. As a result, the implementation of EITF 03-11 did not affect our financial statements.

EITF 01-8

In May 2003, the EITF reached a consensus on Issue 01-8, Determining Whether an Arrangement Contains a Lease. EITF 01-8 provides guidance on how to determine when a contract contains a lease that is within the scope of SFAS No. 13, Accounting for Leases, and provides that any contract that conveys the right to control the use of property, plant, or equipment must be accounted for as a lease. EITF 01-8 applies to new contracts entered into after June 30, 2003. It also applies to any existing arrangements for which the contractual terms are modified or the underlying property, plant, or equipment undergoes a substantial physical change. The adoption of this standard did not have a material impact on our financial results.

EITF 02-3

On October 25, 2002, the EITF reached a consensus on Issue 02-3, Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities, that changed the accounting for certain energy contracts. EITF 02-3 prohibits the use of mark-to-market accounting for any energy-related contracts that are not derivatives. Any non-derivative contracts must be accounted for on the accrual basis and recorded in the income statement gross rather than net upon application of EITF 02-3. This change applied immediately to new contracts executed after October 25, 2002 and applied to existing non-derivative energy-related contracts beginning January 1, 2003.

        In the first quarter of 2003, we adopted EITF 02-3 and recognized a $430.0 million pre-tax, or $266.1 million after-tax, charge as a cumulative effect of change in accounting principle.

        The primary contracts that were subject to the requirements of EITF 02-3 were our full requirements load-serving contracts and unit-contingent power purchase contracts, which are not derivatives. The majority of these contracts are in Texas and New England and were entered into prior to our shift to accrual accounting earlier in 2002. We discuss our shift to accrual accounting in more detail in our 2002 Annual Report on Form 10-K.

        Additionally, we reviewed derivatives we use as supply sources and hedges of contracts that are subject to EITF 02-3. To the extent permitted by SFAS No. 133, we designated derivative contracts used to fulfill our load-serving contracts as either normal purchases or cash flow hedges under SFAS No. 133 effective January 1, 2003.

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        We summarize the impact on our Consolidated Balance Sheets of applying EITF 02-3 on January 1, 2003 as follows:

		Assets		Liabilities		Net
		(In millions)
Mark-to-market energy contracts
	Current	$	759.4	$	709.6	$	49.8
	Noncurrent		926.8		460.0		466.8
	Total		1,686.2		1,169.6		516.6
Other
	Current		85.7		56.8		28.9
	Noncurrent		24.2		2.5		21.7
	Total		109.9		59.3		50.6
Balance at December 31, 2002		$	1,796.1	$	1,228.9	$	567.2

Impact of EITF 02-3 Adoption:
Non-derivative net asset reversed as cumulative effect of change in accounting principle
	Mark-to-market energy contracts	$	(379.4	)
	Other		(50.6	)
Total non-derivative net asset reversed as cumulative effect of change in accounting principle			(430.0	)
Derivatives designated as hedges (net)			6.1
Derivatives designated as normal purchases and sales (net)			(64.3	)
Net mark-to-market derivatives remaining after adoption of EITF 02-3 on January 1, 2003		$	79.0

        On January 1, 2003, we recorded the $430.0 million non-derivative net asset removed from our Consolidated Balance Sheets as a cumulative effect of change in accounting principle, which reduced our 2003 net income by $266.1 million as previously discussed. The $430.0 million represents $379.4 million of non-derivative contracts recorded as "Mark-to-market energy assets and liabilities" and $50.6 million of "Other assets and liabilities" primarily from the re-designation of Texas contracts to accrual accounting in 2002, as discussed in more detail in our 2002 Annual Report on Form 10-K. The fair value of these contracts will be recognized in earnings as power is delivered.

        Additionally, on January 1, 2003, we reclassified the fair value of derivatives designated as hedges as "Risk management assets and liabilities" in the balance sheet and will account for these hedges in accordance with the provisions of SFAS No. 133. At that time, we also reclassified the fair value of derivatives designated as normal purchases and normal sales as "Other assets and liabilities" in the balance sheet and will account for these contracts on the accrual basis, with the fair value amortized into earnings over the lives of the underlying contracts.

        After the adoption of EITF 02-3 on January 1, 2003, net mark-to-market derivatives of $79.0 million, which consisted of $1,099.8 million in assets and $1,020.8 million in liabilities, remained in our Consolidated Balance Sheets. Applying EITF 02-3 does not affect our cash flows or our accounting for new load-serving contracts for which we used accrual accounting since early 2002.

Related Party Transactions—BGE

Income Statement

Under the Restructuring Order issued by the Maryland PSC in November 1999, BGE is providing standard offer service to customers at fixed rates over various time periods during the transition period from July 1, 2000 to June 30, 2006, for those customers that do not choose an alternate supplier. Constellation Power Source provided BGE with 100% of the energy and capacity required to meet its standard offer service obligations for the first three years of the transition period.

        In August 2001, BGE entered into contracts with our wholesale origination and risk management operation to supply 90% and Allegheny Energy Supply Company, LLC (Allegheny) to supply the remaining 10% of BGE's standard offer service for the final three years (July 1, 2003 to June 30, 2006) of the transition period. During the second quarter of 2003, after a competitive bid process, our wholesale origination and risk management operation assumed the obligation from Allegheny to serve the remaining 10% of BGE's standard offer service for the remainder of 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 September 30,				Nine Months Ended September 30,
	2003		2002		2003		2002
	(In millions)
Purchased energy	$	345.7	$	358.5	$	826.5	$	872.8

         In addition, BGE is charged by Constellation Energy for 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 approximately $12.1 million for the quarter ended September 30, 2003 compared to $7.5 million for the same period in 2002 and $33.4 million for the nine months ended September 30, 2003 compared to $22.4 million for the same period in 2002.

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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 $203.5 million at September 30, 2003 and $338.1 million at December 31, 2002 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, and BGE's charges to Constellation Energy and its nonregulated affiliates for certain services it provides them result in intercompany balances in BGE's Consolidated Balance Sheets.

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Item 2. Management's Discussion

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

Introduction

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 "utility business" 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 primarily occur in regional markets in which end use customer electricity rates have been deregulated and thereby separated from the cost of generation supply.

        BGE is a regulated electric and gas public transmission and 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:

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design, construct, and operate single-site heating, cooling, and cogeneration facilities for commercial and industrial customers throughout North America,

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provide home improvements, service gas and electric appliances, service heating, air conditioning, plumbing, electrical, and indoor air quality systems, and provide electric and natural gas retail marketing in central Maryland, and

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own and operate a district cooling system for commercial customers in the City of Baltimore, 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:

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factors which affect our businesses,

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our earnings and costs in the periods presented,

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changes in earnings and costs between periods,

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sources of earnings,

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impact of these factors on our overall financial condition,

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expected future expenditures for capital projects, and

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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 quarter and nine months ended September 30, 2003 and 2002. We analyze and explain the differences between periods in the specific line items of our Consolidated Statements of Income.

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:

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our reported amounts of assets and liabilities in our Consolidated Balance Sheets at the dates of the financial statements,

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our disclosure of contingent assets and liabilities at the dates of the financial statements, and

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our reported amounts of revenues and expenses in our Consolidated Statements of Income during the reporting periods.

        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.

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        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 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 2002 Annual Report on Form 10-K.

Revenue Recognition—Mark-to-Market Method of Accounting

Our merchant energy business engages in wholesale origination and risk management activities using contracts for energy, other energy-related commodities, and related derivative contracts. 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 in more detail in Note 1 of our 2002 Annual Report on Form 10-K.

        On October 25, 2002, the Emerging Issues Task Force (EITF) reached a consensus on 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 consensus affects the accounting for certain contracts and the application of the mark-to-market method of accounting. We describe our current application of the mark-to-market method of accounting based on the impact of the consensus on EITF 02-3 below. The main provisions of EITF 02-3 are as follows:

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The EITF rescinded Issue 98-10. As a result, this consensus prohibits mark-to-market accounting for energy-related contracts that do not meet the definition of a derivative under Statement of Financial Accounting Standards (SFAS) No. 133, Accounting for Derivative Instruments and Hedging Activities. Any contracts subject to the consensus must be accounted for on the accrual basis.

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The EITF indicated that an entity should not record unrealized gains or losses at the inception of derivative contracts unless the fair value of each contract in its entirety is evidenced by quoted market prices or other current market transactions for contracts with similar terms and counterparties.



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The EITF required gains and losses on derivative energy trading contracts (whether realized or unrealized) to be reported as revenue on a net basis in the income statement.

        We use mark-to-market accounting for contracts designated as trading and for other 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 energy contracts 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 fair value that are 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 risks 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.

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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.

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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 individual 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. Changes in market prices will 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 of our 2002 Annual Report on Form 10-K.

        EITF 02-3 affects the timing of recognizing earnings on new non-derivative transactions. In general, earnings on new non-derivative transactions subject to EITF 02-3 are no longer recognized at the inception of the transactions as they were under mark-to-market accounting because they are subject to accrual accounting and are recognized over the term of the transaction. As a result, while total earnings over the term of a transaction will be unchanged, we expect that our reported earnings for contracts subject to EITF 02-3 will generally match the cash flows from those contracts more closely. In addition, our reported earnings may be less volatile under accrual accounting than under mark-to-market accounting, which reflects changes in the fair value of contracts when they occur rather than when products are delivered and costs are incurred.

        Alternatively, other comprehensive income may have greater fluctuations because of a larger number of derivative contracts that we designate for hedge accounting under SFAS No. 133, but these fluctuations will not affect current period earnings or cash flows. Additionally, because we record revenues and costs on a gross basis under accrual accounting, our revenues and costs increased, but our earnings have not been affected by gross versus net reporting.

        The impact of EITF 02-3 will be affected by many factors, including:

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our ability to designate and qualify derivative contracts for normal purchase and sale accounting or hedge accounting under SFAS No. 133,

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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,

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our ability to enter into new mark-to-market derivative origination transactions, and

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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 or current market transactions.

        We discuss the impact of mark-to-market accounting on our financial results in the Results of Operations—Merchant Energy Business section on page 39.

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

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 would be as follows:

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a significant decrease in the market price of a long-lived asset,

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a significant adverse change in the manner an asset is being used or its physical condition,

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an adverse action by a regulator or in the business climate,

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an accumulation of costs significantly in excess of the amount originally expected for the construction or acquisition of an asset,

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a current-period loss combined with a history of losses or the projection of future losses, or

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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 requires 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 will 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 establish 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 to be disposed of by sale under SFAS No. 144, an impairment loss shall be recognized to the extent their carrying amount exceeds their fair value, including costs to sell.

        The estimation of fair value under SFAS No. 144, whether in conjunction with an asset to be held and used or with an asset to be disposed of by sale, also involves estimation and 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 and 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.

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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.

        Specifically, our nuclear decommissioning costs represent our largest asset retirement obligation. This obligation primarily results from the requirement to decommission and decontaminate the Calvert Cliffs and Nine Mile Point plants in connection with their future retirement. We revised our site-specific decommissioning cost estimates as part of the process 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 2003

Workforce Reduction Costs

During the quarter ended September 30, 2003, we recorded $0.7 million in expense, of which BGE recorded $0.2 million, associated with deferred payments to employees eligible for the 2001 Voluntary Special Early Retirement Program.

        During the nine months ended September 30, 2003, we recorded $2.1 million in expense, of which BGE recorded $0.7 million, associated with deferred payments to employees eligible for the 2001 Voluntary Special Early Retirement Program.

Sale of Non-Core Assets

During the nine months ended September 30, 2003, our other nonregulated businesses recognized $16.3 million of pre-tax, or $9.9 million after-tax, gains on the sales of non-core assets as follows:

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a $7.2 million pre-tax gain during the first quarter on the sale of an oil tanker to the U.S. Navy,

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a $5.3 million pre-tax gain during the first quarter 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,

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a $1.2 million pre-tax installment sale gain during the first quarter on a parcel of real estate,

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a $0.5 million pre-tax gain during the second quarter on the sale of financial investments as we continued to liquidate this operation,

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a $1.5 million pre-tax gain on the sale of real estate during the third quarter, and

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a $0.6 million pre-tax gain during the third quarter on the sale of financial investments as we continued to liquidate this operation.

Hurricane Isabel

In September 2003, Hurricane Isabel caused damage to the electric and gas distribution system of BGE. As a result, BGE incurred capitalized costs of $28.9 million and maintenance expenses of $36.4 million, or $22.0 million after tax to restore its distribution system. The maintenance expenses included $31.7 million pre-tax, or $19.2 million after-tax, of incremental expenses.

Generating Facility Commenced Operations

In April 2003, our High Desert Power Project in Victorville, CA, an 830 megawatt (MW) gas-fired combined cycle facility, commenced operations. The project has a long-term power sales agreement with the California Department of Water Resources (CDWR). The contract is a "tolling" structure, under which the CDWR pays a fixed amount of $12.1 million per month and provides CDWR the right, but not the obligation, to purchase power from the project at a price linked to the variable cost of production. During the term of the contract, which runs for seven years and nine months from the April 2003 commercial operation date of the plant, the project will provide energy exclusively to the CDWR.

        In June 2003, we exercised our option under the lease associated with the High Desert Power Project, paid off the lease, and acquired the assets from the lessor. At June 30, 2003 the assets and liabilities associated with the High Desert Power Project were included in our Consolidated Balance Sheets.

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Calvert Cliffs Extended Outage

In April 2003, our merchant energy business completed the Unit 2 steam generator replacement and refueling outage at Calvert Cliffs. This outage was completed in 66 days, 58 fewer days than a similar outage completed at Calvert Cliff's Unit 1 in June 2002.

Acquisitions

During 2003, we acquired the following energy contract portfolios:

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customer load-serving contracts representing 940 MW and corresponding supply portfolio from a subsidiary of CMS Energy Corp,

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certain competitive energy supply contracts with commercial and industrial customers, including 300 MW of electricity and certain natural gas customers, from Nicor Energy L.L.C. in Michigan, Illinois, and Indiana,

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a portfolio of competitive energy supply contracts with commercial and industrial customers, representing 125 MW, from Dynegy Inc., in Alberta, Canada, and

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the load-serving contract and related hedges from Allegheny Energy Supply Company, LLC (Allegheny) to provide 10% of the standard offer service to BGE.

        In June 2003, we exercised our option to purchase the project from the High Desert Power Trust and consolidated the assets and liabilities of the Trust at June 30, 2003.

        On October 22, 2003, we purchased Blackhawk Energy Services (Blackhawk) and Kaztex Energy Management (Kaztex). Blackhawk and Kaztex are providers of natural gas and electricity products, serving approximately 1,100 customers representing approximately 70 billion cubic feet of natural gas and 0.9 million megawatt hours of electricity throughout Illinois and Wisconsin. We acquired 100% ownership of both companies for $26.9 million.

Synthetic Fuel Facilities

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 change agent to create a significant chemical change. To qualify for the Section 29 tax credits, the synthetic fuel must meet three primary conditions:

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there must be a significant chemical change in the coal,

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the product must be sold to an unaffiliated entity, and

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the production facility must have been originally placed in service before July 1, 1998.

        As of September 30, 2003, we have recognized cumulative tax benefits associated with Section 29 credits of $69.7 million, of which $26.7 million was recognized during the nine months ended September 30, 2003 and $8.8 million was recognized during the quarter ended September 30, 2003.

        In June 2003, the Internal Revenue Service (IRS) issued Announcement 2003-46 which indicated they were suspending the issuance of private letter rulings regarding Section 29 tax credits until the IRS completed a review of the scientific validity of certain test procedures and results presented as evidence to prove a significant chemical change had occurred.

        Certain facilities in which we have an investment received private letter rulings from the IRS stating that the synthetic fuel produced undergoes a significant chemical change and thus qualifies for Section 29 credits. These private letter rulings were based, in part, on tests performed by independent scientific laboratories that were disclosed to the IRS as part of the ruling request process. The partnership that owns these facilities is currently under examination by the IRS. As part of their examination, the IRS engaged two third-party chemists to perform tests of the synthetic fuel. In October 2003, these chemists issued reports indicating that the synthetic fuel produced does not undergo a significant chemical change.

        There have been two favorable developments since the second quarter of 2003. First, an owner of a similar synthetic fuel facility that was under examination by the IRS on the chemical change issue recently disclosed that they were informed by the IRS National Office that the private letter ruling for their facility would not be revoked.

        Second, on October 29, 2003, the IRS issued Announcement 2003-70 indicating that it had completed the review started with Announcement 2003-46 and would resume issuing private letter rulings on significant chemical change. Announcement 2003-70 also specified that taxpayers would be required to maintain appropriate procedures and periodic reports from independent laboratories documenting significant chemical change and that these requirements would be extended to taxpayers already holding private letter rulings. We are still evaluating the impact of these requirements.

        As a result of these favorable developments and our belief that the chemical testing procedures and results presented by the independent scientific laboratories in the ruling requests were properly disclosed to the IRS, we believe that the private letter rulings held by the partnership in which we have an interest will not be revoked and that the IRS will favorably conclude their examination of the partnership.

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        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 the review by the IRS or its ultimate impact 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.

Pension Plan Assets

Our actual return on pension plan assets was approximately 13% for the nine months ended September 30, 2003. In addition, we contributed $111 million, or approximately $70 million after-tax, to our pension plans in 2003.

        However, due to declines in interest rate levels through October 31, 2003, we expect to record an after-tax charge to equity of approximately $30 million at December 31, 2003 as a result of increasing our additional minimum pension liability. This amount assumes interest rates remain unchanged through the end of 2003 and a return of zero percent on pension plan assets during the fourth quarter of 2003. The amount ultimately recorded will be determined by the actual return on pension plan assets, which depends on the performance of the financial markets during the remainder of 2003, and our discount rate assumption, which depends on year-end interest rates. As a result, the charge to equity could be materially different than our current estimate.

Dividend Increase

In January 2003, we announced an increase in our quarterly dividend to 26 cents per share on our common stock. This is equivalent to an annual rate of $1.04 per share. Previously, our quarterly dividend on our common stock was 24 cents per share, equivalent to an annual rate of 96 cents per share.

Strategy

We are pursuing a balanced strategy to generate power through our national fleet of plants and to distribute power through our regulated Maryland utility, BGE, and through our national competitive supply activities. Our generation fleet is strategically located in deregulated markets across the country and is diversified by fuel type, including nuclear, coal, gas, and renewable sources. We intend to remain diversified between owned generation, contractual generation, and regulated distribution and competitive supply.

        We expect this focus to provide growth opportunities along with more stable and predictable earnings, cash flows and dividends. The strategy for our merchant energy business is to be a leading competitive supplier of energy solutions for large customers in North America.

        The integration of electric generation assets with wholesale origination and risk management of energy and energy-related commodities allows our merchant energy business to manage energy price risk over geographic regions and over time. Our focus is on providing solutions to customers' energy needs, and our wholesale origination and risk management operation adds value to our 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 origination 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 origination and risk management operation with generation assets that have diversified geographic, fuel, and dispatch characteristics. We also expect to use a disciplined growth strategy through originating transactions with large customers and by acquiring and developing additional generating facilities when desirable to support our merchant energy business.

        Our merchant energy business will focus on long-term, high-value sales of energy, capacity, commodities, and related products to large customers, including distribution utilities, 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 region, the New York region, the Mid-Atlantic region, the Mid-West region, Texas, California, and certain areas in Canada.

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        The growth of BGE and our other retail energy services businesses is expected through focused and disciplined expansion primarily from new customers.

        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 business environment and regulatory changes, and to maintain a strong balance sheet and investment-grade credit quality.

        We also might consider one or more of the following strategies:

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the complete or partial separation of BGE's transmission function from its distribution function,

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mergers or acquisitions of utility or non-utility businesses or assets, and

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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 61.

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

General Industry

Over the past several years, the utility industry and energy markets experienced significant changes as a result of less liquid and more volatile wholesale markets, credit quality deterioration of various industry participants, and the slowing of the U.S. economy.

        The energy markets also were affected by other significant events, including expanded investigations by state and federal authorities into business practices of energy companies in the deregulated power and gas markets relating to "wash trading" to inflate revenues and volumes, and other trading practices designed to manipulate market prices. In addition, several merchant energy businesses significantly reduced their energy trading activities due to deteriorating credit quality.

        During 2003, the energy markets continued to be highly volatile with significant changes in natural gas and power prices as well as the continuation of reduced liquidity in the marketplace. During the third quarter of 2003, the average daily value-at-risk for our wholesale origination and risk management operation was $4.0 million using a 95% confidence level. We discuss the value-at-risk calculation in more detail in the Market Risk section of our 2002 Annual Report on Form 10-K.

        We continue to actively manage our wholesale credit portfolio to attempt to reduce the impact of a potential counterparty default. As of September 30, 2003, approximately 78% of our credit portfolio was rated at least investment grade by the major rating agencies, with 2% rated below investment grade and 20% not rated. Of the 20% not rated, 75% primarily represents governmental entities, municipalities, cooperatives, or other customers that we assess are equivalent to investment grade based on internal credit ratings.

        We continue to examine plans to achieve our strategies and to further strengthen our balance sheet and enhance our liquidity. We discuss our strategies in the Strategy section on page 33. We discuss our liquidity in the Financial Condition section on page 57.

Electric Competition

We are facing competition in the sale of electricity in wholesale power markets and to retail customers.

Maryland

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

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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.

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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.

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BGE provides a market rate standard offer service for those commercial and industrial customers who are no longer eligible for fixed price standard offer service.

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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.

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Eligible commercial and industrial customers have several service options that will fix electric energy rates through June 30, 2004 and competitive transition charges through June 30, 2006.

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BGE transferred, at book value, its generating assets and related liabilities to the merchant energy business.

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        Our wholesale origination and risk management operation provided BGE with 100% of the energy and capacity required to meet its standard offer service obligations through September 30, 2003. Our wholesale origination and risk management operation obtains the energy and capacity to supply BGE's standard offer service obligations from our merchant energy generating plants in the PJM Interconnection (PJM) region, supplemented with energy and capacity purchased from the wholesale market, as necessary.

        In August 2001, BGE entered into contracts with our wholesale origination and risk management operation to supply 90% and with Allegheny to supply the remaining 10% of BGE's standard offer service for the final three years (July 1, 2003 to June 30, 2006) of the transition period. During the second quarter of 2003, after a competitive bid process, our wholesale origination and risk management operation assumed the obligation to serve the remaining 10% of BGE's standard offer service for the remainder of the transition period. As a result, Allegheny is no longer obligated to serve 10% of BGE's standard offer service from July 1, 2003 through June 30, 2006.

        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. 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 a one, two or four year period beyond June 30, 2004, depending on customer load. The 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. The settlement contains 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, will begin in February 2004.

Other States

Several states, other than Maryland, have supported deregulation of the electric industry. The pace of deregulation in other states varies based on historical moves to competition and responses to recent market events. Certain states that were considering deregulation have slowed their plans or postponed consideration. In addition, other states are reconsidering deregulation.

        In response to regional market differences and to promote competitive markets, the 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 36.

        As a result of ongoing litigation before the FERC regarding sales into the spot markets of the California Independent System Operator (ISO) and Power Exchange (PX), we currently estimate that we may be required to pay refunds of between $2 million and $6 million for transactions that we entered into with these entities for the period between October 2000 and June 2001. However, we cannot determine the actual amount we could be required to pay because litigation is ongoing and new events could occur that could cause the actual amount, if any, to be materially different from our estimate.

Gas Competition

Currently, no regulation exists for the wholesale price of natural gas as a commodity, and the regulation of interstate transmission at the federal level has been reduced. All BGE gas customers have the option to purchase gas from other suppliers.

Regulation by the Maryland PSC

In addition to electric restructuring which was discussed earlier, 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. BGE's electric rates are unbundled to show separate components for delivery service, competitive transition charges, standard offer services (generation), transmission, universal service, and certain taxes. The rates for BGE's regulated gas business continue to consist of a "base rate" and a "fuel rate."

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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. BGE has both an electric base rate and a gas base rate. Higher electric base rates apply during the summer when the demand for electricity is higher. Gas base rates are not affected by seasonal changes.

        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.

        As a result of the deregulation of electric generation in Maryland, BGE's residential electric base rates are frozen until 2006. Electric delivery service rates are frozen until 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 Electric Competition—Maryland section on page 35.

Gas Fuel Rate

We charge our gas customers separately for the natural gas they purchase from us. The price we charge for the natural gas is based on a market-based rates incentive mechanism approved by the Maryland PSC. We discuss market-based rates and a recent proceeding with the Maryland PSC in more detail in the Gas Cost Adjustments section on page 52 and in Note 1 of our 2002 Annual Report on Form 10-K.

FERC Regulation

Regional Transmission Organizations and Standard Market 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. 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.

Cash Management

On October 23, 2003, FERC issued Order No. 634-A, concerning the regulation of cash management practices. The Order requires FERC-regulated entities to have their cash management agreements in writing, to detail how the cash pool is managed, and to submit the agreements and any subsequent revisions to the FERC. This Order did not impact our, or BGE's, financial results or liquidity. We discuss our cash management arrangement in the Notes to Consolidated Financial Statements on page 26.

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

36

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 52.

        We measure 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. 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 nine months ended September 30, 2003 and 2002, and the percentage change in the number of degree-days between these periods in the following table:

	Quarter Ended September 30,		Nine Months Ended September 30,
	2003	2002	2003	2002
Heating degree-days	57	59	3,482	2,675
Percent change from prior period	(3.4)%		30.2%
Cooling degree-days	580	667	733	965
Percent change from prior period	(13.0)%		(24.0)%

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,

•

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.

        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 beginning on page 22.

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Results of Operations for the Quarter and Nine Months Ended September 30, 2003 Compared with the Same Periods of 2002

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 54.

Overview

Results

		Quarter Ended September 30,						Nine Months Ended September 30,
		2003			2002			2003			2002
		(In millions, after-tax)
Merchant energy		$	171.6		$	130.3		$	225.9		$	213.7
Regulated electric			18.2			35.0			89.3			68.8
Regulated gas			2.4			(4.1	)		31.9			26.6
Other nonregulated			0.7			(10.5	)		9.6			151.5
Income Before Cumulative Effects of Changes in Accounting Principles			192.9			150.7			356.7			460.6
Cumulative Effects of Changes in Accounting Principles (see Notes)			—			—			(198.4	)		—
Net Income		$	192.9		$	150.7		$	158.3		$	460.6
Special Items Included in Operations (after-tax)
	Net gain on sales of investments and other assets	$	1.3		$	—		$	9.9		$	162.3
	Workforce reduction costs		(0.4	)		(7.5	)		(1.3	)		(31.2	)
	Impairment of investments in qualifying facilities and domestic power projects		—			(9.9	)		—			(9.9	)
	Costs associated with exit of BGE Home merchandise stores		—			(6.0	)		—			(6.0	)
	Impairment of real estate and international investments		—			(1.2	)		—			(1.2	)
Total Special Items		$	0.9		$	(24.6	)	$	8.6		$	114.0

Quarter Ended September 30, 2003

Our total net income for the quarter ended September 30, 2003 increased $42.2 million, or $0.23 per share, compared to the same period of 2002 mostly because of the following:

•

We had higher earnings at our wholesale origination and risk management operation due to new transactions entered into during 2003 and the favorable impacts of higher power prices and the shift from mark-to-market to accrual accounting under EITF 02-3.

•

We had higher earnings due to the High Desert Power Project that commenced operations in April 2003.

•

We had higher earnings from NewEnergy, which we acquired late in the third quarter of 2002, and Alliance, which we acquired late in the fourth quarter of 2002.

•

We recognized impairments of certain investments in qualifying facilities, real estate and international investments in 2002 that had a negative impact in that period.

•

We had higher workforce reduction costs in 2002 that had a negative impact in that period.

•

We had costs associated with our exit of BGE Home merchandise stores in 2002 that had a negative impact in that period.

        These increases were partially offset by the following:

•

We had lower earnings from our regulated electric business mostly because of higher operations and maintenance expenses due to distribution service restoration efforts associated with Hurricane Isabel.

•

We had higher compensation and other costs in our merchant energy business.

•

We had lower earnings from Nine Mile Point primarily due to reduced availability of the plant including the forced outage related to the Northeast blackout in August 2003.

•

We had higher fixed charges primarily due to a higher level of outstanding debt and lower capitalized interest because of the new generating facilities that commenced operations mid-2002.

Nine Months Ended September 30, 2003

Our total net income for the nine months ended September 30, 2003 decreased $302.3 million, or $1.86 per share, compared to the same period of 2002 mostly because of the following:

•

We recorded a $266.1 million after-tax, or $1.61 per share, loss for the cumulative effect of adopting EITF 02-3. 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. We discuss these cumulative effect items in more detail in the Notes to Consolidated Financial Statements on page 23.

•

We recognized a $163.3 million after-tax, or $1.00 per share, gain on the sale of our investment in Orion in 2002 that had a positive impact in that period.

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•

Our results reflected the impact of the shift to accrual accounting under EITF 02-3. Specifically, the absence of 2002 mark-to-market gains for portfolios accounted for on an accrual basis in 2003 and the timing difference in the recognition of earnings for certain economic hedges, which we discuss further on page 44, were only partially offset by the 2003 recognition of accrual earnings on transactions entered into in prior periods.

•

We had higher compensation and other costs in our merchant energy business.

•

Our regulated electric business incurred distribution service restoration expenses associated with Hurricane Isabel.

•

We had higher fixed charges due to lower capitalized interest and a higher level of debt outstanding as a result of refinancing our High Desert Power Project operating lease.

        These decreases were partially offset by the following:

•

We had higher earnings from our wholesale competitive supply activities including higher origination in 2003 and we benefited from the favorable movement of power prices.

•

We had higher earnings from favorable generating plant operational performance. Specifically, our High Desert Power Project commenced operations in April 2003 and our Calvert Cliffs facility completed a steam generator replacement in April 2003, 58 fewer days than a similar outage that was completed in June 2002. These favorable items were partially offset by lower earnings from Nine Mile Point primarily due to reduced availability of the plant.

•

We realized cost reductions due to productivity initiatives including our corporate-wide workforce reduction programs.

•

We had higher earnings from the addition of NewEnergy and Alliance.

•

We had higher earnings from our regulated electric business, excluding the impacts of Hurricane Isabel and changes in fixed charges.

•

We had higher workforce reduction costs in 2002 that had a negative impact in that period.

•

We recognized impairments of certain investments in qualifying facilities, real estate and international investments in 2002 that had a negative impact in that period.

•

We had costs associated with our exit of BGE Home merchandise stores in 2002 that had a negative impact in that period.

•

Our other nonregulated businesses recognized a gain of $9.9 million after-tax, or $0.06 per share, in 2003 related to non-core asset sales.

        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. As discussed in the Business Environment—Electric Competition section on page 34, in connection with the July 1, 2000 implementation of customer choice in Maryland, BGE's generating assets became part of our nonregulated merchant energy business, and our wholesale origination and risk management operation began selling to BGE the energy and capacity required to meet its standard offer service obligations for the first three years (July 1, 2000 to June 30, 2003) of the transition period.

        In August 2001, BGE entered into a contract with our wholesale origination and risk management operation to provide 90% of the energy and capacity required for BGE to meet its standard offer service requirements for the final three years (July 1, 2003 to June 30, 2006) of the transition period. Our merchant energy business revenues also include 90% of the competitive transition charges (CTC revenues) BGE collects from its customers and the portion of BGE's revenues providing for nuclear decommissioning costs.

        During the second quarter of 2003, BGE consented to the assignment of the Allegheny contract and therefore Allegheny is no longer obligated to serve the remaining 10% of BGE's standard offer service for the final three years of the transition period. Our wholesale origination and risk management operation assumed the obligation to serve the remaining 10% of BGE's standard offer service for the remainder of the transition period. We discuss our relationship with Allegheny prior to the termination in more detail in the Business Environment—Electric Competition section on page 35.

        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 28 and in Note 1 of our 2002 Annual Report on Form 10-K. We summarize our policies as follows:

•

We record revenues as they are earned and fuel and purchased energy expenses as they are incurred for contracts and activities subject to accrual accounting, including load-serving activities, as discussed below.

•

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.

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•

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 43.

        In the first quarter of 2003, we adopted EITF 02-3 that required certain contracts to be accounted for on the accrual basis and recorded gross rather than net upon application of EITF 02-3. The primary contracts affected were our full requirements load-serving contracts and unit-contingent power purchase contracts. The majority of these contracts were in Texas and New England and were entered into prior to our shift to accrual accounting earlier in 2002, as discussed in our 2002 Annual Report on Form 10-K. We discuss the adoption of EITF 02-3 in more detail in the Notes to Consolidated Financial Statements on page 24.

        After the re-designation of existing contracts to non-trading, we record revenues and expenses on a gross basis, but this does not have a material impact on earnings because the resulting increase in revenues is accompanied by a similar increase in fuel and purchased energy expenses.

        EITF 02-3 affects the timing of recognizing earnings on new non-derivative transactions. In general, earnings on new non-derivative transactions subject to EITF 02-3 are no longer recognized at the inception of the transactions as they were under mark-to-market accounting because they are subject to accrual accounting and are recognized over the term of the transaction.

        Additionally, we expect lower earnings volatility for this portion of our business because unrealized changes in the fair value of load-serving contracts will no longer be recorded as revenue at the time of the change as they were under mark-to-market accounting.

Results

		Quarter Ended September 30,						Nine Months Ended September 30,
		2003			2002			2003			2002
		(In millions)
Revenues		$	2,177.3		$	853.0		$	5,681.4		$	1,949.6
Fuel and purchased energy expenses			(1,533.6	)		(335.2	)		(4,215.5	)		(716.5	)
Operations and maintenance expenses			(223.7	)		(175.8	)		(721.3	)		(571.3	)
Workforce reduction costs			(0.5	)		(9.1	)		(1.3	)		(19.4	)
Impairment losses and other costs			—			(14.4	)		—			(14.4	)
Depreciation and amortization			(64.7	)		(66.4	)		(172.2	)		(180.3	)
Accretion of asset retirement obligations			(10.7	)		—			(32.0	)		—
Taxes other than income taxes			(28.1	)		(22.3	)		(81.4	)		(63.3	)
Loss on sale of investments and other assets			—			—			—			(6.0	)
Income from Operations		$	316.0		$	229.8		$	457.7		$	378.4
Income Before Cumulative Effects of Changes in Accounting Principles (after-tax)		$	171.6		$	130.3		$	225.9		$	213.7
Cumulative Effects of Changes in Accounting Principles (after-tax)			—			—			(198.4	)		—
Net Income		$	171.6		$	130.3		$	27.5		$	213.7
Special Items Included in Operations (after-tax)
	Loss on sale of investments and other assets	$	—		$	—		$	—		$	(3.9	)
	Impairment of investments in qualifying facilities and domestic power projects		—			(9.9	)		—			(9.9	)
	Workforce reduction costs		(0.3	)		(5.4	)		(0.8	)		(11.6	)
Total Special Items		$	(0.3	)	$	(15.3	)	$	(0.8	)	$	(25.4	)

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.

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Revenues and Fuel and Purchased Energy Expenses

Our wholesale origination and risk management operation manages the revenues we realize from the sale of energy to our customers and our costs of procuring fossil fuel and energy. 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. We discuss non-fuel direct costs, such as ancillary services, transmission costs, financing, and legal costs in conjunction with other operations and maintenance expenses in the Operations and Maintenance Expenses section on page 48.

        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.

•

PJM Platform—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.

•

Plants with Power Purchase Agreements—our generating facilities with long-term power purchase agreements, including Nine Mile Point, Oleander, University Park, and our High Desert Power Project.

•

Competitive Supply—our wholesale business that provides load-serving activities to distribution utilities (primarily in Texas and New England), other wholesale origination and risk management services, and electric and gas energy services to commercial and industrial customers. With the acquisition of the load-serving customers from CMS Energy Corp., as previously discussed on page 32, the results of our gas-fired facilities in the Mid-West region, which were previously part of our "Other" category, became part of our competitive supply activities beginning in the second quarter of 2003.

•

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 September 30,										Nine Months Ended September 30,
		2003					2002					2003					2002
		(Dollar amounts in millions)
Revenues:
	PJM Platform	$	530.2				$	463.9				$	1,371.2				$	1,073.9
	Plants with Power Purchase Agreements		206.6					179.6					472.6					379.5
	Competitive Supply		1,419.2					188.6					3,798.7					450.7
	Other		21.3					20.9					38.9					45.5
	Total	$	2,177.3				$	853.0				$	5,681.4				$	1,949.6
Fuel and purchased energy expenses:
	PJM Platform	$	(212.3	)			$	(162.2	)			$	(605.8	)			$	(411.1	)
	Plants with Power Purchase Agreements		(14.8	)				(13.0	)				(38.6	)				(31.3	)
	Competitive Supply		(1,306.5	)				(160.0	)				(3,571.1	)				(274.1	)
	Other		—					—					—					—
	Total	$	(1,533.6	)			$	(335.2	)			$	(4,215.5	)			$	(716.5	)
Revenues less fuel and purchased energy expenses:					% of Total					% of Total					% of Total					% of Total
	PJM Platform	$	317.9		49	%	$	301.7		58	%	$	765.4		52	%	$	662.8		54	%
	Plants with Power Purchase Agreements		191.8		30			166.6		32			434.0		30			348.2		28
	Competitive Supply		112.7		18			28.6		6			227.6		16			176.6		14
	Other		21.3		3			20.9		4			38.9		2			45.5		4
	Total	$	643.7		100	%	$	517.8		100	%	$	1,465.9		100	%	$	1,233.1		100	%

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

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PJM Platform

	Quarter Ended September 30,						Nine Months Ended September 30,
	2003			2002			2003			2002
	(In millions)
Revenues	$	530.2		$	463.9		$	1,371.2		$	1,073.9
Fuel and purchased energy expenses		(212.3	)		(162.2	)		(605.8	)		(411.1	)
Revenues less fuel and purchased energy expenses	$	317.9		$	301.7		$	765.4		$	662.8

Revenues

BGE Standard Offer Service

The majority of PJM Platform revenues arise from supplying BGE's standard offer service requirements. Revenues from supplying BGE's standard offer service requirements, including CTC and decommissioning revenues, decreased $14.0 million during the quarter ended September 30, 2003 compared to the same period of 2002 mostly due to milder summer weather and power outages resulting from Hurricane Isabel.

        The revenues from supplying the BGE standard offer service requirements, including CTC and decommissioning revenues, decreased $48.9 million during the nine months ended September 30, 2003 compared to the same period of 2002 mostly due to:

•

approximately 1,200 megawatts of large commercial and industrial customers leaving BGE's standard offer service in the second quarter of 2002 and electing other electric generation suppliers, and

•

milder weather 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 Electric Competition—Maryland section on page 34.

        Approximately one-third of the load for large commercial and industrial customers that left BGE's standard offer service elected BGE Home, a subsidiary of Constellation Energy, as their electric generation supplier. Our merchant energy business continues to provide the energy to BGE Home to meet the requirements of these customers under market-based rates.

        Revenues from BGE Home decreased $3.2 million for the quarter ended September 30, 2003. Revenues from BGE Home increased $33.1 million for the nine months ended September 30, 2003 compared to the same periods of 2002. BGE Home is included in our other nonregulated businesses.

        Beginning in the second quarter of 2003, as contracts for large commercial and industrial customers being served by BGE Home expire, the renewal of any customer will be with NewEnergy, our subsidiary which provides electric and gas energy products to commercial and industrial customers, and which is included in our Competitive Supply category.

Other PJM Revenues

Other merchant energy revenues in the PJM region increased $83.5 million for the quarter ended September 30, 2003 compared to the same period in 2002 mostly due to the following:

•

higher sales of energy and related services from our owned generation in excess of that used to serve BGE's standard offer service, and

•

increased sales to BGE Home related to their gas programs.

        Other merchant energy revenues in the PJM region increased $313.1 million for the nine months ended September 30, 2003 compared to the same period of 2002. The increase is primarily due to the following:

•

higher sales of energy and related services from our owned generation in excess of that used to serve BGE's standard offer service,

•

a gain on the assumption of the Allegheny load-serving contract for the remaining 10% of the BGE standard offer service load, and

•

increased sales to BGE Home related to their gas programs.

Fuel and Purchased Energy Expenses

Our merchant energy business had higher fuel and purchased energy expenses in the PJM region for the quarter and nine months ended September 30, 2003 compared to the same periods of 2002 primarily due to the following:

•

higher wholesale market prices for purchased power to serve BGE's standard offer service,

•

higher generation costs related to the increased sales of energy and related services from our owned generation in excess of that used to serve BGE's standard offer service, and

•

increased costs related to sales to BGE Home for their gas programs.

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Plants with Power Purchase Agreements

	Quarter Ended September 30,						Nine Months Ended September 30,
	2003			2002			2003			2002
	(In millions)
Revenues	$	206.6		$	179.6		$	472.6		$	379.5
Fuel and purchased energy expenses		(14.8	)		(13.0	)		(38.6	)		(31.3	)
Revenues less fuel and purchased energy expenses	$	191.8		$	166.6		$	434.0		$	348.2

The increase in revenues during the quarter ended September 30, 2003 compared to the same period of 2002 was primarily due to revenues of $41.7 million from the High Desert Power Project that commenced operations in the second quarter of 2003, partially offset by lower revenues from Nine Mile Point due to reduced availability of the plant including the forced outage related to the Northeast blackout in August 2003.

        The increase in revenues during the nine months ended September 30, 2003 compared to the same period of 2002 was primarily due to the following:

•

revenues of $74.9 million from the High Desert Power Project, and

•

higher revenues of $19.9 million from the Oleander generating facility which commenced operations late in the second quarter of 2002.

        These increases were offset in part by a decrease in Nine Mile Point revenues due to reduced availability of the plant including the forced outage related to the Northeast blackout in August 2003.

        Our plants with power purchase agreements had higher fuel and purchased energy expenses for the quarter and nine months ended September 30, 2003 compared to the same periods of 2002 primarily due to the operation of the High Desert and Oleander generating facilities.

Competitive Supply

	Quarter Ended September 30,						Nine Months Ended September 30,
	2003			2002			2003			2002
	(In millions)
Accrual revenues	$	1,410.5		$	180.8		$	3,787.2		$	288.8
Mark-to-market revenues		8.7			7.8			11.5			161.9
Fuel and purchased energy expenses		(1,306.5	)		(160.0	)		(3,571.1	)		(274.1	)
Revenues less fuel and purchased energy expenses	$	112.7		$	28.6		$	227.6		$	176.6

We analyze our accrual and mark-to-market competitive supply activities separately below.

Accrual Revenues and Fuel and Purchased Energy Expenses

Our accrual revenues and fuel and purchased energy expenses increased for the quarter and nine months ended September 30, 2003 compared to the same periods of 2002 mostly because of the re-designation of our load-serving activities to accrual, including the adoption of EITF 02-3, combined with increased wholesale accrual origination activities, primarily in Texas and New England, and the acquisitions of NewEnergy and Alliance. We provide the changes in revenues and fuel and purchased energy expenses in 2003 compared to 2002 in the following table.

	Quarter Ended September 30, 2003 vs. 2002				Nine Months Ended September 30, 2003 vs. 2002
	Increases in revenues		Increases in fuel and purchased energy expenses		Increases in revenues		Increases in fuel and purchased energy expenses
	(In millions)
Wholesale accrual activities	$	594.1	$	551.2	$	1,786.1	$	1,663.4
Acquisitions		635.6		595.3		1,712.3		1,633.6
Total increase	$	1,229.7	$	1,146.5	$	3,498.4	$	3,297.0

        We discuss the implications of EITF 02-3 in more detail in the Notes to Consolidated Financial Statements on page 24.

Mark-to-Market Revenues

Mark-to-market revenues include net gains and losses from wholesale 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 28. We also discuss the implications of EITF 02-3 on the mark-to-market method of accounting in the Notes to Consolidated Financial Statements on page 24.

        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 in our 2002 Annual Report on Form 10-K. 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.

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        Mark-to-market revenues were as follows:

			Quarter Ended September 30,						Nine Months Ended September 30,
			2003			2002			2003			2002
			(In millions)
Unrealized revenues
	Origination transactions		$	25.0		$	17.6		$	50.2		$	112.5
	Risk management
		Unrealized changes in fair value		(16.3	)		(16.3	)		(38.7	)		38.6
		Changes in valuation techniques		—			6.5			—			10.8
		Reclassification of settled contracts to realized		(10.0	)		(21.9	)		(80.1	)		(29.1	)
	Total risk management			(26.3	)		(31.7	)		(118.8	)		20.3
Total unrealized revenues				(1.3	)		(14.1	)		(68.6	)		132.8
Realized revenues				10.0			21.9			80.1			29.1
Total mark-to-market revenues			$	8.7		$	7.8		$	11.5		$	161.9

        Revenues from origination transactions represent the initial unrealized fair value of new wholesale energy transactions (including restructurings) at the time of contract execution to the extent permitted by applicable accounting rules. Risk management revenues represent both realized and unrealized gains and losses from changes in the value of our entire portfolio. 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 were and continue to be affected by a decrease in the portion of our activities that is subject to mark-to-market accounting. As discussed in our 2002 Annual Report on Form 10-K, we re-designated our Texas load-serving business as accrual during 2002, and we began to account for new non-derivative origination transactions on the accrual basis rather than under mark-to-market accounting. Beginning January 1, 2003, under EITF 02-3, we no longer record existing non-derivative contracts at fair value.

        Mark-to-market revenues were about the same for the quarter ended September 30, 2003 compared to the same period in 2002.

        Mark-to-market revenues decreased $150.4 million during the nine months ended September 30, 2003 compared to the same period of 2002 primarily due to net losses from risk management activities compared to net gains in the prior year and lower origination subject to mark-to-market accounting with the implementation of EITF 02-3. The decrease in risk management revenues is primarily due to mark-to-market revenue associated with the restructuring of our High Desert contract with the CDWR that had a positive impact in 2002, unfavorable changes in regional power prices, price volatility, and the impact of mark-to-market losses on economic hedges that did not qualify for hedge accounting treatment as discussed in more detail below.

        Prior to EITF 02-3, we were required to record all New England load serving positions entered into before the second quarter of 2002 and our hedges against those positions on a mark-to-market basis. With the implementation of EITF 02-3 in the first quarter of 2003, all of the load-serving contracts were converted to accrual accounting. However, several economically effective hedges on these positions did not qualify for accrual hedge accounting treatment under SFAS No. 133 and remained in the mark-to-market portfolio.

        In the nine months ended September 30, 2003, increasing forward prices shifted value between accrual load-serving positions and associated mark-to-market hedges producing a timing difference in the recognition of earnings on related transactions. As a result, we recorded a $5.4 million pre-tax loss on the mark-to-market hedges during the third quarter of 2003 and a $45.1 million pre-tax loss during the nine months ended September 30, 2003. We have realized and will continue to realize gains on the accrual load-serving positions in cash by the end of 2004, offset by cash losses on the hedges, which we were required to mark-to-market.

Mark-to-Market Energy Assets and Liabilities

Our mark-to-market energy assets and liabilities are comprised of derivative contracts, and in 2002, prior to the implementation of EITF 02-3, were comprised of a combination of derivative and non-derivative (physical) contracts. The non-derivative contracts primarily related to load-serving activities originated prior to the shift to accrual accounting in 2002. While some of our mark-to-market 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 other pricing sources and modeling techniques to determine expected future market prices, contract quantities, or both. We discuss our modeling techniques later in this section.

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        Mark-to-market energy assets and liabilities consisted of the following:

	September 30, 2003		December 31, 2002
	(In millions)
Current Assets	$	506.9	$	759.4
Noncurrent Assets		342.5		926.8
Total Assets		849.4		1,686.2
Current Liabilities		530.1		709.6
Noncurrent Liabilities		254.8		460.0
Total Liabilities		784.9		1,169.6
Net mark-to-market energy asset	$	64.5	$	516.6

        The following are the primary sources of the change in net mark-to-market energy asset/liability during 2003:

Change in Net Mark-to-Market Energy Asset (Liability)

		Quarter Ended September 30, 2003		Nine Months Ended September 30, 2003
		(In millions)
Fair value beginning of period		$  (4.0	)	$ 516.6
Changes in fair value recorded as revenues
	Origination transactions	$ 25.0		$ 50.2
	Unrealized changes in fair value	(16.3)		(38.7)
	Changes in valuation techniques	—		—
	Reclassification of settled contracts to realized	(10.0)		(80.1)
Total changes in fair value recorded as revenues		(1.3	)	(68.6	)
Cumulative effect impact of EITF 02-3		—		(379.4	)
Contracts designated as normal purchases/sales and hedges upon implementation of EITF 02-3		—		(58.2	)
Changes in value of exchange-listed futures and options		11.5		2.4
Net change in premiums on options		59.9		45.0
Other changes in fair value		(1.6	)	6.7
Fair value at September 30, 2003		$64.5		$64.5

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

•

Origination transactions represent the initial unrealized fair value at the time these contracts are executed to the extent permitted by accounting rules, including EITF 02-3.

•

Unrealized changes in fair value represent the unrealized changes in commodity prices, the volatility of options on commodities, the time value of options, and other valuation adjustments.

•

Changes in valuation techniques represent improvements in estimation techniques, including modeling and other statistical enhancements used to value our portfolio to reflect more accurately the economic value of our contracts.

•

Reclassification of settled contracts to realized represents the portion of previously unrealized amounts settled during the period and recorded as realized revenues.

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

•

The cumulative effect impact of EITF 02-3 represents the non-derivative portion of the net asset that was reclassified to accrual accounting effective January 1, 2003 as required by EITF 02-3.

•

Contracts designated as normal purchases/sales and hedges upon adoption of EITF 02-3 represents the portion of the net asset reclassified to "Other assets or liabilities" under the normal purchases/normal sales provisions of SFAS No. 133 or "Risk management assets or liabilities" under the cash-flow hedge provisions of SFAS No. 133 in connection with the implementation of EITF 02-3 effective January 1, 2003.

•

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 or a decrease to the net mark-to-market liability and premiums on options sold as a decrease in the net mark-to-market energy asset or an increase to the net mark-to-market liability.

45

        The settlement terms of the net mark-to-market energy asset or liability and sources of fair value as of September 30, 2003 are as follows:

	Settlement Term
	Fair Value
			2003			2004			2005			2006			2007			2008		Thereafter
	(In millions)
Prices provided by external sources (1)	$	(21.5	)	$	20.2		$	18.0		$	74.9		$	(0.6	)	$	—	$	—	$	91.0
Prices based on models		(1.9	)		(0.3	)		(24.7	)		(63.7	)		24.0			14.5		25.6		(26.5	)
Total net mark-to-market energy (liability) asset	$	(23.4	)	$	19.9		$	(6.7	)	$	11.2		$	23.4		$	14.5	$	25.6	$	64.5

(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 below.

        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 2005, but up to 2007, depending upon the region,

•

options for the purchase and sale of electricity during peak hours for delivery terms through 2004, depending upon the region,

•

forward purchases and sales of electric capacity for delivery terms through 2004,

•

forward purchases and sales of natural gas, coal and oil for delivery terms through 2005, and

•

options for the purchase and sale of natural gas, coal and oil for delivery terms through 2005.

        The remainder of the net mark-to-market energy asset or 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 origination 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

46

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 origination 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 on the previous page represent expected future cash flows based on the level of forward prices and volatility factors as of September 30, 2003 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 September 30,				Nine Months Ended September 30,
	2003		2002		2003		2002
	(In millions)
Revenues	$	21.3	$	20.9	$	38.9	$	45.5

Investments in Qualifying Facilities and Domestic Power Projects

Our merchant energy business holds up to a 50% ownership interest in 28 operating domestic energy projects that consist of electric generation, fuel processing, or fuel handling facilities. Of these 28 projects, 20 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.

        Revenues from our investments in qualifying facilities and domestic power projects were about the same for the quarter ended September 30, 2003 compared to the same period in 2002.

        The decrease in revenues during the nine months ended September 30, 2003 compared to the same period of 2002 was primarily due to lower revenues from our California projects because we reversed certain credit reserves that totaled $9.1 million during the first quarter of 2002, as we began receiving payments from the California utilities, which had a positive impact in 2002.

        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 61. 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.

        We have an investment in a partnership that owns a geothermal project with a book value of $104.8 million at September 30, 2003. The project currently is producing at a level such that we expect the project to generate sufficient cash flows over its life to enable us to recover our equity interest in the project. However, should the project not continue to produce a sufficient geothermal resource, or should future well drilling at this project prove to be unsuccessful or become uneconomic, our investment could become impaired under the provisions of APB No. 18 and any losses recognized could be material.

        Currently, we are re-evaluating our strategy regarding our investment in this project, which may include soliciting bids to determine the level of interest in the project. If we determine that the offers to purchase the project would provide more attractive cash flows than under our current hold and use strategy, we may decide to dispose of the project. If we determine that disposal is more likely than not to occur, we would evaluate our investment for impairment and any adjustment could be material.

        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,

47

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 recognize losses that could be material.

Operations and Maintenance Expenses

Our merchant energy business operations and maintenance expenses increased $47.9 million in the third quarter of 2003 compared to the same period of 2002 mostly due to the following:

•

an increase of $20.7 million due to the acquisitions of NewEnergy and Alliance,

•

an increase in costs related to our wholesale origination and risk management operation as a result of the growth of this operation,

•

costs of $5.9 million related to our High Desert Power Project that commenced operations in the second quarter of 2003,

•

an increase of $5.0 million at Nine Mile Point, and

•

higher benefit and other inflationary cost increases.

        These increases were offset in part by cost reductions due to productivity initiatives including our corporate-wide workforce reduction programs.

        Our merchant energy business operations and maintenance expenses increased $150.0 million for the nine months ended September 30, 2003 compared to the same period of 2002 mostly due to the following:

•

an increase of $66.4 million due to the acquisitions of NewEnergy and Alliance,

•

an increase of $26.0 million at Nine Mile Point including higher costs associated with the refueling outage of Unit 1 in 2003 compared to the 2002 refueling outage of Unit 2. Since we own 100% of Unit 1, we incur all outage costs compared to 82% of costs for Unit 2,

•

an increase in costs related to our wholesale origination and risk management operation as a result of the growth of this operation, and

•

costs of $10.6 million related to our High Desert Power Project that commenced operations in the second quarter of 2003,

•

higher benefit and other inflationary cost increases.

        These increases were offset in part by cost reductions due to productivity initiatives including our corporate-wide workforce reduction programs.

Workforce Reduction Costs

Our merchant energy business recognized $0.5 million in the third quarter of 2003 and $9.1 million in the same period of 2002 for expenses associated with our workforce reduction efforts. During the nine months ended September 30, 2003 our merchant energy business recognized expenses associated with our workforce reduction efforts of $1.3 million compared to $19.4 million for the same period in 2002.

        We discuss these workforce reduction costs in more detail in the Notes to Consolidated Financial Statements on page 12.

Depreciation and Amortization Expense

Merchant energy depreciation and amortization expense decreased $1.7 million in the third quarter of 2003 compared to the same period of 2002 and $8.1 million for the nine months ended September 30, 2003 compared to the same period of 2002 mostly because of the adoption of SFAS No. 143.

        Under SFAS No. 143, a portion of the decommissioning amortization is included as "Accretion of asset retirement obligations" expense beginning in 2003 as discussed below. In addition, beginning in 2003 we no longer include the expected net future costs of removal as a component of depreciation expense. These decreases were partially offset by higher depreciation expense related to new generating facilities that commenced operations in mid-2002 and the High Desert Power Project that commenced operations in 2003.

Accretion of Asset Retirement Obligations

On January 1, 2003, we adopted SFAS No. 143 that requires the accretion of the asset retirement obligation liability due to the passage of time until the liability is settled. Accordingly, we recognized $10.7 million of accretion expense in the third quarter of 2003 and $32.0 million of accretion expense for the nine months ended September 30, 2003. We discuss SFAS No. 143 in the Notes to Consolidated Financial Statements on page 23.

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Taxes Other Than Income Taxes

Merchant energy taxes other than income taxes increased $5.8 million in the third quarter of 2003 compared to the same period of 2002 and $18.1 million for the nine months ended September 30, 2003 compared to the same period of 2002 mostly because of gross receipt taxes associated with NewEnergy and property taxes on new generating facilities.

Regulated Electric Business

As discussed in the Electric Competition—Maryland section on page 34, our regulated electric business was significantly impacted by the July 1, 2000 implementation of customer choice. These changes include BGE's generating assets and related liabilities becoming part of our nonregulated merchant energy business on that date.

        BGE's electric rates are frozen in total during the transition period and are unbundled to show separate components for delivery service, transition charges, standard offer services (generation), transmission, universal service, and certain taxes. 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 September 30,						Nine Months Ended September 30,
		2003			2002			2003			2002
		(In millions)
Revenues		$	582.3		$	596.3		$	1,505.6		$	1,537.1
Electricity purchased for resale expenses			(345.7	)		(358.6	)		(826.5	)		(872.9	)
Operations and maintenance expenses			(103.8	)		(67.8	)		(219.5	)		(188.1	)
Workforce reduction costs			(0.2	)		(3.1	)		(0.6	)		(31.9	)
Depreciation and amortization			(45.8	)		(43.6	)		(134.5	)		(131.4	)
Taxes other than income taxes			(35.1	)		(35.5	)		(104.1	)		(104.4	)
Income from Operations		$	51.7		$	87.7		$	220.4		$	208.4
Net Income		$	18.2		$	35.0		$	89.3		$	68.8
Special Items Included in Operations (after-tax)
	Workforce reduction costs	$	(0.1	)	$	(1.9	)	$	(0.4	)	$	(19.3	)

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

        Net income from the regulated electric business decreased during the quarter ended September 30, 2003 compared to the same period of 2002 mostly because of distribution service restoration expenses and a decrease in revenues resulting from lower distribution sales volumes primarily due to cooler summer weather. The total distribution service restoration expenses related to Hurricane Isabel were $21.8 million after-tax, which included $19.2 million of incremental expenses. These unfavorable results were partially offset by lower interest expense.

        Net income from the regulated electric business increased during the nine months ended September 30, 2003 compared to the same period of 2002 mostly because of the following:

•

lower workforce reduction costs of $18.9 million after-tax related to our corporate-wide workforce reduction programs,

•

lower interest expense,

•

increased distribution sales volumes due to colder winter weather, and

•

cost reductions in 2003 resulting from our corporate-wide workforce reduction programs and other productivity initiatives.

        These favorable results were partially offset by distribution service restoration expenses related to Hurricane Isabel as previously discussed.

Electric Revenues

The changes in electric revenues in 2003 compared to 2002 were caused by:

	Quarter Ended September 30, 2003 vs. 2002			Nine Months Ended September 30, 2003 vs. 2002
	(In millions)
Distribution sales volumes	$	(4.6	)	$	6.3
Standard offer service		(9.4	)		(46.3	)
Total change in electric revenues from electric system sales		(14.0	)		(40.0	)
Other		—			8.5
Total change in electric revenues	$	(14.0	)	$	(31.5	)

49

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 2003 compared to 2002 were:

	Quarter Ended September 30, 2003 vs. 2002		Nine Months Ended September 30, 2003 vs. 2002
Residential	(7.9	)%	2.4	%
Commercial	4.1		3.0
Industrial	(7.0	)	(4.8	)

        During the third quarter of 2003, we distributed less electricity to residential customers compared to the same period of 2002 mostly due to cooler summer weather, decreased usage per customer, and power outages resulting from Hurricane Isabel. We distributed more electricity to commercial customers mostly due to increased usage per customer. We distributed less electricity to industrial customers mostly because of lower usage by industrial customers.

        During the nine months ended September 30, 2003, we distributed more electricity to residential customers compared to the same period of 2002 mostly due to increased usage per customer, colder winter weather, and an increased number of customers, partially offset by cooler summer weather. We distributed more electricity to commercial customers mostly due to increased usage per customer. We distributed less electricity to industrial customers mostly because of lower usage by industrial customers.

Standard Offer Service

BGE provides standard offer service for customers that do not select an alternative generation supplier as discussed in the Electric Competition—Maryland section on page 34.

        Standard offer service revenues decreased during the third quarter of 2003 compared to the same period of 2002 mostly due to milder weather and power outages resulting from Hurricane Isabel.

        Standard offer service revenues decreased during the nine months ended September 30, 2003 compared to the same period of 2002 mostly because of the following:

•

approximately 1,200 megawatts of large commercial and industrial customers leaving BGE's standard offer service in the second quarter of 2002 and electing other electric generation suppliers, and

•

cooler summer weather in 2003.

        This decrease was partially offset by increased residential standard offer service revenues due to increased usage per customer, colder winter weather, and an increased number of customers.

Electricity Purchased for Resale Expenses

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

        Our electricity purchased for resale expenses for the third quarter of 2003 were lower compared to the same period of 2002 mostly due to cooler summer weather and power outages resulting from Hurricane Isabel in the third quarter of 2003.

        Our electricity purchased for resale expenses were lower during the nine months ended September 30, 2003 compared to the same period of 2002 mostly due to large commercial and industrial customers leaving BGE's standard offer service and electing other electric generation suppliers as previously discussed, cooler summer weather and outages resulting from Hurricane Isabel, partially offset by increased consumption by residential customers.

Electric Operations and Maintenance Expenses

Regulated electric operations and maintenance expenses increased $36.0 million during the third quarter of 2003 compared to the same period of 2002 and increased $31.4 million during the nine months ended September 30, 2003 compared to the same period in 2002. The increase is mostly due to distribution restoration expenses related to Hurricane Isabel of $36.1 million, which includes $4.7 million of non-incremental labor expenses. The increase also reflects higher benefit and other inflationary costs, offset by cost reductions resulting from our corporate-wide workforce reduction programs and other productivity initiatives.

Workforce Reduction Costs

BGE's electric business workforce reduction expenses decreased $2.9 million pre-tax, or $1.8 million after-tax, in the third quarter of 2003 and decreased $31.3 million pre-tax, or $18.9 million after-tax, during the nine months ended September 30, 2003 compared to the same periods in 2002 because these programs were substantially completed in 2002. We discuss our workforce reduction efforts in the Notes to Consolidated Financial Statements on page 12.

Other Electric Operating Expenses

Regulated other electric operating expenses were about the same for the quarter and nine months ended September 30, 2003 compared to the same periods of 2002.

50

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 September 30,						Nine Months Ended September 30,
		2003			2002			2003			2002
		(In millions)
Gas revenues		$	81.0		$	72.2		$	524.5		$	388.1
Gas purchased for resale expenses			(30.1	)		(28.3	)		(319.5	)		(191.3	)
Operations and maintenance expenses			(24.1	)		(25.1	)		(71.8	)		(71.0	)
Workforce reduction costs			—			(0.2	)		(0.1	)		(0.2	)
Depreciation and amortization			(11.7	)		(11.5	)		(34.8	)		(36.0	)
Taxes other than income taxes			(4.0	)		(7.5	)		(22.1	)		(24.7	)
Income (Loss) from operations		$	11.1		$	(0.4	)	$	76.2		$	64.9
Net Income (Loss)		$	2.4		$	(4.1	)	$	31.9		$	26.6
Special Items Included in Operations (after-tax)
	Workforce reduction costs	$	—		$	(0.1	)	$	—		$	(0.1	)

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

        Net income from the regulated gas business for the quarter and nine months ended September 30, 2003 increased compared to the same periods of 2002 mostly because of the following:

•

the reinstatement of a $7.7 million pre-tax regulatory asset following an order issued by the Maryland PSC, and

•

the approval of $3.6 million of property tax refund claims by the State of Maryland resulting from a reclassification of gas distribution pipeline from real property to personal property.

Gas Revenues

The changes in gas revenues in 2003 compared to 2002 were caused by:

	Quarter Ended September 30, 2003 vs. 2002			Nine Months Ended September 30, 2003 vs. 2002
	(In millions)
Distribution sales volumes	$	1.1		$	27.1
Base rates		(0.1	)		(1.2	)
Weather normalization		(1.7	)		(25.4	)
Gas cost adjustments		8.9			125.6
Total change in gas revenues from gas system sales		8.2			126.1
Off-system sales		0.3			9.2
Other		0.3			1.1
Total change in gas revenues	$	8.8		$	136.4

Distribution Sales Volumes

The percentage changes in our distribution sales volumes, by type of customer, in 2003 compared to 2002 were:

	Quarter Ended September 30, 2003 vs. 2002		Nine Months Ended September 30, 2003 vs. 2002
Residential	12.3	%	30.4	%
Commercial	(3.2	)	14.4
Industrial	(36.6	)	(20.5	)

        During the quarter ended September 30, 2003, we distributed more gas to residential customers compared to the same period of 2002 mostly due to increased usage per customer. We distributed less gas to commercial and industrial customers mostly due to decreased usage per customer.

        During the nine months ended September 30, 2003, we distributed more gas to residential and commercial customers compared to the same period of 2002 mostly due to colder winter weather and increased usage per customer. We distributed less gas to industrial customers mostly due to decreased usage by industrial customers.

Base Rates

Base rate revenues were about the same for the quarter and nine months ended September 30, 2003 compared to the same periods of 2002.

51

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 2002 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 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 and nine months ended September 30, 2003, gas cost adjustment revenues increased compared to the same periods of 2002 because we sold more gas at a higher price.

        In December 2002, a Hearing Examiner from the Maryland PSC issued a proposed order related to our annual gas cost adjustment clause review proceeding that allows us to recover $1.7 million of a previously established regulatory asset of $9.4 million for certain credits that were over-refunded to customers through our market-based rates. BGE reserved the remaining difference of $7.7 million as disallowed fuel costs in the fourth quarter of 2002. In August 2003, the Maryland PSC issued an order authorizing us to recover the remaining $7.7 million and we reinstated the previously established $9.4 million regulatory asset.

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 nine months ended September 30, 2003, revenues from off-system gas sales increased compared to the same periods of 2002 mostly because the gas we sold off-system was at a higher price, partially offset by less gas sold.

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 ended September 30, 2003, gas purchased for resale expenses increased compared to the same period of 2002, because the gas we purchased was at a higher price, partially offset by less gas sold and the $7.7 million recovery of previously disallowed fuel costs as discussed in the Gas Cost Adjustments section. During the nine months ended September 30, 2003, gas purchased for resale expenses increased compared to the same period of 2002 because we purchased more gas at a higher price.

Gas Operations and Maintenance Expenses

Regulated gas operations and maintenance expenses were about the same during the quarter and nine months ended September 30, 2003 compared to the same periods of 2002.

Taxes Other Than Income Taxes

Regulated gas taxes other than income taxes decreased during the quarter and nine months ended September 30, 2003 compared to the same periods of 2002 mostly due to the approval of a $3.6 million property tax refund claim by the State of Maryland resulting from a reclassification of gas distribution pipeline from real property to personal property.

Other Gas Operating Expenses

Regulated other gas operating expenses were about the same during the quarter and nine months ended September 30, 2003 compared to the same periods of 2002.

52

Other Nonregulated Businesses

Results

		Quarter Ended September 30,						Nine Months Ended September 30,
		2003			2002			2003			2002
		(In millions)
Revenues		$	144.5		$	133.5		$	443.3		$	385.6
Operating expenses			(129.9	)		(126.8	)		(403.0	)		(360.0	)
Workforce reduction costs			—			(0.1	)		(0.1	)		(0.2	)
Impairments losses and other costs			—			(10.2	)		—			(10.2	)
Depreciation and amortization			(5.5	)		(4.3	)		(14.1	)		(12.4	)
Taxes other than income taxes			(0.8	)		(1.2	)		(2.6	)		(3.3	)
Net gain on sales of investments and other assets			2.1			—			16.3			260.3
Income (Loss) from Operations		$	10.4		$	(9.1	)	$	39.8		$	259.8
Net Income (Loss)		$	0.7		$	(10.5	)	$	9.6		$	151.5
Special Items Included in Operations (after-tax)
	Net gain on sales of investments and other assets	$	1.3		$	—		$	9.9		$	166.2
	Workforce reduction costs		—			(0.1	)		(0.1	)		(0.2	)
	Costs associated with exit of BGE Home merchandise stores		—			(6.0	)		—			(6.0	)
	Impairment of real estate and international investments		—			(1.2	)		—			(1.2	)
Total Special Items		$	1.3		$	(7.3	)	$	9.8		$	158.8

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.

During the quarter ended September 30, 2003, net income from our other nonregulated businesses increased compared to the same period of 2002 mostly because we recognized costs associated with the exit of BGE Home merchandise stores and impairment of real estate and international investments in 2002 that had a negative impact in that period.

        During the nine months ended September 30, 2003, net income from our other nonregulated businesses decreased compared to the same period of 2002 mostly because we recognized a $163.3 million after-tax gain on the sale of our investment in Orion in 2002 that had a positive impact in that period. This decrease was partially offset by the following 2003 transactions:

•

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 on an installment sale of a parcel of real estate,

•

a $1.5 million pre-tax gain on the sale of real estate,

•

a $1.1 million pre-tax gain on the sale of financial investments, and

•

higher net income from BGE Home due to improved performance in their gas and electric commodity programs.

        As previously discussed in our 2002 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.

        Our remaining real estate projects, which represent approximately 330 acres of land holdings at September 30, 2003, are partially or substantially developed. Our strategy is to hold and in some cases further develop these projects to increase their value. However, if we were to sell these projects in the current market, we may have losses that could be material, although the amount of the losses is hard to predict.

        In addition, we initiated a liquidation program for our financial investments operation and expect to sell substantially all of our investments in this operation by the end of 2003. Through September 30, 2003, we liquidated approximately 89% of our investment portfolio since the beginning of 2002.

53

Consolidated Nonoperating Income and Expenses

Fixed Charges

During the quarter ended September 30, 2003, total fixed charges increased compared to the same period of 2002 mostly because we had lower capitalized interest due to our new generating facilities commencing operations and due to the issuance of $550 million of debt in June 2003 that was used to refinance the High Desert Power Project lease. We discuss the refinancing of the High Desert Power Project lease in more detail in the Notes to Consolidated Financial Statements on page 21.

        During the nine months ended September 30, 2003, total fixed charges increased compared to the same period of 2002 mostly because we had lower capitalized interest due to our new generating facilities commencing operations and a higher level of long-term debt due to the strengthening of our balance sheet and the refinancing of the High Desert Power Project lease. The majority of this debt, $1.8 billion was issued in the first quarter of 2002, with additional issuances totaling $700 million occurring in the second half of 2002. We used the proceeds of these issuances primarily to repay our short-term borrowings that funded our construction program and acquisitions.

        During the quarter and nine months ended September 30, 2003, total fixed charges at BGE decreased compared to the same periods of 2002 mostly because of a lower level of debt outstanding and lower interest rates.

Income Taxes

During the quarter ended September 30, 2003, our income taxes increased compared to the same period of 2002 mostly because of higher taxable income.

        During the nine months ended September 30, 2003, our income taxes decreased compared to the same period of 2002 mostly because of the gain on the sale of our investment in Orion in the first quarter of 2002 that increased income taxes in that period and a higher level of synthetic fuel tax credits in 2003.

        During the quarter ended September 30, 2003, income taxes at BGE decreased compared to the same period of 2002 mostly because of lower taxable income primarily due to expenses associated with Hurricane Isabel. During the nine months ended September 30, 2003, income taxes at BGE increased compared to the same period of 2002 mostly because of higher taxable income.

Financial Condition

Cash Flows

Cash provided by operations was $579.3 million for the nine months ended September 30, 2003 compared to $655.7 million for the same period in 2002.

        Cash used in investing activities for the nine months ended September 30, 2003 was $980.8 million compared to $116.2 million for the same period in 2002. This change was primarily due to a decrease in the sales of investments and other assets because of the sale of Orion and Corporate Office Properties Trust that generated $555.4 million in cash proceeds in 2002 and an increase in cash used for acquisitions in 2003 compared to the same period in 2002.

        Cash provided by financing activities for the nine months ended September 30, 2003 was $209.6 million compared to cash used in financing activities of $153.6 million for the same period in 2002. This $363.2 million change was primarily due to a lower repayment of debt, partially offset by lower issuances of long-term debt compared to the same period in 2002.

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. All Constellation Energy and BGE credit ratings have stable outlooks. At the date of this report, our credit ratings were as follows:

		Standard & Poor's 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 Originated Preferred Securities	BBB	A3	A-
	Preference Stock	BBB	Baa1	A-

54

Available Sources of Funding

As previously discussed in our 2002 Annual Report on Form 10-K, we decided to sell certain non-core assets to focus on our core strategies. We expect to use the proceeds from the sale of non-core assets to reduce our debt and fund our merchant energy business. 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 September 30, 2003 we had credit facilities of approximately $1.5 billion as discussed below.

        In June 2003, Constellation Energy arranged a $447.5 million 364-day revolving credit facility and a $447.5 million three-year revolving credit facility replacing a $640.0 million 364-day revolving credit facility and a $188.5 million three-year revolving credit facility. Both of the facilities that were replaced expired in the second quarter of 2003. We use these two facilities to allow the issuance of commercial paper and letters of credit. We also use the multi-year facilities to support the issuance of letters of credit primarily for our merchant energy business.

        Constellation Energy also has a $640.0 million revolving credit facility available to allow the issuance of commercial paper and letters of credit. This facility expires in June 2005. These revolving credit facilities allow the issuance of letters of credit up to approximately $1.1 billion.

        At September 30, 2003, letters of credit that totaled $412.1 million were issued under all of our facilities, which results in approximately $1.1 billion of unused credit facilities.

BGE

During 2003, certain credit facilities expired and BGE renewed those facilities. BGE continues to maintain $200.0 million in annual committed credit facilities, expiring May 2004 through November 2004, in order to allow commercial paper to be issued. As of September 30, 2003, BGE had no outstanding commercial paper, which results in $200.0 million of unused credit facilities.

Other Nonregulated Businesses

BGE Home Products & Services maintains a program to sell up to $50 million of receivables. We expect to extend this program beyond the current expiration date in December 2003.

        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 business requires a great deal of capital. Our estimated annual amounts for the years 2003 and 2004 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 2003 and 2004 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, and

•

the availability of cash from operations.

        Our estimates are also subject to additional factors. Please see the Forward Looking Statements section on page 61.

Calendar Year Estimates			2003		2004
			(In millions)
Nonregulated Capital Requirements:
	Merchant energy
		Steam generators	$	55	$	—
		Environmental controls		15		—
		Reactor vessel head replacement		10		25
		Continuing requirements (including nuclear fuel)		325		340
	Total merchant energy capital requirements			405		365
	Other nonregulated capital requirements			55		65
	Total nonregulated capital requirements			460		430
Utility Capital Requirements:
	Regulated electric			230		205
	Regulated gas			60		60
	Total utility capital requirements			290		265
Total capital requirements			$	750	$	695

The table above does not include amounts associated with the refinancing of the High Desert Power Project or the capital requirements and financing costs of approximately $40 million for the High Desert Power Project for the six months ended June 30, 2003. We discuss the acquisition of the High Desert Power Project in the Notes to Consolidated Financial Statements on page 21.

55

Capital Requirements

Merchant Energy Business

Our merchant energy business will require additional funding for the following:

•

Costs for replacing the reactor vessel heads at Calvert Cliffs. We expect to replace the reactor vessel heads during the 2006 refueling outage for Unit 1 and the 2007 refueling outage for Unit 2.

•

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 the Environmental Matters section of the Notes to Consolidated Financial Statements beginning on page 17.

Regulated Electric and Gas

Regulated electric and gas construction expenditures primarily include new business construction needs and improvements to existing facilities. Capital requirements for 2003 in the table on page 55 include $28.9 million in costs incurred as a result of Hurricane Isabel to restore the electric distribution system.

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 a mixture of debt and equity with an overall goal of maintaining a strong investment grade credit profile.

BGE

Funding for utility capital expenditures is expected from internally generated funds. During 2003, we expect our regulated utility business to generate significant cash flow from operations. 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 on page 26.

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. BGE Home Products & Services can continue to fund capital requirements through sales of receivables.

        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. We discuss our remaining non-core assets and market conditions in the Results of Operations—Other Nonregulated Businesses section on page 53.

Committed Amounts

Our total contractual and contingent obligations as of September 30, 2003 are shown in the following table:

	Payments/Expiration
	2003		2004- 2005		2006- 2007		Thereafter		Total
	(In millions)
Contractual Obligations
Short-term borrowings	$	10.4	$	—	$	—	$	—	$	10.4
Nonregulated long-term debt1		2.1		346.6		601.8		2,744.9		3,695.4
BGE long-term debt1		—		193.0		541.2		911.4		1,645.6
BGE preference stock		—		—		—		190.0		190.0
Fuel and transportation		193.5		535.8		180.5		78.1		987.9
Purchased capacity and energy2		340.9		1,287.6		395.6		246.5		2,270.6
Operating leases		5.5		40.8		34.9		148.5		229.7
Capital and other commitments3		10.7		42.4		26.9		244.7		324.7
Total contractual obligations		563.1		2,446.2		1,780.9		4,564.1		9,354.3
Contingent Obligations
Letters of credit		249.5		162.6		—		—		412.1
Guarantees — competitive supply4		2,142.8		1,034.4		50.8		313.7		3,541.7
Other guarantees, net5		6.7		7.1		3.0		233.4		250.2
Total contingent obligations		2,399.0		1,204.1		53.8		547.1		4,204.0
Total obligations	$	2,962.1	$	3,650.3	$	1,834.7	$	5,111.2	$	13,558.3

1 Amounts in long-term debt maturities reflect the original maturity date. Investors may require us to repay $387.0 million early through put options and remarketing features.

2 Our contractual obligations for purchased capacity and energy are shown on a gross basis for certain transactions, including the fixed payment portions related to capacity payments under tolling contracts that were previously included in mark-to-market energy assets and liabilities prior to EITF 02-3. We have recorded approximately $40.3 million of liabilities related to purchased capacity and energy obligations at September 30, 2003 in our Consolidated Balance Sheets.

3 Amounts related to capital expenditures are included for applicable years in our capital requirements table.

4 While the face amount of these guarantees is $3,541.7 million, we do not expect to fund the full amount. Our calculation of the fair value of obligations covered by these guarantees was $714.9 million at September 30, 2003.

5 Other guarantees in the above table are shown net of liabilities recorded at September 30, 2003 in our Consolidated Balance Sheets.

56

        While we included our contingent obligations in the table above, these amounts do not represent incremental consolidated Constellation Energy obligations; rather, they primarily represent parental guarantees of certain subsidiary obligations. Specifically, the $3,541.7 million guarantees—competitive supply represent the face amount of these guarantees. Our calculation of the fair value of obligations covered by these guarantees was $714.9 million at September 30, 2003. We do not expect to fund the full amounts under the letters of credit and guarantees.

Liquidity Provisions

We have certain agreements that contain provisions that would 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. However, under counterparty contracts related to our wholesale origination and risk management operation, where we are obligated to post collateral, 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/Baa2	1	$	—	$	—
BBB-/Baa3	2		99		99
Below investment grade (BB+)	3		596		695

        At September 30, 2003, we had approximately $1.3 billion of unused credit facilities and $423.1 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.

        In many cases, customers of our wholesale origination and risk management operation rely on the creditworthiness of Constellation Energy. A decline below investment grade by 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 September 30, 2003, the debt to capitalization ratios as defined in the credit agreements were no greater than 56%.

        A BGE credit facility of $50.0 million that expires in August 2004 requires BGE to maintain a ratio of debt to capitalization equal to or less than 65%. At September 30, 2003, the debt to capitalization ratio for BGE as defined in the credit agreement was 50%. At September 30, 2003, no amount is outstanding under this facility.

        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 and Nine Mile Point to ensure these plants have funds to meet expenses and obligations to safely operate and maintain the plants.

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 17 and in our 2002 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 Issued and Adopted

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

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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 sections in the Notes to Consolidated Financial Statements beginning on page 15,



•

activities of our wholesale origination and risk management operation in the Merchant Energy Business section of Management's Discussion and Analysis beginning on page 39, and

•

changes to our business environment in the Business Environment section of Management's Discussion and Analysis beginning on page 34.

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 that has materially affected, or is reasonably likely to materially affect, either Constellation Energy's or BGE's internal control over financial reporting.

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PART II. OTHER INFORMATION

Item 1. Legal Proceedings

California

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, recision 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 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. In 2002, the court issued an order to the plaintiff asking that he show cause why he had not yet served the defendants. In April 2002, a second show cause order was issued. After several postponements, a hearing is now scheduled in February 2004 on that order.

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 Litigation

Beginning in September 2002, BGE, Constellation Energy, and several other defendants have been involved in numerous actions 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 55 cases have been filed to date in the Circuit Court for Baltimore City, 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 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' appeal rights do not expire until the cases are finally concluded as to all defendants. At this time no discovery has occurred. We believe that we have meritorious defenses to all of the cases and intend to defend the action 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 is scheduled to end in December 2003. 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 525 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,

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•

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, 161 asbestos cases were dismissed or resolved for amounts that were not significant. Approximately 235 cases are scheduled for trial by the end of 2004.

        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.

Other

McCray, et. al. v. Baltimore Gas and Electric Company—On June 10, 2002, a suit was filed in the Circuit Court of Baltimore City, Maryland seeking a total of $585 million in compensatory and punitive damages from BGE as a result of a fire in a home that caused five fatalities. Electricity to the home was shut off. BGE believes it has meritorious defenses and intends 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.

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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," "expects," "intends," "plans," and other similar words. These statements 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 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's and BGE's ability to maintain their current credit ratings,

•

the effectiveness of Constellation Energy's and BGE's risk management policies and procedures and the ability of our counterparties to satisfy their financial and performance commitments,

•

the liquidity and competitiveness of wholesale markets for energy commodities,

•

operational factors affecting the start-up or ongoing 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 increase 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 business 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 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.

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Item 6. Exhibits and Reports on Form 8-K

(a)	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)	Rule 13a-14(a)/15(d)-14(a) Certification
	Exhibit No. 31(b)	Rule 13a-14(a)/15(d)-14(a) Certification
	Exhibit No. 31(c)	Rule 13a-14(a)/15(d)-14(a) Certification
	Exhibit No. 31(d)	Rule 13a-14(a)/15(d)-14(a) Certification
	Exhibit No. 32(a)	Section 1350 Certification
	Exhibit No.32(b)	Section 1350 Certification
	Exhibit No.32(c)	Section 1350 Certification
	Exhibit No.32(d)	Section 1350 Certification

         (b) Reports on Form 8-K for the quarter ended September 30, 2003:

Date	Item Reported
July 31, 2003	Item 7. Financial Statements and Exhibits
	Item 12. Results of Operations and Financial Condition

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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: November 13, 2003
	/s/  E. FOLLIN SMITHE. Follin Smith, Senior Vice President on behalf of each Registrant and as Principal Financial Officer of each Registrant

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