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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, 2005

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

MARYLAND
(State of Incorporation of both registrants)

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

410-783-2800

(Registrants' telephone number, including area code)

NOT APPLICABLE

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

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

         Indicate by check mark whether Constellation Energy Group, Inc. is an accelerated filer  Yes ý        No o

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

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

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

Common Stock, without par value 178,481,082 shares outstanding of
Constellation Energy Group, Inc. on October 28, 2005.

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

TABLE OF CONTENTS

			Page
Part I—Financial Information
	Item 1—Financial Statements
		Constellation Energy Group, Inc. and Subsidiaries
		Consolidated Statements of Income	3
		Consolidated Statements of Comprehensive Income	3
		Consolidated Balance Sheets	4
		Consolidated Statements of Cash Flows	6
		Baltimore Gas and Electric Company and Subsidiaries
		Consolidated Statements of Income	7
		Consolidated Statements of Comprehensive Income	7
		Consolidated Balance Sheets	8
		Consolidated Statements of Cash Flows	10
		Notes to Consolidated Financial Statements	11
	Item 2—Management's Discussion and Analysis of Financial Condition and Results of Operations
		Introduction and Overview	27
		Business Environment	27
		Events of 2005	30
		Results of Operations	31
		Financial Condition	46
		Capital Resources	48
	Item 3—Quantitative and Qualitative Disclosures About Market Risk		52
	Item 4—Controls and Procedures		52
Part II—Other Information
	Item 1—Legal Proceedings		53
	Item 2—Unregistered Sales of Equity Securities and Use of Proceeds		53
	Item 5—Other Information		53
	Item 6—Exhibits		56
	Signature		57

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,
		2005			2004			2005			2004
		(In millions, except per share amounts)
Revenues
	Nonregulated revenues	$	4,183.4		$	2,702.2		$	9,771.0		$	7,018.0
	Regulated electric revenues		626.8			582.0			1,583.4			1,543.6
	Regulated gas revenues		112.2			74.6			618.5			504.0
	Total revenues		4,922.4			3,358.8			11,972.9			9,065.6
Expenses
	Fuel and purchased energy expenses		3,953.2			2,317.3			9,218.0			6,372.7
	Operating expenses		415.4			445.3			1,339.3			1,296.6
	Workforce reduction costs		3.9			—			3.9			—
	Depreciation and amortization		143.3			132.5			407.4			376.1
	Accretion of asset retirement obligations		15.8			14.5			46.2			38.1
	Taxes other than income taxes		73.8			67.0			209.4			192.5
	Total expenses		4,605.4			2,976.6			11,224.2			8,276.0
Income from Operations			317.0			382.2			748.7			789.6
Other Income (Expense)			16.1			(0.6	)		43.0			15.1
Fixed Charges
	Interest expense		75.7			79.9			230.2			246.4
	Interest capitalized and allowance for borrowed funds used during construction		(2.1	)		(2.2	)		(7.6	)		(8.0	)
	BGE preference stock dividends		3.3			3.3			9.9			9.9
	Total fixed charges		76.9			81.0			232.5			248.3
Income from Continuing Operations Before Income Taxes			256.2			300.6			559.2			556.4
Income Tax Expense			72.1			95.8			138.7			115.8
Income from Continuing Operations			184.1			204.8			420.5			440.6
	Income (loss) from discontinued operations, net of income taxes of $4.1, $5.7, $12.0, and ($11.4), respectively		1.4			5.6			7.4			(35.8	)
Net Income		$	185.5		$	210.4		$	427.9		$	404.8
Earnings Applicable to Common Stock		$	185.5		$	210.4		$	427.9		$	404.8
Average Shares of Common Stock Outstanding—Basic			178.1			175.5			177.5			170.7
Average Shares of Common Stock Outstanding—Diluted			180.5			176.4			179.6			171.8
Earnings Per Common Share from Continuing Operations—Basic		$	1.03		$	1.17		$	2.37		$	2.58
	Income (loss) from discontinued operations—Basic		0.01			0.03			0.04			(0.21	)
Earnings Per Common Share—Basic		$	1.04		$	1.20		$	2.41		$	2.37
Earnings Per Common Share from Continuing Operations—Diluted		$	1.02		$	1.16		$	2.34		$	2.56
	Income (loss) from discontinued operations—Diluted		0.01			0.03			0.04			(0.20	)
Earnings Per Common Share—Diluted		$	1.03		$	1.19		$	2.38		$	2.36
Dividends Declared Per Common Share		$	0.335		$	0.285		$	1.005		$	0.855

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)

Constellation Energy Group, Inc. and Subsidiaries

			Three Months Ended September 30,						Nine Months Ended September 30,
			2005			2004			2005			2004
			(In millions)
Net Income			$	185.5		$	210.4		$	427.9		$	404.8
	Other comprehensive income (OCI)
		Reclassification of net losses on sales of securities from OCI to net income, net of taxes		1.6			2.6			1.5			2.3
		Reclassification of net gains on hedging instruments from OCI to net income, net of taxes		(318.7	)		(111.0	)		(416.9	)		(180.2	)
		Net unrealized gains on hedging instruments, net of taxes		820.8			88.0			906.9			286.8
		Net unrealized gains (losses) on securities, net of taxes		6.7			(1.2	)		15.3			12.8
		Net unrealized gain on foreign currency, net of taxes		0.7			—			1.1			—
Comprehensive Income			$	696.6		$	188.8		$	935.8		$	526.5

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, 2005*			December 31, 2004
			(In millions)
Assets
	Current Assets
		Cash and cash equivalents	$	1,135.0		$	706.3
		Accounts receivable (net of allowance for uncollectibles of $38.1 and $43.1, respectively)		2,819.1			1,979.3
		Mark-to-market energy assets		1,845.8			567.3
		Risk management assets		1,963.2			471.5
		Fuel stocks		361.3			298.3
		Materials and supplies		200.8			203.8
		Assets held for sale—discontinued operations		326.8			—
		Other		487.5			262.9
		Total current assets		9,139.5			4,489.4
	Investments and Other Assets
		Nuclear decommissioning trust funds		1,091.4			1,033.7
		Mark-to-market energy assets		1,003.0			359.8
		Risk management assets		661.5			306.2
		Investments in qualifying facilities and power projects		308.1			318.4
		Regulatory assets (net)		148.8			195.4
		Goodwill		147.1			144.8
		Other		511.1			412.8
		Total investments and other assets		3,871.0			2,771.1
	Property, Plant and Equipment
		Nonregulated property, plant and equipment		8,453.9			8,638.4
		Regulated property, plant and equipment		5,502.4			5,412.7
		Nuclear fuel (net of amortization)		250.2			264.3
		Accumulated depreciation		(4,288.8	)		(4,228.8	)
		Net property, plant and equipment		9,917.7			10,086.6
	Total Assets		$	22,928.2		$	17,347.1

* Unaudited

See Notes to Consolidated Financial Statements.

4

CONSOLIDATED BALANCE SHEETS

Constellation Energy Group, Inc. and Subsidiaries

			September 30, 2005*			December 31, 2004
			(In millions)
Liabilities and Equity
	Current Liabilities
		Current portion of long-term debt	$	200.8		$	480.4
		Accounts payable and accrued liabilities		2,033.0			1,424.9
		Customer deposits and collateral		791.0			223.8
		Mark-to-market energy liabilities		1,801.5			559.7
		Risk management liabilities		643.7			304.3
		Liabilities associated with assets held for sale		274.6			—
		Deferred income taxes		602.4			95.0
		Accrued expenses and other		642.2			574.3
		Total current liabilities		6,989.2			3,662.4
	Deferred Credits and Other Liabilities
		Deferred income taxes		1,093.3			1,303.3
		Asset retirement obligations		876.4			825.0
		Mark-to-market energy liabilities		932.5			315.0
		Risk management liabilities		1,563.7			472.2
		Postretirement and postemployment benefits		381.0			375.3
		Net pension liability		265.5			269.7
		Deferred investment tax credits		65.8			71.2
		Other		292.9			232.0
		Total deferred credits and other liabilities		5,471.1			3,863.7
	Long-term Debt
		Long-term debt of Constellation Energy		3,061.1			3,363.3
		Long-term debt of nonregulated businesses		345.0			437.2
		First refunding mortgage bonds of BGE		342.8			346.3
		Other long-term debt of BGE		879.6			899.6
		6.20% deferrable interest subordinated debentures due October 15, 2043 to BGE wholly owned BGE Capital Trust II relating to trust preferred securities		257.7			257.7
		Unamortized discount and premium		(8.5	)		(10.5	)
		Current portion of long-term debt		(200.8	)		(480.4	)
		Total long-term debt		4,676.9			4,813.2
	Minority Interests			22.7			90.9
	BGE Preference Stock Not Subject to Mandatory Redemption			190.0			190.0
	Common Shareholders' Equity
		Common stock		2,597.0			2,502.5
		Retained earnings		2,674.9			2,425.9
		Accumulated other comprehensive income (loss)		306.4			(201.5	)
		Total common shareholders' equity		5,578.3			4,726.9
	Commitments, Guarantees, and Contingencies (see Notes)
	Total Liabilities and Equity		$	22,928.2		$	17,347.1

* Unaudited

See Notes to Consolidated Financial Statements.

5

CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)

Constellation Energy Group, Inc. and Subsidiaries

Nine Months Ended September 30,				2005			2004
				(In millions)
Cash Flows From Operating Activities
	Net income			$	427.9		$	404.8
	Adjustments to reconcile to net cash provided by operating activities
		(Income) loss from discontinued operations			(7.4	)		35.8
		Depreciation and amortization			484.7			474.4
		Accretion of asset retirement obligations			46.2			38.1
		Deferred income taxes			2.8			90.8
		Investment tax credit adjustments			(5.4	)		(5.4	)
		Deferred fuel costs			12.1			10.8
		Pension and postemployment benefits			4.0			(8.8	)
		Workforce reduction costs			3.9			—
		Other non-cash adjustments included in income			(3.1	)		5.3
		Equity in earnings of affiliates less than dividends received			28.3			17.3
		Revenues from derivative contracts classified as financing activities under SFAS No. 149			(47.4	)		—
		Changes in
			Accounts receivable		(477.0	)		421.9
			Mark-to-market energy assets and liabilities		(98.6	)		(35.7	)
			Risk management assets and liabilities		(51.5	)		(41.5	)
			Materials, supplies, and fuel stocks		(126.0	)		(138.7	)
			Other current assets		(193.0	)		(28.7	)
			Accounts payable and accrued liabilities		438.2			(471.6	)
			Other current liabilities		662.7			7.1
			Other		(2.1	)		(26.8	)
	Net cash provided by operating activities				1,099.3			749.1
Cash Flows From Investing Activities
	Investments in property, plant and equipment				(476.9	)		(496.4	)
	Asset acquisitions and business combinations, net of cash acquired				(238.1	)		(457.0	)
	Contributions to nuclear decommissioning trust funds				(13.2	)		(17.7	)
	Proceeds from sale of discontinued operations				217.6			72.7
	Sales of investments and other assets				1.9			29.6
	Issuances of loans receivable				(82.8	)		—
	Other investments				(52.2	)		(16.3	)
	Net cash used in investing activities				(643.7	)		(885.1	)
Cash Flows From Financing Activities
	Net issuance (maturity) of short-term borrowings				10.0			(8.1	)
	Proceeds from issuance of common stock				66.5			271.7
	Repayment of long-term debt				(338.4	)		(180.4	)
	Common stock dividends paid				(169.1	)		(139.7	)
	Proceeds from acquired contracts				403.3			—
	Revenues from derivative contracts classified as financing activities under SFAS No. 149				47.4			—
	Other				(41.8	)		0.1
	Net cash used in financing activities				(22.1	)		(56.4	)
Net Increase (Decrease) in Cash and Cash Equivalents					433.5			(192.4	)
Cash and Cash Equivalents at Beginning of Period					706.3			721.3
Cash and Cash Equivalents at End of Period				$	1,139.8	*	$	528.9

* Includes $4.8 million related to "Assets held for sale" at September 30, 2005

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,
			2005			2004			2005			2004
			(In millions)
Revenues
	Electric revenues		$	626.8		$	582.0		$	1,583.4		$	1,543.6
	Gas revenues			115.9			75.3			626.9			507.4
	Total revenues			742.7			657.3			2,210.3			2,051.0
Expenses
	Operating expenses
		Electricity purchased for resale		362.5			338.4			849.0			833.1
		Gas purchased for resale		72.1			31.6			422.5			307.1
		Operations and maintenance		112.7			107.9			332.5			312.3
	Depreciation and amortization			58.6			61.3			176.6			181.9
	Taxes other than income taxes			41.9			41.0			126.7			124.1
	Total expenses			647.8			580.2			1,907.3			1,758.5
Income from Operations				94.9			77.1			303.0			292.5
Other Income (Expense)				1.2			(3.2	)		4.7			(2.2	)
Fixed Charges
	Interest expense			23.9			23.9			71.4			73.6
	Allowance for borrowed funds used during construction			(0.6	)		(0.2	)		(1.6	)		(0.7	)
	Total fixed charges			23.3			23.7			69.8			72.9
Income Before Income Taxes				72.8			50.2			237.9			217.4
Income Taxes				27.1			18.8			91.0			84.8
Net Income				45.7			31.4			146.9			132.6
Preference Stock Dividends				3.3			3.3			9.9			9.9
Earnings Applicable to Common Stock			$	42.4		$	28.1		$	137.0		$	122.7

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)

			Three Months Ended September 30,				Nine Months Ended September 30,
			2005		2004		2005		2004
			(In millions)
Net Income			$	42.4	$	28.1	$	137.0	$	122.7
	Other comprehensive income
		Reclassification of unrealized gain on hedging instruments from OCI to net income, net of taxes		—		—		—		(0.1	)
Comprehensive Income			$	42.4	$	28.1	$	137.0	$	122.6

See Notes to Consolidated Financial Statements.

7

CONSOLIDATED BALANCE SHEETS

Baltimore Gas and Electric Company and Subsidiaries

				September 30, 2005*			December 31, 2004
				(In millions)
Assets
	Current Assets
		Cash and cash equivalents		$	11.3		$	8.2
		Accounts receivable (net of allowance for uncollectibles of $13.0 and $13.0, respectively)			359.7			381.8
		Investment in cash pool, affiliated company			117.1			127.9
		Accounts receivable, affiliated companies			34.0			1.0
		Fuel stocks			105.1			86.5
		Materials and supplies			38.8			34.6
		Prepaid taxes other than income taxes			67.2			44.5
		Other			5.4			7.2
		Total current assets			738.6			691.7
Investments and Other Assets
		Regulatory assets (net)			148.8			195.4
		Receivable, affiliated company			160.0			150.4
		Other			146.9			134.2
		Total investments and other assets			455.7			480.0
	Utility Plant
		Plant in service
			Electric		3,870.5			3,759.3
			Gas		1,109.2			1,086.7
			Common		414.0			478.4
			Total plant in service		5,393.7			5,324.4
		Accumulated depreciation			(1,938.3	)		(1,921.5	)
		Net plant in service			3,455.4			3,402.9
		Construction work in progress			105.9			83.1
		Plant held for future use			2.8			5.2
		Net utility plant			3,564.1			3,491.2
	Total Assets			$	4,758.4		$	4,662.9

* Unaudited

See Notes to Consolidated Financial Statements.

8

CONSOLIDATED BALANCE SHEETS

Baltimore Gas and Electric Company and Subsidiaries

			September 30, 2005*			December 31, 2004
			(In millions)
Liabilities and Equity
	Current Liabilities
		Current portion of long-term debt	$	181.0		$	165.9
		Accounts payable and accrued liabilities		122.4			125.4
		Accounts payable and accrued liabilities, affiliated companies		126.0			146.1
		Customer deposits		64.8			64.3
		Accrued taxes		33.5			32.2
		Accrued expenses and other		79.6			71.7
		Total current liabilities		607.3			605.6
	Deferred Credits and Other Liabilities
		Deferred income taxes		600.8			608.0
		Postretirement and postemployment benefits		280.2			278.2
		Deferred investment tax credits		15.6			16.9
		Other		21.7			20.0
		Total deferred credits and other liabilities		918.3			923.1
	Long-term Debt
		First refunding mortgage bonds of BGE		342.8			346.3
		Other long-term debt of BGE		879.6			899.6
		6.20% deferrable interest subordinated debentures due October 15, 2043 to wholly owned BGE Capital Trust II relating to trust preferred securities		257.7			257.7
		Long-term debt of nonregulated businesses		25.0			25.0
		Unamortized discount and premium		(2.7	)		(3.2	)
		Current portion of long-term debt		(181.0	)		(165.9	)
		Total long-term debt		1,321.4			1,359.5
	Minority Interest			18.4			18.7
	Preference Stock Not Subject to Mandatory Redemption			190.0			190.0
	Common Shareholder's Equity
		Common stock		912.2			912.2
		Retained earnings		790.1			653.1
		Accumulated other comprehensive income		0.7			0.7
		Total common shareholder's equity		1,703.0			1,566.0
	Commitments, Guarantees, and Contingencies (see Notes)
	Total Liabilities and Equity		$	4,758.4		$	4,662.9

* Unaudited

See Notes to Consolidated Financial Statements.

9

CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)

Baltimore Gas and Electric Company and Subsidiaries

Nine Months Ended September 30,				2005			2004
				(In millions)
Cash Flows From Operating Activities
	Net income			$	146.9		$	132.6
	Adjustments to reconcile to net cash provided by operating activities
		Depreciation and amortization			187.5			187.9
		Deferred income taxes			(6.4	)		28.9
		Investment tax credit adjustments			(1.3	)		(1.4	)
		Deferred fuel costs			12.1			10.8
		Pension and postemployment benefits			(5.2	)		(18.7	)
		Allowance for equity funds used during construction			(2.8	)		(1.4	)
		Changes in
			Accounts receivable		22.1			22.4
			Receivables, affiliated companies		(33.0	)		(47.8	)
			Materials, supplies, and fuel stocks		(22.9	)		(45.5	)
			Other current assets		(20.9	)		(24.6	)
			Accounts payable and accrued liabilities		(3.0	)		(8.4	)
			Accounts payable and accrued liabilities, affiliated companies		(20.1	)		(40.2	)
			Other current liabilities		9.5			(22.4	)
			Other		(23.1	)		(19.8	)
	Net cash provided by operating activities				239.4			152.4
Cash Flows From Investing Activities
	Utility construction expenditures (excluding equity portion of allowance for funds used during construction)				(199.2	)		(185.4	)
	Change in cash pool at parent				10.8			303.7
	Sales of investments and other assets				—			4.9
	Other				(14.5	)		2.7
	Net cash (used in) provided by investing activities				(202.9	)		125.9
Cash Flows From Financing Activities
	Distribution to parent				—			(139.7	)
	Repayment of long-term debt				(23.5	)		(129.8	)
	Preference stock dividends paid				(9.9	)		(9.9	)
	Net cash used in financing activities				(33.4	)		(279.4	)
Net Increase (Decrease) in Cash and Cash Equivalents					3.1			(1.1	)
Cash and Cash Equivalents at Beginning of Period					8.2			11.0
Cash and Cash Equivalents at End of Period				$	11.3		$	9.9

See Notes to Consolidated Financial Statements.

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 "regulated business(es)" are to BGE.

Variable Interest Entities

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

VIE	Nature of Involvement	Date of Involvement
Power projects and fuel supply entities	Equity investment and guarantees	Prior to 2003
Power contract monetization entities	Power sale agreements, loans, and guarantees	March 2005

        We discuss the nature of our involvement with the power contract monetization VIEs in detail below in the Customer Contract Restructuring section.

        The following is summary information available as of September 30, 2005 about the VIEs in which we have a significant interest, but are not the primary beneficiary:

	Power Contract Monetization VIEs		All Other VIEs		Total
	(In millions)
Total assets	$	783.8	$	231.4	$	1,015.2
Total liabilities		689.8		82.5		772.3
Our ownership interest		—		46.2		46.2
Other ownership interests		94.0		102.7		196.7
Our maximum exposure to loss		79.0		68.0		147.0

        The maximum exposure to loss represents the loss that we would incur in the unlikely event that our interests in all of these entities were to become worthless and we were required to fund the full amount of all guarantees associated with these entities. Our maximum exposure to loss as of September 30, 2005 consists of the following:

•

outstanding loans and letters of credit totaling $88.4 million,

•

the carrying amount of our investment totaling $45.9 million, and

•

debt and performance guarantees totaling $12.7 million.

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

Customer Contract Restructuring

In March 2005, our merchant energy business closed a transaction in which we assumed from a counterparty two power sales contracts with existing VIEs. Under the contracts, we sell power to the VIEs which, in turn, sell that power to an electric distribution utility through 2013.

        The VIEs previously were created by the counterparty to issue debt in order to monetize the value of the original contracts to purchase and sell power. The difference between the contract prices at which the VIEs purchase and sell power is used to service the debt of the VIEs, which totaled $677.6 million at September 30, 2005.

        The market price for power at the closing of our transaction was higher than the contract price under the existing power sales contracts we assumed. Therefore, we received compensation totaling $308.5 million, equal to the net present value of the difference between the contract price under the power sales contracts and the market price of power at closing. We used a portion of this amount to

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settle $68.5 million of existing derivative liabilities with the same counterparty, and we also loaned $82.8 million to the holder of the equity in the VIEs. As a result, we received net cash at closing of $157.2 million. We also guaranteed our subsidiaries' performance under the power sales contracts.

        The table below summarizes the transaction and the net cash received at closing:

	(In millions)
Gross compensation from original power sales contracts counterparty equal to fair value of power sales contracts at closing	$	308.5
Settlement of existing derivative liabilities		(68.5	)
Third-party loan secured by equity in VIE		(82.8	)
Net cash received at closing	$	157.2

        We recorded the closing of this transaction in our financial statements as follows:

	Balance Sheet	Cash Flows
Fair value of power sales contracts assumed (designated as cash-flow hedge)	Risk management liabilities	Financing cash inflow
Settlement of existing derivative liabilities	Mark-to-market and risk management liabilities	Operating cash outflow
Third-party loan	Other assets	Investing cash outflow

        We recorded the gross compensation we received to assume the power sales contracts as a financing cash inflow because it constitutes a prepayment for a portion of the market price of power which we will sell to the VIEs over the term of the contracts and does not represent a cash inflow from current period operating activities. We record the ongoing cash flows related to the sale of power to the VIEs as a financing cash inflow in accordance with Statement of Financial Accounting Standards (SFAS) No. 149, Amendment of FASB Statement No. 133 on Derivative and Hedging Activities.

        If the electric distribution utility were to default under its obligation to buy power from the VIEs, the equity holder could transfer its equity interests to us in lieu of repaying the loan. In this event, we would have the right to seek recovery of our losses from the electric distribution utility.

Earnings Per Share

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

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

	Quarter Ended September 30,		Nine Months Ended September 30,
	2005	2004	2005	2004
	(In millions)
Non-dilutive stock options	—	1.5	—	1.2
Dilutive common stock equivalent shares	2.4	0.9	2.1	1.1

Stock-Based Compensation

Under our long-term incentive plans, we granted stock options, performance and service-based restricted stock, performance-based units, and equity to officers, key employees, and members of the Board of Directors. As permitted by SFAS No. 123, Accounting for Stock-Based Compensation, we measure our stock-based compensation using the intrinsic value method in accordance with Accounting Principles Board Opinion (APB) No. 25, Accounting for Stock Issued to Employees, and related interpretations. We discuss these plans and accounting further in Note 14 of our 2004 Annual Report on Form 10-K.

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

		Quarter Ended September 30,						Nine Months Ended September 30,
		2005			2004			2005			2004
		(In millions, except per share amounts)
Net income, as reported		$	185.5		$	210.4		$	427.9		$	404.8
Add: Stock-based compensation expense determined under intrinsic value method and included in reported net income, net of related tax effects			7.8			3.7			17.8			9.5
Deduct: Stock-based compensation expense determined under fair value based method for all awards, net of related tax effects			(10.1	)		(5.9	)		(24.5	)		(15.3	)
Pro-forma net income		$	183.2		$	208.2		$	421.2		$	399.0
Earnings per share:
	Basic – as reported	$	1.04		$	1.20		$	2.41		$	2.37
	Basic – pro forma	$	1.03		$	1.19		$	2.37		$	2.34
	Diluted – as reported	$	1.03		$	1.19		$	2.38		$	2.36
	Diluted – pro forma	$	1.01		$	1.18		$	2.34		$	2.32

        In December 2004, the Financial Accounting Standards Board (FASB) issued SFAS No. 123 Revised (SFAS No. 123R), Share-Based Payment, which changed the accounting for stock-based compensation to require companies to expense stock options and other equity awards based on their grant-date fair values. We discuss SFAS No. 123R in more detail in the Accounting Standards Issued section on page 25.

Accretion of Asset Retirement Obligations

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

        The change in our "Asset retirement obligations" liability during 2005 was as follows:

	(In millions)
Liability at January 1, 2005	$	825.0
Accretion expense		46.2
Liabilities incurred		5.2
Liabilities settled		—
Revisions to cash flows		—
Other		—
Liability at September 30, 2005	$	876.4

        "Liabilities incurred" represents the asset retirement obligation associated with our investments in gas producing fields. We discuss this investment in more detail in the Asset Acquisition section on page 15.

        In March 2005, the FASB issued Interpretation No. (FIN) 47, Accounting for Conditional Asset Retirement Obligations—an interpretation of FASB Statement No. 143. We discuss FIN 47 in more detail in the Accounting Standards Issued section on page 26.

Workforce Reduction

We incurred costs related to workforce reduction efforts initiated in 2004. We discuss these costs in more detail in Note 2 of our 2004 Annual Report on Form 10-K.

        The following table summarizes the status of the involuntary severance liability:

	(In millions)
Severance liability balance at January 1, 2005	$	9.7
Amounts recorded as pension and postretirement liabilities		(3.6	)
Net cash severance liability		6.1
Cash severance payments		(4.2	)
Other		(0.2	)
Severance liability balance at September 30, 2005	$	1.7

Other represents adjustments to estimated severance liability based on additional information.

        As a result of the workforce reduction efforts initiated in 2004, in the third quarter of 2005 we were required to record a pre-tax settlement charge in our Consolidated Statements of Income of $3.9 million for one of our

13

qualified pension plans under SFAS No. 88, Employers' Accounting for Settlements and Curtailments of Defined Benefit Pension Plans and for Termination Benefits. This charge reflects recognition of the portion of deferred actuarial gains and losses associated with employees who were terminated as part of the restructuring or retired in 2005 and who elected to receive their pension benefit in the form of a lump-sum payment. In accordance with SFAS No. 88, a settlement charge must be recognized at the point in time when lump-sum payments exceed annual pension plan service and interest cost, which occurred in the third quarter of 2005.

Discontinued Operations

International Investments

In September 2005, we entered into an agreement to sell Constellation Power International Investments, Ltd. Our international investments include our interests in a Panamanian electric distribution facility and a fund that holds interests in two South American energy projects. Our other nonregulated businesses classified our international investments as held for sale and performed an impairment test under SFAS No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets, as of September 30, 2005. The impairment test indicated that the fair value less costs to sell exceeded the carrying value of the plant; therefore, we did not record an impairment charge.

        We completed the sale of our international investments on October 3, 2005 and we will recognize a pre-tax gain of approximately $23 million, or $15 million after-tax, in the fourth quarter of 2005. A portion of the sale proceeds, approximately $4 million cash, is contingent upon collection of certain receivables by March 31, 2006. This portion of the sales proceeds will not be recognized until collection of the receivables is assured beyond a reasonable doubt.

Oleander

In March 2005, we reached an agreement in principle to sell to affiliates of The Southern Company (Southern) our Oleander generating facility, a four-unit peaking plant located in Florida. Our merchant energy business classified Oleander as held for sale and performed an impairment test under SFAS No. 144 as of March 31, 2005. The impairment test indicated that the carrying value of the plant was higher than its fair value less costs to sell, and therefore in March 2005 we recorded an impairment charge of $4.8 million pre-tax as part of discontinued operations.

        In June 2005, we completed the sale of this facility to Southern for $217.6 million. We recognized a gain on the sale of $1.5 million pre-tax as part of discontinued operations.

        Presented in the table below are certain amounts related to these discontinued operations that are included in "Income (loss) from discontinued operations" in our Consolidated Statements of Income.

						International Investments
Quarter ended September 30,	Oleander									Total
	2005			2004		2005		2004		2005			2004
	(In millions)
Revenues	$	—		$	14.5	$	100.0	$	54.4	$	100.0		$	68.9
Income before income taxes		—			7.6		5.8		4.0		5.8			11.6
Net income		—			4.7		1.6		1.1		1.6			5.8
Pre-tax impairment charge		—			—		—		—		—			—
After-tax impairment charge		—			—		—		—		—			—
Pre-tax loss on sale		(0.3	)		—		—		—		(0.3	)		—
After-tax loss on sale		(0.2	)		—		—		—		(0.2	)		—
(Loss) income from discontinued operations, net of taxes		(0.2	)		4.7		1.6		1.1		1.4			5.8

We recognized a loss from discontinued operations of $(0.2) million, net of income taxes of $(0.1) million for the quarter ended September 30, 2004 related to our Hawaiian geothermal facility.

						International Investments
Nine months ended September 30,	Oleander									Total
	2005			2004		2005		2004		2005			2004
	(In millions)
Revenues	$	14.7		$	33.8	$	228.1	$	164.4	$	242.8		$	198.2
Income before income taxes		8.5			15.5		14.5		13.0		23.0			28.5
Net income		5.3			9.5		4.5		3.9		9.8			13.4
Pre-tax impairment charge		(4.8	)		—		—		—		(4.8	)		—
After-tax impairment charge		(3.0	)		—		—		—		(3.0	)		—
Pre-tax gain on sale		1.2			—		—		—		1.2			—
After-tax gain on sale		0.6			—		—		—		0.6			—
Income from discontinued operations, net of taxes		2.9			9.5		4.5		3.9		7.4			13.4

We recognized a loss from discontinued operations of $(49.2) million, net of income taxes of $(26.5) million, for the nine months ended September 30, 2004 related to our Hawaiian geothermal facility.

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        Presented in the table below are the components of the assets and liabilities held for sale for our international investments, which are included with our other nonregulated businesses:

At September 30, 2005
		(In millions)
Assets held for sale
	Cash	$	4.8
	Accounts receivable		80.1
	Property, plant and equipment		231.3
	Other assets		10.6
Total		$	326.8
Liabilities associated with assets held for sale
	Accounts payable	$	66.6
	Accrued interest		14.8
	Other liabilities		97.0
	Long-term debt		96.2
Total		$	274.6

Business Combination

In April 2005, we acquired Cogenex Corporation from Alliant Energy Corporation. We include Cogenex with our other nonregulated businesses and have included their results in our consolidated financial statements since the date of acquisition. Cogenex is a North American energy services firm providing consulting and technology solutions to industrial, institutional, and governmental customers. We acquired 100% ownership of Cogenex for $36.4 million. We acquired cash of $14.4 million as part of the purchase.

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

At April 1, 2005
	(In millions)
Cash	$	14.4
Other Current Assets		11.2
Total Current Assets		25.6
Net Property, Plant and Equipment		—
Other Assets		36.8
Total Assets Acquired		62.4
Current Liabilities		6.8
Deferred Credits and Other Liabilities		19.2
Net Assets Acquired	$	36.4

        Currently, the purchase price remains subject to certain adjustments, which could impact our purchase price allocation.

Asset Acquisition

In June 2005, we acquired working interests in gas producing fields in Texas and Alabama for approximately $211 million in cash and the assumption of below-market natural gas swaps and other liabilities totaling approximately $22 million. At the time of acquisition, these working interests had independently estimated proved reserves of approximately 216 billion cubic feet equivalent. The Texas asset acquisition was for approximately a 70% working interest and the Alabama asset acquisition was for a 100% working interest.

Information by Operating Segment

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

•

Our nonregulated merchant energy business includes:

—

full requirements load-serving sales of energy and capacity to utilities and commercial and industrial customers,

—

structured transactions and risk management services for various customers (including hedging of output from generating facilities and fuel costs and limited for profit trading activities managed through daily value at risk and liquidity position limits),

—

gas retail energy products and services to commercial and industrial customers,

—

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

—

products and services to upstream (exploration and production) and downstream (transportation and storage) natural gas customers,

—

coal sourcing services for the variable or fixed supply needs of North American and international power generators, and

—

operations and maintenance consulting services.

•

Our regulated electric business purchases, transmits, distributes, and sells electricity in Central Maryland.

•

Our regulated gas business purchases, transports, and sells natural gas in Central Maryland.

        Our remaining nonregulated businesses:

•

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

•

provide home improvements, service electric and gas appliances, service heating, air conditioning, plumbing, electrical, and indoor air quality systems, and provide natural gas marketing to residential customers in Central Maryland.

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        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 Panamanian distribution facility and in a fund that holds interests in two South American energy projects. We discuss the sale of our interests in our Panamanian distribution facility and the fund that holds interests in two South American energy projects in the Discontinued Operations section on page 14.

        Our Merchant Energy, Regulated Electric, and Regulated Gas 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 below.

	Reportable Segments
	Merchant Energy Business			Regulated Electric Business		Regulated Gas Business			Other Nonregulated Businesses			Eliminations			Consolidated
	(In millions)
For the quarter ended September 30,
2005
Unaffiliated revenues	$	4,134.2		$	626.8	$	112.2		$	49.2		$	—		$	4,922.4
Intersegment revenues		263.0			—		3.7			0.1			(266.8	)		—
Total revenues		4,397.2			626.8		115.9			49.3			(266.8	)		4,922.4
(Loss) income from discontinued operations		(0.2	)		—		—			1.6			—			1.4
Net income (loss)		141.5			51.1		(8.6	)		1.5			—			185.5
2004
Unaffiliated revenues	$	2,655.9		$	582.0	$	74.6		$	46.3		$	—		$	3,358.8
Intersegment revenues		282.4			—		0.7			—			(283.1	)		—
Total revenues		2,938.3			582.0		75.3			46.3			(283.1	)		3,358.8
Income from discontinued operations		4.5			—		—			1.1			—			5.6
Net income (loss)		188.0			36.8		(8.8	)		(5.6	)		—			210.4
For the nine months ended September 30,
2005
Unaffiliated revenues	$	9,627.2		$	1,583.4	$	618.5		$	143.8		$	—		$	11,972.9
Intersegment revenues		685.2			—		8.4			0.6			(694.2	)		—
Total revenues		10,312.4			1,583.4		626.9			144.4			(694.2	)		11,972.9
Income from discontinued operations		2.9			—		—			4.5			—			7.4
Net income		285.8			120.0		17.3			4.8			—			427.9
2004
Unaffiliated revenues	$	6,873.2		$	1,543.6	$	504.0		$	144.8		$	—		$	9,065.6
Intersegment revenues		799.0			—		3.4			—			(802.4	)		—
Total revenues		7,672.2			1,543.6		507.4			144.8			(802.4	)		9,065.6
(Loss) income from discontinued operations		(39.7	)		—		—			3.9			—			(35.8	)
Net income (loss)		287.7			107.1		15.7			(5.7	)		—			404.8

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

At September 30, 2005, total assets were $22,928.2 million compared to total assets of $17,347.1 million at December 31, 2004. During the quarter ended September 30, 2005, the energy markets were affected by higher commodity prices caused by a tight supply and demand balance, the impact of hot weather, and hurricane-related supply disruptions of the Gulf Coast energy infrastructure. Due to these events, the value of our merchant energy business mark-to-market and risk management assets increased significantly.

16

Pension and Postretirement Benefits

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

	Quarter Ended September 30,						Nine Months Ended September 30,
	2005			2004			2005			2004
	(In millions)
Components of net periodic pension benefit cost
Service cost	$	11.0		$	10.1		$	33.5		$	30.1
Interest cost		20.7			20.6			62.6			61.7
Expected return on plan assets		(25.3	)		(24.6	)		(74.8	)		(73.4	)
Amortization of unrecognized prior service cost		1.4			1.4			4.3			4.3
Recognized net actuarial loss		6.5			3.6			18.6			10.8
Amount capitalized as construction cost		(1.7	)		(1.2	)		(5.4	)		(3.1	)
Net periodic pension benefit cost	$	12.6		$	9.9		$	38.8		$	30.4

The amounts shown above do not reflect a settlement charge of $3.9 million recorded in the third quarter of 2005 related to one of our qualified pension plans and $2.8 million in the third quarter of 2004 related to one of our nonqualified plans. Net periodic pension benefit cost excludes a reduction in termination benefits of $0.4 million in 2005. BGE's portion of our net periodic pension benefit cost was $5.6 million for the quarter ended September 30, 2005 and $3.9 million for the quarter ended September 30, 2004. BGE's portion of net periodic pension benefit cost was $16.1 million for the nine months ended September 30, 2005 and $8.6 million for the nine months ended September 30, 2004.

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

	Quarter Ended September 30,						Nine Months Ended September 30,
	2005			2004			2005			2004
	(In millions)
Components of net periodic postretirement benefit cost
Service cost	$	2.0		$	1.4		$	5.7		$	5.3
Interest cost		6.0			4.7			17.8			18.3
Amortization of transition obligation		0.6			0.4			1.6			1.7
Amortization of unrecognized prior service cost		(0.9	)		(0.8	)		(2.6	)		(2.9	)
Recognized net actuarial loss		1.7			0.6			4.8			2.5
Amount capitalized as construction cost		(2.0	)		(1.3	)		(5.9	)		(5.3	)
Net periodic postretirement benefit cost	$	7.4		$	5.0		$	21.4		$	19.6

BGE's portion of our net periodic postretirement benefit cost was $6.8 million for the quarter ended September 30, 2005 and $4.6 million for the quarter ended September 30, 2004. BGE's portion of our net periodic postretirement benefit costs was $18.8 million for the nine months ended September 30, 2005 and $17.4 million for the nine months ended September 30, 2004.

        Our non-qualified pension plans and our postretirement benefit programs are not funded; however, we have trust assets securing certain executive pension benefits. We estimate that we will incur $3.1 million in pension benefit payments for our non-qualified pension plans and $27.9 million for retiree health and life insurance benefit payments during 2005. We contributed an additional $50.0 million to our qualified pension plans in March 2005, even though there was no Internal Revenue Service (IRS) required minimum contribution in 2005.

Financing Activities

During the first quarter of 2005, we entered into a new five-year credit facility totaling $1.5 billion. This new facility replaced two facilities totaling $1.1 billion—a $640.0 million facility that would have expired in June 2005 and a $447.5 million facility that would have expired in June 2006. Constellation Energy also has an existing $800.0 million revolving credit facility expiring in June 2007 and a $300.0 million facility expiring in June 2009.

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

        These revolving credit facilities allow the issuance of letters of credit up to approximately $2.6 billion. In addition, BGE maintains $200.0 million in credit facilities. At September 30, 2005, letters of credit that totaled $1.9 billion were issued under our facilities.

        During the fourth quarter of 2005, we expect to amend and extend the terms of our $800.0 million and our $300.0 million facilities. We expect to amend the $800.0 million facility into a $1.0 billion facility and the $300.0 million facility into a $750.0 million facility, both expiring in the fourth quarter of 2010.

        In July 2005, BGE announced a partial call of $1.9 million principal amount of its Remarketed Floating Rate Series Bonds due September 1, 2006 in connection with its annual sinking fund. The redemption was made pursuant to the sinking fund provisions of BGE's mortgage. Bonds called were randomly selected by lot. Bonds called for the sinking fund were redeemed in part on August 26, 2005 at the sinking fund call price of 100% of principal amount, plus accrued interest from June 1, 2005 to, but not including, August 26, 2005.

        Additionally, under our employee benefit plans and shareholder investment plans we issued $66.5 million of common stock during the nine months ended September 30, 2005.

17

Income Taxes

We have investments in facilities that manufacture solid synthetic fuel produced from coal as defined under the Internal Revenue Code (IRC) 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.

        As of September 30, 2005, we have recognized cumulative tax benefits associated with synthetic fuel tax credits of $281.3 million, of which $28.1 million was recognized during the quarter ended September 30, 2005 and $80.1 million during the nine months ended September 30, 2005.

        The IRC provides for a phase-out of the tax credit if average annual wellhead oil prices increase above certain levels. Each year, we are required to compare average annual wellhead oil prices per barrel as determined by the IRS (reference price) to an inflation adjusted oil price for the year, also determined by the IRS. The reference price is determined based on wellhead prices for all domestic oil production as published by the Energy Information Administration. During the nine months ended September 30, 2005, we estimate that the reference price averaged approximately $6 per barrel lower than the NYMEX price for light, sweet crude oil. For 2005, we estimate the credit reduction would begin if the reference price exceeds approximately $52 per barrel and would be fully phased out if the reference price exceeds approximately $66 per barrel. We currently believe that the 2005 reference price will not trigger a phase-out of the synthetic fuel tax credits in 2005 and, accordingly, we have recognized the full tax benefit of these credits in our Consolidated Statements of Income for the quarter and nine months ended September 30, 2005.

        While we do not currently believe the reference price will trigger a phase-out of synthetic fuel tax credits in 2005, if oil prices remain at recent high levels, a portion of our synthetic fuel tax credits could be phased-out in 2006 and 2007. We actively monitor and manage this exposure as part of our ongoing hedging activities. The objective of these activities is to reduce the potential losses we could incur if the reference price in a year exceeds a level triggering a phase-out of synthetic fuel tax credits.

        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 the IRC, we cannot predict the timing or outcome of any future challenge by the IRS, legislative or regulatory action, oil prices, the effectiveness of our hedging program, or the ultimate impact of such events on the synthetic fuel tax credits that we have claimed to date or expect to claim in the future, but the impact could be material to our financial results.

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

		Quarter Ended September 30,						Nine Months Ended September 30,
		2005			2004			2005			2004
		(In millions)
Income from continuing operations before income taxes (excluding BGE preference stock dividends)		$	259.5		$	303.9		$	569.1		$	566.3
Statutory federal income tax rate			35	%		35	%		35	%		35	%
Income taxes computed at statutory federal rate			90.8			106.4			199.2			198.2
(Decreases) increases in income taxes due to:
	Synthetic fuel tax credits		(28.1	)		(21.9	)		(80.1	)		(66.7	)
	Synthetic fuel tax credits (2003)*		—			—			—			(35.9	)
	State income taxes, net of federal tax benefit		10.8			12.2			24.0			21.4
	Other		(1.4	)		(0.9	)		(4.4	)		(1.2	)
Total income taxes		$	72.1		$	95.8		$	138.7		$	115.8
Effective tax rate			27.8	%		31.5	%		24.4	%		20.4	%

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

*Credits associated with 2003 production at our South Carolina facility that were recognized in the second quarter of 2004 upon receipt of a favorable Private Letter Ruling from the IRS.

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Commitments, Guarantees, and Contingencies

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

•

purchase of electric generating capacity and energy,

•

procurement and delivery of fuels,

•

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

•

long-term service agreements, capital for construction programs, and other.

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

        Our regulated businesses enter into various long-term contracts for the procurement of electricity and for the procurement, transportation, and storage of gas. As discussed in Note 1 of our 2004 Annual Report on Form 10-K, the costs of energy under these contracts are fully recoverable by our regulated businesses.

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

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

        At September 30, 2005, the total amount of commitments was $5,868.4 million. These commitments are primarily related to our merchant energy business.

Long-Term Power Sales Contracts

We enter into long-term power sales contracts in connection with our load-serving activities. We also enter into long-term power sales contracts associated with certain of our power plants. Our load-serving power sales contracts extend for terms through 2017 and provide for the sale of energy to electricity distribution utilities and certain retail customers. Our power sales contracts associated with our power plants extend for terms into 2014 and provide for the sale of all or a portion of the actual output of certain of our power plants. All long-term contracts were executed at pricing that approximated market rates, including profit margin, at the time of execution.

Guarantees

The terms of our guarantees are as follows:

	Expiration
	2005		2006- 2007		2008- 2009		Thereafter		Total
	(In millions)
Competitive Supply	$	3,082.1	$	2,239.4	$	324.2	$	1,562.2	$	7,207.9
Other		0.4		5.6		15.3		1,268.9		1,290.2
Total	$	3,082.5	$	2,245.0	$	339.5	$	2,831.1	$	8,498.1

        At September 30, 2005, we had a total of $8,498.1 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 our incremental obligations, but rather represent parental guarantees of existing subsidiary obligations, and we do not expect to fund the full amount under these guarantees.

•

Constellation Energy guaranteed $7,207.9 million on behalf of our subsidiaries for competitive supply activities. These guarantees are put into place in order to allow our subsidiaries the flexibility needed to conduct business with counterparties without having to post other forms of collateral. If the parent company was required to fund these subsidiary obligations, the total amount based on September 30, 2005 market prices would be $2,958.2 million. The recorded fair value of obligations in our Consolidated Balance Sheets for guarantees was $1,346.9 million at September 30, 2005.

•

Constellation Energy guaranteed $939.3 million primarily on behalf of our nuclear generating facilities primarily related to nuclear insurance and for credit support to ensure these plants have funds to meet expenses and obligations to safely operate and maintain the plants.

•

Constellation Energy guaranteed $59.5 million on behalf of our other nonregulated businesses primarily for loans and performance bonds of which $25.0 million was recorded in our Consolidated Balance Sheets at September 30, 2005.

•

Our merchant energy business guaranteed $19.6 million for loans and other performance guarantees related to certain power projects in which we have an investment.

•

Our other nonregulated businesses guaranteed $8.5 million primarily for performance bonds.

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•

BGE guaranteed two-thirds of certain debt of Safe Harbor Water Power Corporation, an unconsolidated investment. At September 30, 2005, Safe Harbor Water Power Corporation had outstanding debt of $20.0 million. The maximum amount of BGE's guarantee is $13.3 million.

•

BGE guaranteed the Trust Preferred Securities of $250.0 million of BGE Capital Trust II, an unconsolidated investment, as discussed in more detail in Note 9 of our 2004 Annual Report on Form 10-K.

        The total fair value of the obligations for our guarantees recorded in our Consolidated Balance Sheets was $1,371.9 million at September 30, 2005, and not the $8.5 billion of total guarantees. We assess the risk of having to perform under these guarantees to be minimal.

Environmental Matters

Solid and Hazardous Waste

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

Metal Bank

In 1997, the EPA, under the Comprehensive Environmental Response, Compensation and Liability Act ("Superfund"), issued a Record of Decision (ROD) for the proposed clean-up at the Metal Bank of America site, a metal reclaimer in Philadelphia. We had previously recorded a liability in our Consolidated Balance Sheets for BGE's 15.47% share of probable clean-up costs. Based on current settlement negotiations among the EPA and the potentially responsible parties involved at the site, we do not believe we will incur clean-up costs in excess of the amount recorded as a liability. 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.

68th Street Dump

In 1999, the EPA proposed to add the 68th Street Dump in Baltimore, Maryland to the Superfund National Priorities List ("NPL"), which is its list of sites targeted for clean-up and enforcement, and sent a general notice letter to BGE and 19 other parties identifying them as potentially liable parties at the site. In March 2004, we and other potentially responsible parties formed the 68th Street Coalition, which has entered into consent order negotiations with the EPA to investigate clean-up options for the site under the Superfund Alternative Sites Program. While negotiations under this program are ongoing, the 68th Street Dump will not be placed on the NPL. At this stage, it is not possible to predict the outcome of those discussions or our share of the liability. However, the costs could have a material effect on our financial results.

Kane and Lombard

The EPA issued its ROD for the Kane and Lombard Drum site located in Baltimore, Maryland on September 30, 2003. The ROD specifies the clean-up plan for the site, consisting of enhanced reductive dechlorination, a soil management plan, and institutional controls. In July 2004, the EPA issued a Special Notice/Demand Letter to BGE and three other potentially responsible parties regarding implementation of the remedy. In response, the potentially responsible parties have begun negotiations with the EPA regarding the implementation. The total clean-up costs are estimated to be approximately $10 million. We estimate our current share of site-related costs to be 11.1% of the total. In December 2002, we recorded a liability in our Consolidated Balance Sheets for our share of the clean-up costs that we believe is probable. Our final share of the $10 million has not been determined and it may vary from the current estimate.

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Spring Gardens

In December 1996, BGE signed a consent order with the Maryland Department of the Environment that requires it to implement remedial action plans for contamination at and around the Spring Gardens site, located in Baltimore, Maryland. The Spring Gardens site was once used to manufacture gas from coal and oil. Based on the remedial action plans, BGE estimates its probable clean-up costs will total $47 million. BGE has recorded these costs as a liability in its Consolidated Balance Sheets and has deferred these costs, net of accumulated amortization and amounts it recovered from insurance companies, as a regulatory asset. Based on the results of studies at this site, it is reasonably possible that additional costs could exceed the amount BGE has recognized by approximately $14 million. Through September 30, 2005, BGE has spent approximately $40 million for remediation at this site.

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

Air Quality

In late July 2005, we received two Notices of Violation (NOVs) from the Placer County Air Pollution Control District, Placer County California (District) alleging that the Rio Bravo Rocklin facility located in Lincoln, California had violated certain District air emission regulations. We have a combined 50% ownership interest in the partnership which owns the Rio Bravo Rocklin facility. The NOVs allege a total of 38 violations between January 2003 and March 2005 of either the facility's air permit or federal, state, and county air emission standards related to NO_x, carbon monoxide, and particulate emissions, as well as violations of certain monitoring and reporting requirements during that time period. The maximum civil penalties for the alleged violations range from $10,000 to $40,000 per violation. Management of the Rio Bravo Rocklin facility is currently evaluating the allegations in the NOVs; and therefore, it is not possible to determine the actual liability, if any, of the partnership that owns the Rio Bravo Rocklin facility.

Legal Proceedings

Western Power Markets

James M. Millar v. Allegheny Energy Supply, Constellation Power Source, Inc., High Desert Power Project, LLC, et al.—On December 19, 2003, plaintiffs filed an amended complaint in Superior Court of California, County of San Francisco, naming for the first time, Constellation Power Source, Inc., renamed Constellation Energy Commodities Group, Inc. (CCG), and High Desert Power Project, LLC (High Desert), two of our subsidiaries, as additional defendants. The complaint is a putative class action on behalf of California electricity consumers and alleges that the defendant power suppliers, including CCG and High Desert, violated California's Unfair Competition Law in connection with certain long-term power contracts that the defendants negotiated with the California Department of Water Resources in 2001 and 2002. The Court recently granted the defendants' motion to dismiss the action based on the Court's lack of jurisdiction over the claims in question. No appeal will be filed; therefore, the action is resolved.

City of Tacoma v. AEP, et al.,—The City of Tacoma, on June 7, 2004, in the U.S. District Court, Western District of Washington, filed a complaint against over 60 companies, including CCG. The complaint alleges that the defendants engaged in manipulation of electricity markets resulting in prices for power in the western power markets that were substantially above what market prices would have been in the absence of the alleged unlawful contracts, combinations and conspiracy in violation of Section 1 of the Sherman Act. The complaint further alleges that the total amount of damages is unknown, but is estimated to exceed $175 million. On February 11, 2005, the Court granted the defendants' motion to dismiss the action based on the Court's lack of jurisdiction over the claims in question. The plaintiff has appealed the dismissal of the action to the Ninth Circuit Court of Appeals. We believe that we have meritorious defenses to this action and intend to defend against it vigorously. However, we cannot predict the timing, or outcome, of this case, or its possible effect on our financial results.

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Wholesale Electricity Antitrust Cases

In connection with a proceeding originally filed in March 2002, Reliant Energy Services (Reliant) and certain of its affiliates filed to join CCG and 29 other companies as cross-defendants in a proceeding entitled Wholesale Electricity Antitrust Cases I and II, which is now pending in the Superior Court of the State of California, County of San Diego, Case Nos. 4204 and 4205. The proceeding is a putative class action brought by various plaintiffs on behalf of California residents and alleges claims under certain California antitrust and fair competition laws. In general, the plaintiffs allege that Reliant and the other original defendants engaged in certain anti-competitive actions causing prices not reflective of market in the California electricity markets. Motions to dismiss the claims filed against the original defendants were recently granted. No action is required by CCG or the other cross-defendants until a determination is made as to whether the original defendants intend to pursue or dismiss the cross claims filed against CCG and the 29 other cross defendants. We believe that we have meritorious defenses to this action and intend to defend against it vigorously. However, we cannot predict the timing, or outcome, of this case, or its possible effect on our financial results.

Mercury

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

        In a ruling applicable to all but six of the cases, involving claims related to approximately 49 children, the Circuit Court for Baltimore City dismissed with prejudice all claims against BGE and Constellation Energy and entered into a stay of the proceedings as they relate to other defendants. Plaintiffs may attempt to pursue appeals of the rulings in favor of BGE and Constellation Energy once the cases are finally concluded as to all defendants. We believe that we have meritorious defenses and intend to defend the actions vigorously. However, we cannot predict the timing, or outcome, of these cases, or their possible effect on our, or BGE's, financial results.

Employment Discrimination

Miller, et. al. v. Baltimore Gas and Electric Company, et al.—This action was filed on September 20, 2000 in the U.S. District Court for the District of Maryland. Besides BGE, Constellation Energy, Constellation Nuclear Power Plants, Inc. and Calvert Cliffs Nuclear Power Plant, Inc. 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, Inc. The parties have reached a settlement which has been approved by the Court. Under the settlement, Calvert Cliffs Nuclear Power Plant, Inc. will modify certain employment practices and we have agreed to pay a settlement amount that is not material to our financial results.

Asbestos

Since 1993, BGE has been involved in several actions concerning asbestos. These actions are based on the theory of "premises liability," alleging that BGE knew of and exposed individuals to asbestos in the course of the construction of certain power plants constructed by independent contractors on behalf of BGE.

        BGE and numerous other parties are defendants in these cases. Approximately 504 individuals who were never employees of BGE have pending claims each seeking several million dollars in compensatory and punitive damages. Cross-claims and third party claims brought by other defendants may also be filed against BGE in these actions. To date, claims of 43 asbestos plaintiffs have been settled for amounts that were not significant and approximately 388 were dismissed without payment. The remaining claims are currently pending in state courts in Maryland and Pennsylvania.

        BGE does not know the specific facts necessary for it to assess its potential liability for the above referenced pending cases, such as the identity of the facilities at which the plaintiffs allegedly worked as contractors, the names of plaintiffs' employers, the dates on which the exposure allegedly occurred and the facts and circumstances relating to the alleged exposure.

        Until the relevant facts for the above referenced pending cases are established, we cannot determine if the pending cases will be dismissed prior to trial, be postponed, or be settled, and 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.

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        There has been no activity related to certain third party claims filed against BGE by Pittsburgh Corning Corp. (PCC) since PCC filed bankruptcy in April 2000. In addition, we do not believe that any amounts payable under claims made by PCC would have a material effect on our, or BGE's, financial results.

Canadian Environmental Class Action

Christopher M. Robinson, et. al. v. Ontario Power Generation Inc., et. al.—On June 30, 2005, three individuals filed a class action in the Superior Court of Justice in Ontario, Canada against 21 companies, including Constellation Power Source Generation, Inc. (CPSG), one of our subsidiaries. The complaint alleges claims on behalf of residents of Ontario, Canada that have allegedly suffered adverse health effects as a result of emissions of sulfur dioxide, nitrogen oxide, and particulate matter from approximately 60 different coal-fired power plants operating in Ontario, Michigan, Ohio, Pennsylvania, Kentucky, and West Virginia. CPSG is named as a defendant as a result of its minority ownership interests in two coal-fired power plants located in Pennsylvania. The complaint requests past damages of approximately Cdn$50 billion plus future annual damages of approximately Cdn$4 billion until trial. We believe that we have meritorious defenses to this action and intend to defend against it vigorously. We cannot predict the timing, or outcome, of this case, or its possible effect on our financial results.

Insurance

Our nuclear and non-nuclear property insurance policies were renewed effective July 1, 2005. Our non-nuclear property insurance annual aggregate limit for non-certified acts of terrorism increased to $1 billion from $333.3 million. Our excess nuclear property coverage changed to include a clause where Calvert Cliffs and Nine Mile Point share $1 billion of total excess coverage in the unlikely event of two property losses exceeding the full limit. In addition, our nuclear liability insurance was impacted by the Energy Policy Act of 2005, which renewed the Price-Anderson Act and increased the limit of annual liability per incident at any commercial reactor in the country.

        Below is a description of our current coverage for nuclear liability insurance and nuclear and non-nuclear property insurance.

Nuclear Liability Insurance

Pursuant to the Price-Anderson Act, we are required to insure against public liability claims resulting from nuclear incidents to the full limit of public liability. This limit of liability consists of the maximum available commercial insurance of $300 million and mandatory participation in an industry-wide retrospective premium assessment program. The retrospective premium assessment is $100.6 million per reactor, increasing the total amount of insurance for public liability to approximately $10.8 billion. Under the retrospective assessment program, we can be assessed up to $503 million per incident at any commercial reactor in the country, payable at no more than $75 million per incident per year. This assessment also applies in excess of our worker radiation claims insurance and is subject to inflation and state premium taxes. Claims resulting from non-certified acts of terrorism are limited to the commercial insurance discussed above, regardless of the number of nuclear plants affected. In addition, the U.S. Congress could impose additional revenue-raising measures to pay claims.

Non-Nuclear Property Insurance

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

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Nuclear Property Insurance

Our policies provide $500 million in primary coverage at each nuclear plant—Calvert Cliffs, Nine Mile Point, and Ginna. In addition, we maintain $1.77 billion of excess coverage at Ginna and $2.25 billion in excess coverage under a blanket excess program offered by the industry mutual insurer at both Calvert Cliffs and Nine Mile Point. Under the blanket excess policy, Calvert Cliffs and Nine Mile Point share $1.0 billion of the total $2.25 billion of excess property coverage. Therefore, in the unlikely event of two full limit property damage losses at Calvert Cliffs and Nine Mile Point, we would recover $4.5 billion instead of $5.5 billion. This coverage currently is purchased through the 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 $92.3 million.

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

        We discuss our other nuclear insurance programs in Note 12 of our 2004 Annual Report on Form 10-K.

SFAS No. 133 Hedging Activities

We are exposed to market risk, including changes in interest rates and the impact of market fluctuations in the price and transportation costs of electricity, natural gas, and other commodities. We discuss our market risk in more detail in our 2004 Annual Report on Form 10-K.

Interest Rates

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

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

        "Accumulated other comprehensive income" includes net unrealized pre-tax gains on interest rate cash-flow hedges totaling $16.1 million at September 30, 2005 and $18.3 million at December 31, 2004. 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. We had no hedge ineffectiveness on these swaps.

        During 2004, to optimize the mix of fixed and floating-rate debt, we entered into interest rate swaps qualifying as fair value hedges relating to $450 million of our fixed-rate debt maturing in 2012 and 2015, and converted this notional amount of debt to floating-rate. The fair value of these hedges was $11.1 million at September 30, 2005 and $13.3 million at December 31, 2004 and was recorded as an increase in our "Risk management assets" and "Long-term debt." We have not recognized any hedge ineffectiveness on these interest rate swaps.

Commodity Prices

At September 30, 2005, our merchant energy business had designated certain purchase and sale contracts as cash-flow hedges of forecasted transactions for the years 2005 through 2015 under SFAS No. 133.

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

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        At September 30, 2005, our merchant energy business had net unrealized pre-tax gains of $692.6 million on these hedges recorded in "Accumulated other comprehensive income." We expect to reclassify $1,522.9 million of net pre-tax gains on cash-flow hedges from "Accumulated other comprehensive income" into earnings during the next twelve months based on the market prices at September 30, 2005. However, the actual amount reclassified into earnings could vary from the amounts recorded at September 30, 2005 due to future changes in market prices.

        We recognized into earnings a pre-tax loss of $4.8 million for the quarter ended September 30, 2005 and a pre-tax loss of $6.6 million for the quarter ended September 30, 2004 related to the ineffective portion of our hedges.

        We recognized into earnings a pre-tax loss of $3.6 million for the nine months ended September 30, 2005 and a pre-tax loss of $1.9 million for the nine months ended September 30, 2004 related to the ineffective portion of our hedges. In addition, during the nine months ended September 30, 2005, we terminated a contract previously designated as a cash-flow hedge. The forecasted transaction originally hedged is no longer probable and as a result we recognized a pre-tax loss of $6.1 million.

        Our merchant energy business also enters into natural gas storage contracts under which the gas in storage qualifies for fair value hedge accounting treatment under SFAS No. 133. For the quarter ended September 30, 2005, we had unrealized pre-tax gains of $7.8 million and unrealized pre-tax losses of $11.4 million due to hedge ineffectiveness, resulting in a pre-tax net loss of $3.6 million recognized into earnings. For the nine months ended September 30, 2005, we had unrealized pre-tax gains of $10.4 million and unrealized pre-tax losses of $13.5 million due to hedge ineffectiveness, resulting in a pre-tax loss of $3.1 million recognized into earnings. We record the changes in fair value of these hedges as a component of "Fuel and purchased energy expenses" in our Consolidated Statements of Income.

Accounting Standards Issued

SFAS No. 123 Revised

In December 2004, the FASB issued SFAS No. 123 Revised (SFAS No. 123R), Share-Based Payment. SFAS No. 123R revises SFAS No. 123, Accounting for Stock-Based Compensation, and supersedes APB No. 25, Accounting for Stock Issued to Employees. SFAS No. 123R requires companies to recognize compensation expense for all equity-based compensation awards issued to employees. Equity-based compensation awards include stock options, restricted stock, and any other share-based payments. Under SFAS No. 123R, we must recognize compensation cost over the period during which an employee is required to provide service in exchange for the award. We will estimate the fair value of employee stock options using option-pricing models adjusted for the unique characteristics of those instruments.

        We previously disclosed in our 2004 Annual Report on Form 10-K that we planned to adopt SFAS No. 123R effective July 1, 2005. The Securities and Exchange Commission issued Final Rule 74 in April 2005, which delayed the required implementation of SFAS No. 123R until January 1, 2006.

        We have determined that we will early adopt SFAS No. 123R in the fourth quarter of 2005 using the Modified Prospective Application method without restatement of prior periods. Under this method, we will begin to amortize compensation cost for the remaining portion of our outstanding awards for which the requisite service has not yet been rendered. Compensation cost for these awards will be based on the fair value of those awards as disclosed on a pro-forma basis under SFAS No. 123 in the Stock-Based Compensation section on page 13. We will account for awards that are granted, modified, or settled after October 1, 2005 in accordance with SFAS No. 123R.

        We do not expect the impact of this standard on our ongoing operating results will be materially different than the results as disclosed on a pro-forma basis in the Stock-Based Compensation section on page 13. Based on our analysis to date, we anticipate that other than the requirement for expensing stock options, our share-based awards will continue to be accounted for substantially as they are currently. We also expect to recognize a small, favorable cumulative effect of change in accounting principle due to the requirement to reduce compensation expense for estimated forfeitures relating to outstanding unvested service-based restricted stock awards and performance-based restricted stock and unit awards at October 1, 2005.

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FIN 47

In March 2005, the FASB issued FIN 47, Accounting for Conditional Asset Retirement Obligations—an interpretation of FASB Statement No. 143. FIN 47 is effective December 31, 2005. FIN 47 clarifies that asset retirement obligations that are conditional upon a future event are subject to the provisions of SFAS No. 143. Under SFAS No. 143, we are required to recognize an estimated liability for legal obligations associated with the retirement of tangible long-lived assets. Based on the analysis performed to date, which has not been finalized, we have identified conditional asset retirement obligations relating primarily to asbestos removal at certain of our generating facilities. We estimate that the asset retirement obligations for these facilities will total approximately $10 to $15 million and will result in approximately a $5 to $10 million after-tax charge to earnings as a cumulative effect of change in accounting principle. Currently, we do not expect the adoption of FIN 47 to have a material impact on BGE's financial results. We are still evaluating the impact of FIN 47 and therefore the actual impact of FIN 47 on our, or BGE's, financial results could differ from the above estimates.

Accounting Standards Adopted

SFAS No. 153

In December 2004, the FASB issued SFAS No. 153, Exchanges of Nonmonetary Assets, an amendment of APB Opinion No. 29. SFAS No. 153 amends APB Opinion No. 29 to require nonmonetary exchanges to be measured at the fair value of the exchanged assets unless the transaction does not have commercial substance. SFAS No. 153 was effective for nonmonetary exchanges occurring after June 30, 2005. The adoption of this standard did not have a material impact on our financial results.

Related Party Transactions—BGE

Income Statement

BGE provides standard offer service to those customers that do not choose an alternative electric supplier. Our wholesale marketing and risk management operation provided BGE with the energy and capacity required to meet its commercial and industrial standard offer service obligations through June 30, 2004, and provides the energy and capacity required to meet its residential standard offer service obligations through June 30, 2006. Bidding to supply BGE's standard offer service to commercial and industrial customers beyond June 30, 2004, and to residential customers beyond June 30, 2006, will occur from time to time through a competitive bidding process approved by the Maryland Public Service Commission. Our wholesale marketing and risk management operation is supplying a portion of BGE's standard offer service obligation to commercial and industrial customers.

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

	Quarter Ended September 30,				Nine Months Ended September 30,
	2005		2004		2005		2004
	(In millions)
Purchased energy	$	248.7	$	281.7	$	647.2	$	776.2

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

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

	Quarter Ended September 30,				Nine Months Ended September 30,
	2005		2004		2005		2004
	(In millions)
Charges to BGE	$	28.4	$	27.9	$	81.1	$	70.8

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 $117.1 million at September 30, 2005 and $127.9 million at December 31, 2004 under this arrangement.

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

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

26

Item 2. Management's Discussion

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

Introduction and Overview

Constellation Energy Group, Inc. (Constellation Energy) is a North American energy company that conducts its business through various subsidiaries including a merchant energy business and Baltimore Gas and Electric Company (BGE). We describe our operating segments in the Notes to Consolidated Financial Statements on page 15.

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

        Our 2004 Annual Report on Form 10-K includes a detailed discussion of various items impacting our business, our results of operations, and our financial condition. These include:

•

Introduction and Overview section which provides a description of our business segments,

•

Strategy section,

•

Business Environment section, including how regulation, weather, and other factors affect our business, and

•

Critical Accounting Policies section.

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

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

•

factors which affect our businesses,

•

our earnings and costs in the periods presented,

•

changes in earnings and costs between periods,

•

sources of earnings,

•

impact of these factors on our overall financial condition,

•

expected future expenditures for capital projects, and

•

expected sources of cash for further capital expenditures.

        As you read this discussion and analysis, refer to our Consolidated Statements of Income on page 3, which present the results of our operations for the quarters and nine months ended September 30, 2005 and 2004. We analyze and explain the differences between periods in the specific line items of our Consolidated Statements of Income.

        We have organized our discussion and analysis as follows:

•

We describe changes to our business environment during the year.

•

We highlight significant events that occurred in 2005 that are important to understanding our results of operations and financial condition.

•

We then review our results of operations beginning with an overview of our total company results, followed by a more detailed review of those results by operating segment.

•

We review our financial condition, addressing our sources and uses of cash, capital resources, commitments, and liquidity.

•

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

Business Environment

With the evolving regulatory environment surrounding customer choice, increasing competition, and the growth of our merchant energy business, various factors affect our financial results. We discuss these various factors in the Forward Looking Statements section on page 53. We discuss our market risks in the Market Risk section on page 50.

        In this section, we discuss in more detail events which have impacted our business during the nine months ended September 30, 2005.

Regulation by the Maryland PSC

Base Rates

On April 29, 2005, BGE filed an application for a $52.7 million annual increase in our gas base rates. The Maryland Public Service Commission (Maryland PSC) held hearings on our application in September 2005 and is expected to issue an order by late December 2005. We cannot provide assurance that the Maryland PSC will approve the rate increase request, or if it does, that it will grant BGE the full amount requested.

Standard Offer Service—Provider of Last Resort (POLR)

In June 2005, BGE, along with other parties, requested the Maryland PSC to extend POLR service through May 2008 for those commercial and industrial customers for which market-based standard offer service is scheduled to expire at the end of May 2006. The Maryland PSC held hearings in August 2005 to consider the request, and in September 2005, issued an order extending the service through May 2007 on substantially the same terms as under the existing service, except that wholesale bidding for service to some customers would be conducted more frequently. The extension of the POLR service for these commercial and industrial customers is not expected to have a material impact on our, or BGE's, financial results.

27

        We discuss Standard Offer Service—Provider of Last Resort in more detail in Item 1. Business—Electric Regulatory Matters and Competition section of our 2004 Annual Report on Form 10-K.

Regulation in Other States

Proposition 80 has been placed on the ballot for the November 8, 2005 special election in California. If passed and enacted into law, Proposition 80 would greatly expand the California Public Utility Commission's authority over competitive supply providers in California. At this time we cannot determine the likelihood of success of the ballot initiative or, if enacted, the ultimate effect of Proposition 80 on the California business of our competitive supply operation. However, if enacted, Proposition 80 could have a material effect on our financial results.

Federal Regulation

Federal Energy Regulatory Commission (FERC)

In May 2005, FERC issued an order accepting BGE's joint application to have network transmission rates established through a formula that tracks costs instead of through fixed rates. The formula approach was effective as of June 1, 2005, and the implementation of these rates did not have a material effect on our, or BGE's, financial results. The use of the formula approach that was implemented is subject to refund based on the outcome of a hearing before an administrative law judge. We cannot predict the outcome of this hearing or whether FERC will ultimately affirm the judge's decision.

        In November 2004, FERC eliminated through and out transmission rates between the Midwest Independent System Operators (MISO) and PJM Interconnection (PJM) territories and put in place Seams Elimination Charge/Cost Adjustment/Assignment (SECA) transition rates, which are paid by the transmission customers of MISO and PJM and allocated among the various transmission owners in PJM and MISO. The SECA transition rates are in effect from December 1, 2004 through March 31, 2006. FERC has set for hearing the various compliance filings that established the level of the SECA rates and indicated that the SECA rates are being recovered from the MISO and PJM transmission customers subject to refund by the MISO and PJM transmission owners. In addition, FERC has indicated that the transmission customers that are charged the SECA rates will be provided an opportunity to demonstrate that such charges should be shifted to their wholesale power suppliers. Various Constellation entities are recipients of SECA payments, payers of SECA charges, and suppliers to whom such charges may be shifted. We are unable to predict the timing or outcome of FERC's SECA rate proceeding. However, as the amounts collected under the SECA rates are subject to refund and the ultimate outcome of the proceeding establishing SECA rates is uncertain, the result of this proceeding may have a material effect on our financial results.

Federal Energy Legislation

The Energy Policy Act of 2005 was signed by the President on August 8, 2005. The legislation encourages investments in energy production and delivery infrastructure, including further development of competitive wholesale energy markets, and promotes the use of a diverse mix of fuels and renewable technologies to generate electricity, including federal support and tax incentives for clean coal, nuclear, and renewable power generation. Effective February 2006, the legislation repeals the Public Utility Holding Company Act of 1935. We are still reviewing all aspects of the legislation. In addition, there are a number of FERC rulemaking proceedings in process or being contemplated relating to the implementation of the legislation. We cannot predict the timing or outcome of these proceedings, or their possible effect on our financial results.

Environmental Matters

Air Quality

National Ambient Air Quality Standards (NAAQS)

The NAAQS are federal air quality standards that establish maximum ambient air concentrations for the following specific pollutants: ozone (smog), carbon monoxide, lead, particulates, sulfur dioxide (SO₂), and nitrogen dioxide (NO₂). Our generating facilities are primarily affected by ozone and particulates standards. Ozone is formed when sunlight interacts with emissions of nitrogen oxides (NO_x) and volatile organic compounds (such as from motor vehicle exhaust). Our generating facilities are subject to various permits and programs meant to achieve or preserve attainment of the standards for all these pollutants.

28

        In order for states to achieve compliance with the NAAQS, the Environmental Protection Agency (EPA) adopted the Clean Air Interstate Rule (CAIR) in March 2005 to further reduce ozone and fine particulate pollution by addressing the interstate transport of SO₂ and NO_x emissions from fossil fuel-fired plants located primarily in the Eastern United States. The NO_x reduction requirements will be phased-in starting in 2009 with both annual and ozone season reduction requirements. The phase-in will be complete by 2015. The SO₂ reduction requirements will be phased-in starting in 2010 with the phase-in complete by 2015. According to the EPA, when fully implemented, CAIR will reduce SO₂ emissions in the affected states by over 70 percent and reduce NO_x emissions by over 60 percent from 2003 levels. Although CAIR provides the overall reduction requirements for SO₂ and NO_x, we do not yet know the impact on our facilities as that will be determined by the affected states in which our facilities operate. We are in the process of evaluating the impact of the rules on our financial results based on the information currently available to us.

        In addition, CAIR is subject to legal challenges filed by the states and industry and environmental groups. We cannot predict the timing or outcome of these challenges, or their possible effect on our financial results. As of the filing date of this report, we believe that the environmental capital expenditure estimates provided in Item 1. Business—Environmental Matters in our 2004 Annual Report on Form 10-K remain reasonable projections. Additional federal and/or state legislation or regulation requiring further emission reductions from our facilities could be adopted, which may require us to incur additional environmental capital expenditures.

        In May 2005, the EPA adopted a stricter NAAQS for ozone. States will be required to submit plans to the EPA to meet the new standard by 2007, at which time the standard will take effect. We are unable to determine the impact that complying with the stricter NAAQS for ozone will have on our financial results until the states in which our generating facilities are located adopt plans to meet the new standard. In transitioning to the stricter NAAQS for ozone, the EPA has delayed the requirement that states impose fees on generating facilities located in areas that have not met the NAAQS for ozone. Such fees could have been assessed on certain of our generating facilities located in Maryland and California beginning in 2006, but now will not be assessed prior to 2010.

        In June 2005, the EPA finalized its rules relating to regional haze, which address emissions of SO₂, NO_x, and particulate matter. However, adoption of CAIR by states is expected to meet the emissions reduction requirements under the regional haze rules. We expect Maryland and Pennsylvania, where we own several generating facilities, to adopt CAIR. As a result, we believe the adoption of the regional haze rules by the EPA will not have a material effect on our financial results.

Hazardous Air Emissions

The Clean Air Act requires the EPA to evaluate the public health impacts of hazardous air emissions from electric steam generating facilities. In March 2005, the EPA finalized regulations to reduce the emissions of mercury from coal-fired facilities. Under the Clean Air Mercury Rule (CAMR), the EPA has decided to regulate mercury through a market-based cap and trade program that will reduce nationwide utility emissions of mercury in two phases. Unlike the proposed rule, the final CAMR does not address emissions of nickel. The first phase of the program will begin in 2010. Additional mercury reductions will be required in the second phase of the program starting in 2018. According to the EPA, the CAMR will reduce mercury emissions from all affected coal-fired power plants by about 19 percent from 1999 levels in 2010, mostly from controls installed to comply with CAIR. The EPA expects total mercury reductions from all affected coal-fired plants of about 69 percent from 1999 levels by 2018.

        The CAMR will affect all coal or waste coal fired boilers at our generating facilities. Although our planned capital expenditures for compliance with CAIR are anticipated to enable us to substantially meet the mercury reduction requirements under the first phase of the cap and trade program, the overall cost of compliance with the CAMR, including complying with the requirements under the second phase of the program, could be material. We are currently evaluating the impact of the rule on our financial results. In addition, CAMR is subject to legal challenges filed by the states, industry, and environmental groups. We cannot predict the timing or outcome of these challenges, or their possible effect on our financial results.

        You will find details of our environmental matters in the Environmental Matters section of the Notes to Consolidated Financial Statements beginning on page 20 and in our 2004 Annual Report on Form 10-K in Item 1. Business—Environmental Matters.

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 25.

29

Events of 2005

Commodity Prices

During the quarter ended September 30, 2005, the energy markets were affected by higher commodity prices caused by a tight supply and demand balance, the impact of hot weather, and hurricane-related supply disruptions of the Gulf Coast energy infrastructure. These events contributed to changes in our financial statements as follows:

•

total mark-to-market assets increased $1,921.7 million and total mark-to-market liabilities increased $1,859.3 million since December 31, 2004,

•

total risk management assets increased $1,847.0 million and total risk management liabilities increased $1,430.9 million since December 31, 2004,

•

customer deposits and collateral increased $567.2 million since December 31, 2004,

•

accumulated other comprehensive income increased $507.9 million since December 31, 2004,

•

total merchant revenues increased $1,458.9 million during the quarter ended September 30, 2005 compared to the same period of 2004, and

•

total merchant fuel and purchased energy expenses increased $1,552.7 million during the quarter ended September 30, 2005 compared to the same period of 2004.

        We discuss the impact of higher commodity prices on our financial condition and results of operations in more detail in the following sections:

•

Merchant Energy Results beginning on page 32,

•

Financial Condition on page 46,

•

Contractual Payment Obligations and Committed Amounts on page 48, and

•

Market Risk beginning on page 50.

        We discuss factors that could impact our financial results in the Forward Looking Statements section on page 53.

Discontinued Operations

In June 2005, we sold our Oleander generating facility and in September 2005, we entered into an agreement to sell Constellation Power International Investments, Ltd. Our international investments included our interests in a Panamanian electric distribution facility and a fund that holds interests in two South American energy projects.

        We discuss the sale of the Oleander generating facility and our international investments in more detail in the Notes to Consolidated Financial Statements beginning on page 14.

Business Combination and Asset Acquisition

In April 2005, we acquired Cogenex Corporation and in June 2005, we acquired working interests in gas producing fields in Texas and Alabama.

        We discuss these transactions in more detail in the Notes to Consolidated Financial Statements on page 15.

Pension Plan Assets

Our actual return on pension plan assets was 4.2% through September 30, 2005. In addition, we contributed $50 million, or approximately $30 million after-tax, to our pension plans in 2005.

        If pension plan assets earn 2.25% during the fourth quarter of 2005, or one-fourth of our 9% annual return on pension assets assumption, and interest rates remain at current levels, an after-tax charge to equity of approximately $20 million would be recorded at December 31, 2005 to increase our additional minimum pension liability. This primarily results from the decline in interest rates since year-end 2004, which in turn increases our pension liability. The amount ultimately recorded will be determined by our actual 2005 return on pension plan assets, which depends on the performance of the financial markets during 2005, and our discount rate assumption, which depends on year-end interest rates. As a result, the charge to equity, if any, could be materially different than our current estimate.

30

Results of Operations for the Quarter and Nine Months Ended
September 30, 2005 Compared with the Same Periods of 2004

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. We discuss changes in other income, fixed charges, and income taxes, as necessary, in the aggregate for all segments in the Consolidated Nonoperating Income and Expenses section on page 45.

Overview

Results

		Quarter Ended September 30,						Nine Months Ended September 30,
		2005			2004			2005			2004
		(In millions, after-tax)
Merchant energy		$	141.7		$	183.5		$	282.9		$	327.4
Regulated electric			51.1			36.8			120.0			107.1
Regulated gas			(8.6	)		(8.8	)		17.3			15.7
Other nonregulated			(0.1	)		(6.7	)		0.3			(9.6	)
Income from Continuing Operations			184.1			204.8			420.5			440.6
	Income (loss) from discontinued operations (see Notes)		1.4			5.6			7.4			(35.8	)
Net Income		$	185.5		$	210.4		$	427.9		$	404.8
Other Items Included in Operations (after-tax)
	Non-qualifying hedges	$	(22.8	)	$	(1.8	)	$	(34.5	)	$	(5.3	)
	Workforce reduction costs		(2.3	)		—			(2.3	)		—
	Recognition of 2003 synthetic fuel tax credits		—			—			—			35.9
Total Other Items		$	(25.1	)	$	(1.8	)	$	(36.8	)	$	30.6

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

Quarter Ended September 30, 2005

Our total net income for the quarter ended September 30, 2005 decreased $24.9 million, or $0.16 per share, compared to the same period of 2004 mostly because of the following:

•

We had lower earnings of $21.0 million after-tax related to losses on economic, non-qualifying hedges. We discuss these economic, non-qualifying hedges in more detail in the Mark-to-Market Revenues section on page 37.

•

We had lower earnings at our retail competitive supply operation of $14.7 million after-tax primarily due to higher costs to serve fixed-price, load obligations and the absence of bankruptcy settlements that had a favorable impact in 2004.

•

We had lower Competitive Transition Charge (CTC) related earnings of $6.1 million after-tax, primarily resulting from certain commercial customers that have completed their obligation to pay the CTC.

        These decreases were partially offset by the following:

•

We had higher earnings of $14.5 million after-tax at our regulated businesses primarily due to warmer weather during the third quarter of 2005 compared to the same period of 2004.

•

We had higher earnings of approximately $5 million after-tax mostly due to corporate-wide productivity initiatives.

Nine Months Ended September 30, 2005

Our total net income for the nine months ended September 30, 2005 increased $23.1 million, or $0.02 per share, compared to the same period of 2004 mostly because of the following:

•

We recorded a $49.2 million after-tax, or $0.29 per share, loss from discontinued operations on our Hawaiian geothermal facility in the first quarter of 2004 which had a negative impact in that period.

•

We realized higher gross margin from our wholesale marketing and risk management operation, which included the monetization of a power purchase agreement and higher mark-to-market revenues. We discuss our mark-to-market revenues in more detail in the Mark-to-Market Revenues section on page 36.

•

We had higher earnings of $33.8 million after-tax at our Nine Mile Point facility primarily due to productivity cost initiatives.

•

We had higher earnings of $26.7 million after-tax due to lower interest expense resulting from the maturity of $300.0 million in long-term debt and the favorable impact of floating-rate swaps entered into in the second quarter of 2004, and higher interest and investment income due to a higher cash balance and higher decommissioning trust asset earnings.

•

We had higher earnings of $14.5 million after-tax at our regulated businesses primarily due to warmer weather during the third quarter of 2005 compared to the same period of 2004.

        These increases were partially offset by the following:

•

Our merchant energy business recognized $35.9 million of 2003 synthetic fuel tax credits in the second quarter of 2004 which had a positive impact in that period.

31

•

We had lower earnings of $29.2 million after-tax related to losses associated with economic hedges that do not qualify for cash-flow hedge accounting treatment.

•

We had lower earnings at our retail competitive supply operation of $17.6 million after-tax primarily due to higher costs to serve fixed-price, load obligations and the absence of bankruptcy settlements that had a favorable impact in 2004.

•

We had lower earnings of $14.5 million after-tax due to lower CTC revenues.

        Earnings per share during the quarter and nine months ended September 30, 2005 was also impacted by additional dilution resulting from the issuance of common stock, including 6.0 million shares issued on July 1, 2004 related to the acquisition of Ginna.

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

Merchant Energy Business

Background

Our merchant energy business is a competitive provider of energy solutions for various customers. We discuss the impact of deregulation on our merchant energy business in Item 1. Business—Competition section of our 2004 Annual Report on Form 10-K.

        We record merchant energy revenues and expenses in our financial results in different periods depending upon which portion of our business they affect. We discuss our revenue recognition policies in the Critical Accounting Policies section and Note 1 of our 2004 Annual Report on Form 10-K. We summarize our policies as follows:

•

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

•

Prior to the settlement of the forecasted transaction being hedged, we record changes in the fair value of contracts designated as cash-flow hedges in other comprehensive income to the extent that the hedges are effective. We record the effective portion of the changes in fair value of hedges in earnings in the period the settlement of the hedged transaction occurs. We record the ineffective portion of the changes in fair value of hedges, if any, in earnings in the period in which the change occurs.

•

We record changes in the fair value of contracts that are subject to mark-to-market accounting in revenues on a net basis in the period in which the change occurs.

        Mark-to-market accounting requires us to make estimates and assumptions using judgment in determining the fair value of our contracts and in recording revenues from those contracts. We discuss the effects of mark-to-market accounting on our revenues in the Mark-to-Market Revenues section on page 36. We discuss mark-to-market accounting and the accounting policies for the merchant energy business further in the Critical Accounting Policies section and in Note 1 of our 2004 Annual Report on Form 10-K.

        During the quarter ended September 30, 2005, the energy markets were affected by higher commodity prices caused by a tight supply and demand balance, the impact of hot weather, and hurricane-related supply disruptions of the Gulf Coast energy infrastructure. We discuss the impact of these events on the results of our merchant energy business in more detail below.

Results

		Quarter Ended September 30,						Nine Months Ended September 30,
		2005			2004			2005			2004
		(In millions)
Revenues		$	4,397.2		$	2,938.3		$	10,312.4		$	7,672.2
Fuel and purchased energy expenses			(3,778.0	)		(2,225.3	)		(8,606.6	)		(6,005.2	)
Operating expenses			(273.4	)		(295.1	)		(931.8	)		(883.2	)
Workforce reduction costs			(3.9	)		—			(3.9	)		—
Depreciation and amortization			(74.3	)		(65.2	)		(202.6	)		(178.0	)
Accretion of asset retirement obligations			(15.8	)		(14.5	)		(46.2	)		(38.1	)
Taxes other than income taxes			(31.3	)		(25.9	)		(81.3	)		(67.1	)
Income from Operations		$	220.5		$	312.3		$	440.0		$	500.6
Income from Continuing Operations (after-tax)		$	141.7		$	183.5		$	282.9		$	327.4
	(Loss) income from discontinued operations (after-tax)		(0.2	)		4.5			2.9			(39.7	)
Net Income		$	141.5		$	188.0		$	285.8		$	287.7
Other Items Included in Operations (after-tax)
	Non-qualifying hedges	$	(22.8	)	$	(1.8	)	$	(34.5	)	$	(5.3	)
	Workforce reduction costs		(2.3	)		—			(2.3	)		—
	Recognition of 2003 synthetic fuel tax credits		—			—			—			35.9
Total Other Items		$	(25.1	)	$	(1.8	)	$	(36.8	)	$	30.6

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

Above amounts include intercompany transactions eliminated in our Consolidated Financial Statements. The Information by Operating Segment section within the Notes to Consolidated Financial Statements on page 16 provides a reconciliation of operating results by segment to our Consolidated Financial Statements.

32

Revenues and Fuel and Purchased Energy Expenses

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

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

•

Mid-Atlantic Region—our fossil, nuclear, and hydroelectric generating facilities and load-serving activities in the PJM Interconnection (PJM) region for which the output is primarily used to serve BGE. This also includes active portfolio management of the generating assets and other physical and financial contractual arrangements, as well as other PJM competitive supply activities.

•

Plants with Power Purchase Agreements—our generating facilities outside the Mid-Atlantic Region with long-term power purchase agreements, including the Nine Mile Point, Ginna, University Park, and High Desert facilities.

•

Retail Competitive Supply—our operation that provides electric and gas energy products and services to commercial and industrial customers.

•

Wholesale Competitive Supply—our marketing and risk management operation that provides energy products and services outside the Mid-Atlantic Region primarily to distribution utilities, power generators, and other wholesale customers.

•

Other—our investments in qualifying facilities and domestic power projects and our operations and maintenance consulting services.

33

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

			Quarter Ended September 30,										Nine Months Ended September 30,
			2005					2004					2005					2004
			(Dollar amounts in millions)
Revenues:
	Mid-Atlantic Region		$	746.7				$	615.7				$	1,736.9				$	1,472.4
	Plants with Power Purchase Agreements			254.6					247.5					639.0					520.9
	Competitive Supply
		Retail		1,990.1					1,082.6					4,713.6					3,062.6
		Wholesale		1,383.0					965.2					3,180.6					2,559.4
	Other			22.8					27.3					42.3					56.9
	Total		$	4,397.2				$	2,938.3				$	10,312.4				$	7,672.2
Fuel and purchased energy expenses:
	Mid-Atlantic Region		$	(563.8	)			$	(318.5	)			$	(1,105.0	)			$	(718.2	)
	Plants with Power Purchase Agreements			(23.7	)				(15.1	)				(57.6	)				(37.6	)
	Competitive Supply
		Retail		(1,938.0	)				(1,014.0	)				(4,530.9	)				(2,871.9	)
		Wholesale		(1,252.5	)				(877.7	)				(2,913.1	)				(2,377.5	)
	Other			—					—					—					—
	Total		$	(3,778.0	)			$	(2,225.3	)			$	(8,606.6	)			$	(6,005.2	)
Gross Margin:						% of Total					% of Total					% of Total					% of Total
	Mid-Atlantic Region		$	182.9		30	%	$	297.2		42	%	$	631.9		37	%	$	754.2		45	%
	Plants with Power Purchase Agreements			230.9		37			232.4		32			581.4		34			483.3		29
	Competitive Supply
		Retail		52.1		8			68.6		10			182.7		11			190.7		11
		Wholesale		130.5		21			87.5		12			267.5		16			181.9		11
	Other			22.8		4			27.3		4			42.3		2			56.9		4
	Total		$	619.2		100	%	$	713.0		100	%	$	1,705.8		100	%	$	1,667.0		100	%

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

34

Mid-Atlantic Region

	Quarter Ended September 30,						Nine Months Ended September 30,
	2005			2004			2005			2004
	(In millions)
Revenues	$	746.7		$	615.7		$	1,736.9		$	1,472.4
Fuel and purchased energy expenses		(563.8	)		(318.5	)		(1,105.0	)		(718.2	)
Gross margin	$	182.9		$	297.2		$	631.9		$	754.2

The decrease in gross margin during the quarter and nine months ended September 30, 2005 compared to the same periods of 2004 is primarily due to a decrease of approximately $104 million mostly because of rising commodity prices and hotter than normal weather in the Mid-Atlantic region, which resulted in higher load-serving costs, and lower CTC revenues. CTC revenues were $10.1 million lower during the quarter ended September 30, 2005 compared to the same period of 2004 and $24.1 million lower during the nine months ended September 30, 2005 compared to the same period of 2004.

        CTC revenues will continue to decrease as residential, commercial, and industrial customers complete their CTC obligation. CTC revenues will be completely phased-out by June 30, 2006. We discuss the change in CTC revenue over time in more detail in our 2004 Annual Report on Form 10-K.

Plants with Power Purchase Agreements

	Quarter Ended September 30,						Nine Months Ended September 30,
	2005			2004			2005			2004
	(In millions)
Revenues	$	254.6		$	247.5		$	639.0		$	520.9
Fuel and purchased energy expenses		(23.7	)		(15.1	)		(57.6	)		(37.6	)
Gross margin	$	230.9		$	232.4		$	581.4		$	483.3

The increase in gross margin during the nine months ended September 30, 2005 compared to the same period of 2004 was primarily due to $71.5 million from Ginna, which was acquired in June 2004. This increase in gross margin at Ginna includes an increase in revenues of $76.5 million. We also had higher gross margin of $27.9 million at our Nine Mile Point facility that benefited from higher generation due to fewer refueling outage days and the absence of an unplanned outage that occurred in January 2004.

Competitive Supply

Retail

	Quarter Ended September 30,						Nine Months Ended September 30,
	2005			2004			2005			2004
	(In millions)
Accrual revenues	$	2,000.6		$	1,080.4		$	4,727.3		$	3,064.4
Mark-to-market revenues		(10.5	)		2.2			(13.7	)		(1.8	)
Fuel and purchased energy expenses		(1,938.0	)		(1,014.0	)		(4,530.9	)		(2,871.9	)
Gross margin	$	52.1		$	68.6		$	182.7		$	190.7

The decrease in gross margin from our retail competitive supply activities during the quarter ended September 30, 2005 compared to the same period of 2004 is primarily due to a combination of higher market prices for electricity and increased customer usage because of the hotter than normal weather, which increased our cost to serve our fixed-price, load-serving obligations. We also had a favorable bankruptcy settlement that had a positive impact in 2004. These decreases in margin were partially offset by serving 6.0 million more megawatt hours in the quarter ended September 30, 2005 compared to the same period of 2004 primarily due to the growth of this operation.

        The decrease in gross margin from our retail competitive supply activities during the nine months ended September 30, 2005 compared to the same period of 2004 is primarily due to a combination of higher market prices for electricity and increased customer usage because of the hotter than normal weather, which increased our cost to serve our fixed-price, load-serving obligations, and favorable bankruptcy settlements that had a positive impact in 2004. These decreases in margin were partially offset by serving 15.7 million more megawatt hours during the nine months ended September 30, 2005 compared to the same period of 2004 primarily due to the growth of this operation.

Wholesale

	Quarter Ended September 30,						Nine Months Ended September 30,
	2005			2004			2005			2004
	(In millions)
Accrual revenues	$	1,264.8		$	912.3		$	2,993.4		$	2,480.7
Fuel and purchased energy expenses		(1,252.5	)		(877.7	)		(2,913.1	)		(2,377.5	)
Wholesale accrual activities		12.3			34.6			80.3			103.2
Mark-to-market revenues		118.2			52.9			187.2			78.7
Gross margin	$	130.5		$	87.5		$	267.5		$	181.9

35

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

Wholesale Accrual Activities

Our wholesale marketing and risk management operation had lower gross margin during the quarter ended September 30, 2005 compared to the same period of 2004 due to a decrease of approximately $18 million primarily in the New England region mostly because of the absence of several favorable items, including settlements, power prices, and contracts that existed in 2004 that had a positive impact in that period.

        Our wholesale marketing and risk management operation's gross margin was lower during the nine months ended September 30, 2005 compared to the same period of 2004 due to a decrease of approximately $74 million primarily in the New England region mostly because of the absence of several favorable items, including settlements, power prices, and contracts that existed in 2004 that had a positive impact in that period, offset by newly originated and realized business in power, gas, and coal in 2005. A substantial portion of newly originated gross margin related to the monetization of a power purchase agreement during the first quarter of 2005. The power purchase agreement would have otherwise delivered through December 2006. This sale for cash allowed us to eliminate performance risk by the counterparty under the original contract.

Mark-to-Market Revenues

Mark-to-market revenues include net gains and losses from origination and risk management activities for which we use the mark-to-market method of accounting. We discuss these activities and the mark-to-market method of accounting in more detail in the Critical Accounting Policies section of our 2004 Annual Report on Form 10-K.

        As a result of the nature of our operations and the use of mark-to-market accounting for certain activities, mark-to-market revenues and earnings will fluctuate. We cannot predict these fluctuations, but the impact on our revenues and earnings could be material. We discuss our market risk in more detail in the Market Risk section on page 50. The primary factors that cause fluctuations in our mark-to-market revenues and earnings are:

•

the number, size, and profitability of new transactions including termination or restructuring of existing contracts,

•

the number and size of our open derivative positions, and

•

changes in the level and volatility of forward commodity prices and interest rates.

        Mark-to-market revenues were as follows:

			Quarter Ended September 30,						Nine Months Ended September 30,
			2005			2004			2005			2004
			(In millions)
Unrealized revenues
	Origination transactions		$	3.2		$	7.5		$	12.8		$	17.1
	Risk management
		Unrealized changes in fair value		104.5			47.6			160.7			59.8
		Changes in valuation techniques		—			—			—			—
		Reclassification of settled contracts to realized		(62.8	)		(17.3	)		(124.6	)		(53.5	)
	Total risk management			41.7			30.3			36.1			6.3
Total unrealized revenues*				44.9			37.8			48.9			23.4
Realized revenues				62.8			17.3			124.6			53.5
Total mark-to-market revenues			$	107.7		$	55.1		$	173.5		$	76.9

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

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

        Origination gains represent the initial fair value recognized on these structured transactions. The recognition of origination gains is dependent on the existence of observable market data that validates the initial fair value of the contract. Origination gains arose from 13 transactions during the quarter ended September 30, 2005, compared to three transactions during the same period of 2004. Origination gains arose from 38 transactions during the nine months ended September 30, 2005, compared to ten transactions during the same period of 2004.

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

36

        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 later in this section.

        Mark-to-market revenues increased $52.6 million during the quarter ended September 30, 2005 compared to the same period of 2004 primarily due to an increase in unrealized changes in fair value mostly because of new contracts entered into and realized during the third quarter of 2005 and changes in the value of open positions as a result of higher commodity prices, price volatility, and other factors. These increases in mark-to-market revenues include changes in the close-out adjustment of $6.6 million during the quarter ended September 30, 2005 compared to the same period of the prior year for transactions that we have now observed sufficient market price information and/or we realized cash flows since the transactions' inception. We discuss the close-out adjustment in more detail in the Critical Accounting Policies section of our 2004 Annual Report on Form 10-K. These increases in mark-to-market revenues were partially offset by the impact of $34.8 million of higher mark-to-market losses on economic hedges that did not qualify for cash-flow hedge accounting treatment. We discuss these non-qualifying hedges in more detail below.

        Mark-to-market revenues increased $96.6 million during the nine months ended September 30, 2005 compared to the same period of 2004 primarily due to an increase in unrealized changes in fair value mostly because of new contracts entered into and realized during the third quarter of 2005 and changes in the value of open positions as a result of higher commodity prices, price volatility, and other factors. These increases in mark-to-market revenues include changes in the close-out adjustment of $43.5 million during the nine months ended September 30, 2005 compared to the same period of the prior year for transactions that we have now observed sufficient market price information and/or we realized cash flows since the transactions' inception. These increases in mark-to-market revenues were partially offset by the impact of $48.2 million of higher mark-to-market losses on economic hedges that did not qualify for cash-flow hedge accounting treatment.

        In the first nine months of 2005, increasing forward prices shifted value between accrual contracts and the associated mark-to-market positions of certain contracts in New England that contain fuel adjustment clauses and gas transport hedges, producing a timing difference in the recognition of earnings on these transactions. These mark-to-market hedges are economically effective; however, they do not qualify for cash-flow hedge accounting under Statement of Financial Accounting Standards (SFAS) No. 133, Accounting for Derivative Instruments and Hedging Activities, as amended. This mark-to-market loss is expected to be offset as we realize the related accrual contracts in cash in future periods.

Mark-to-Market Energy Assets and Liabilities

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

	September 30, 2005		December 31, 2004
	(In millions)
Current Assets	$	1,845.8	$	567.3
Noncurrent Assets		1,003.0		359.8
Total Assets		2,848.8		927.1
Current Liabilities		1,801.5		559.7
Noncurrent Liabilities		932.5		315.0
Total Liabilities		2,734.0		874.7
Net mark-to-market energy asset	$	114.8	$	52.4

        The increases in our gross mark-to-market assets and liabilities were due primarily to higher commodity prices during the third quarter of 2005. These price increases resulted in larger mark-to-market positions with individual counterparties which must be recorded gross in the balance sheet unless a legal right of offset exists.

37

        The following are the primary sources of the change in the net mark-to-market energy asset during the quarter and nine months ended September 30, 2005:

		Quarter Ended September 30, 2005						Nine Months Ended September 30, 2005
		(In millions)
Fair value at beginning of period					$	92.6					$	52.4
Changes in fair value recorded as revenues
	Origination gains	$	3.2					$	12.8
	Unrealized changes in fair value		104.5						160.7
	Changes in valuation techniques		—						—
	Reclassification of settled contracts to realized		(62.8	)					(124.6	)
Total changes in fair value recorded as revenues						44.9						48.9
Changes in value of exchange-listed futures and options						(42.2	)					(70.2	)
Net change in premiums on options						32.6						85.1
Other changes in fair value						(13.1	)					(1.4	)
Fair value at end of period					$	114.8					$	114.8

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

•

Origination gains represent the initial unrealized fair value at the time these contracts are executed to the extent permitted by applicable accounting rules.

•

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

•

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

•

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

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

•

Changes in value of exchange-listed futures and options are adjustments to remove unrealized revenue from exchange-traded contracts that are included in risk management revenues. The fair value of these contracts is recorded in "Accounts receivable" rather than "Mark-to-market energy assets" in our Consolidated Balance Sheets because these amounts are settled through our margin account with a third-party broker.

•

Net changes in premiums on options reflects the accounting for premiums on options purchased as an increase in the net mark-to-market energy asset and premiums on options sold as a decrease in the net mark-to-market energy asset.

        The settlement terms of the net mark-to-market energy asset and sources of fair value as of September 30, 2005 are as follows:

	Settlement Term
	2005			2006			2007			2008			2009			2010			Thereafter		Fair Value
	(In millions)
Prices provided by external sources (1)	$	42.2		$	(52.4	)	$	66.4		$	80.2		$	0.7		$	—		$	—	$	137.1
Prices based on models		(0.9	)		12.7			(3.1	)		(18.8	)		(4.1	)		(8.1	)		—		(22.3	)
Total net mark-to-market energy asset	$	41.3		$	(39.7	)	$	63.3		$	61.4		$	(3.4	)	$	(8.1	)	$	—	$	114.8

(1)

Includes contracts actively quoted and contracts valued from other external sources.

38

        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 on the previous page 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 2008, but up to 2009, depending upon the region,

•

options for the purchase and sale of electricity during peak hours for delivery terms through 2008, depending upon the region,

•

forward purchases and sales of electric capacity for delivery terms primarily through 2006, but up to 2007, depending upon the region,

•

forward purchases and sales of natural gas, coal, and oil for delivery terms primarily through 2007, but up to 2010, depending upon the commodity, and

•

options for the purchase and sale of natural gas, coal, and oil for delivery terms through 2011.

        The remainder of the net mark-to-market energy asset 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 the wholesale marketing and risk management operation are direct contracts between market participants and are not exchange-traded or financially settling contracts that can be readily liquidated in their entirety through an exchange or other market mechanism. Consequently, we and other market participants generally realize the value of these contracts as cash flows become due or payable under the terms of the contracts rather than through selling or liquidating the contracts themselves.

39

        Consistent with our risk management practices, the amounts shown in the table on page 38 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 the wholesale marketing and risk management operation, we expect to realize the value of these contracts, as well as any contracts we may enter into in the future to manage our risk, over time as the contracts and related hedges settle in accordance with their terms. Generally, we do not expect to realize the value of these contracts and related hedges by selling or assigning the contracts themselves in total.

        The fair values in the table represent expected future cash flows based on the level of forward prices and volatility factors as of September 30, 2005 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.

Risk Management Assets and Liabilities

We record derivatives that qualify for designation as hedges under SFAS No. 133 in "Risk management assets and liabilities" in our Consolidated Balance Sheets. Our risk management assets and liabilities consisted of the following:

	September 30, 2005		December 31, 2004
	(In millions)
Current Assets	$	1,963.2	$	471.5
Noncurrent Assets		661.5		306.2
Total Assets		2,624.7		777.7
Current Liabilities		643.7		304.3
Noncurrent Liabilities		1,563.7		472.2
Total Liabilities		2,207.4		776.5
Net risk management asset	$	417.3	$	1.2

        The significant increases in our gross risk management assets and liabilities and our net risk management asset were due primarily to higher commodity prices during the third quarter of 2005. These price increases resulted in larger positions with individual counterparties which must be recorded gross in the balance sheet unless a legal right of offset exists. The increase in our net risk management asset was partially offset by the assumption of below-market power sale agreements in connection with a customer contract restructuring. We discuss the customer contract restructuring transaction in more detail in the Notes to Consolidated Financial Statements beginning on page 11.

Other

	Quarter Ended September 30,				Nine Months Ended September 30,
	2005		2004		2005		2004
	(In millions)
Revenues	$	22.8	$	27.3	$	42.3	$	56.9

Other revenues decreased $14.6 million for the nine months ended September 30, 2005 compared to the same period of 2004 mostly due to a contingent payment received from our synthetic fuel facilities located in Virginia and West Virginia that had a favorable impact in 2004.

        Our merchant energy business holds up to a 50% voting interest in 24 operating domestic energy projects that consist of electric generation, fuel processing, or fuel handling facilities. Of these 24 projects, 17 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.

40

        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 the impact of subsidies from the State of California in more detail in the Merchant Energy Business—Other section in our 2004 Annual Report on Form 10-K.

        We discuss certain risks and uncertainties in more detail in our Forward Looking Statements section on page 53. However, should future events cause these investments to become uneconomic, our investments in these projects could become impaired under the provisions of Accounting Principles Board Opinion (APB) No. 18, The Equity Method of Accounting for Investments in Common Stock.

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

Operating Expenses

Our merchant energy business operating expenses decreased $21.7 million during the quarter ended September 30, 2005 compared to the same period of 2004 mostly due to the following:

•

lower expenses of $20.0 million primarily related to compensation costs, and

•

lower operating expenses of $6.4 million at Nine Mile Point, primarily due to productivity initiatives including a lower number of employees and contractors.

        These decreases in expenses were partially offset by an increase of $7.2 million due to Ginna due to an increase in corporate overhead expense allocations.

        Our merchant energy business operating expenses increased $48.6 million during the nine months ended September 30, 2005 compared to the same period of 2004 mostly due to an increase of $71.0 million from Ginna, which was acquired in June 2004. This increase in expenses was partially offset by lower operating expenses of $36.4 million at Nine Mile Point primarily due to lower refueling outage expenses and a lower number of employees and contractors.

Workforce Reduction Costs

As a result of the workforce reduction efforts initiated in 2004, in the third quarter of 2005 we were required to record a pre-tax settlement charge of $3.9 million for one of our qualified pension plans under SFAS No. 88, Employers' Accounting for Settlements and Curtailments of Defined Benefit Pension Plans and for Termination Benefits. We discuss the workforce reduction efforts initiated in 2004 in more detail in Note 2 of our 2004 Annual Report on Form 10-K. The $3.9 million charge reflects recognition of the portion of deferred actuarial gains and losses associated with employees who were terminated as part of the restructuring or retired in 2005 and who elected to receive their pension benefit in the form of a lump-sum payment. In accordance with SFAS No. 88, a settlement charge must be recognized at the point in time when lump-sum payments exceed annual pension plan service and interest cost, which occurred in the third quarter.

Depreciation and Amortization Expense

Merchant energy depreciation and amortization expense increased $9.1 million during the quarter ended September 30, 2005 compared to the same period of 2004 mostly due to $3.6 million related to our investments in gas producing facilities which were acquired in the second quarter of 2005 and $2.4 million related to our South Carolina synthetic fuel facility.

        Merchant energy depreciation and amortization expenses increased $24.6 million during the nine months ended September 30, 2005 compared to the same period of 2004 mostly due to $8.7 million related to Ginna and a $6.5 million increase related to our South Carolina synthetic fuel facility. We also had a $4.4 million increase in deprecation and amortization related to our investments in gas producing facilities.

Accretion of Asset Retirement Obligations

Merchant energy accretion expenses increased $8.1 million during the nine months ended September 30, 2005 compared to the same period of 2004 mostly due to the recognition of $5.3 million at Ginna.

Taxes Other Than Income Taxes

Merchant energy taxes other than income taxes increased $5.4 million during the quarter ended September 30, 2005 compared to the same period of 2004 mostly due to $5.1 million related to higher gross receipts taxes at our retail electric operation.

        Taxes other than income taxes increased $14.2 million during the nine months ended September 30, 2005 compared to the same period of 2004 mostly due to $8.9 million related to higher gross receipts taxes at our retail electric operation and $3.7 million related to property taxes for Ginna.

41

Regulated Electric Business

Our regulated electric business is discussed in detail in Item 1. Business—Electric Business section of our 2004 Annual Report on Form 10-K.

Results

	Quarter Ended September 30,						Nine Months Ended September 30,
	2005			2004			2005			2004
	(In millions)
Revenues	$	626.8		$	582.0		$	1,583.4		$	1,543.6
Electricity purchased for resale expenses		(362.5	)		(338.4	)		(849.0	)		(833.1	)
Operations and maintenance expenses		(79.6	)		(77.5	)		(235.4	)		(222.9	)
Depreciation and amortization		(46.9	)		(49.2	)		(141.1	)		(145.5	)
Taxes other than income taxes		(34.7	)		(33.9	)		(102.2	)		(100.3	)
Income from Operations	$	103.1		$	83.0		$	255.7		$	241.8
Net Income	$	51.1		$	36.8		$	120.0		$	107.1

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 16 provides a reconciliation of operating results by segment to our Consolidated Financial Statements.

Net income from the regulated electric business increased during the quarter and nine months ended September 30, 2005 compared to the same periods of 2004 mostly due to warmer summer weather.

Electric Revenues

The changes in electric revenues in 2005 compared to 2004 were caused by:

	Quarter Ended September 30, 2005 vs. 2004		Nine Months Ended September 30, 2005 vs. 2004
	(In millions)
Distribution volumes	$	27.5	$	21.2
Standard offer service		10.0		10.7
Total change in electric revenues from electric system sales		37.5		31.9
Other		7.3		7.9
Total change in electric revenues	$	44.8	$	39.8

Distribution Volumes

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

        The percentage changes in our distribution volumes, by type of customer, in 2005 compared to 2004 were:

	Quarter Ended September 30, 2005 vs. 2004		Nine Months Ended September 30, 2005 vs. 2004
Residential	12.7	%	1.8	%
Commercial	8.1		5.5
Industrial	(5.9	)	(10.6	)

        During the quarter ended September 30, 2005 compared to the same period of 2004, we distributed more electricity to residential customers mostly due to warmer weather and an increased number of customers. We distributed more electricity to commercial customers mostly due to warmer weather, increased usage per customer, and an increased number of customers. We distributed less electricity to industrial customers mostly due to decreased usage per customer.

        During the nine months ended September 30, 2005 compared to the same period of 2004, we distributed more electricity to residential customers mostly due to warmer summer weather and an increased number of customers, partially offset by decreased usage per customer. We distributed more electricity to commercial customers mostly due to increased usage per customer, an increased number of customers, and warmer summer weather. We distributed less electricity to industrial customers mostly due to decreased usage per customer.

Standard Offer Service

BGE provides standard offer service for customers that do not select an alternative supplier as discussed in Item 1. Business—Electric Regulatory Matters and Competition section of our 2004 Annual Report on Form 10-K.

        Standard offer service revenues increased during the quarter and nine months ended September 30, 2005 compared to the same periods of 2004 mostly due to warmer summer weather and increased standard offer service rates. For the nine months ended September 30, 2005, the increased revenues were partially offset by decreased revenues due to commercial and industrial customers that elected alternative suppliers beginning July 1, 2004.

Electricity Purchased for Resale Expenses

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

42

        Electricity purchased for resale expenses increased $24.1 million in the quarter and $15.9 million in the nine months ended September 30, 2005 compared to the same periods of 2004 mostly due to increased distribution volumes primarily due to warmer summer weather and increased standard offer service rates. For the nine months ended September 30, 2005, the higher expenses were partially offset by decreased expenses due to commercial and industrial customers that elected alternative suppliers beginning July 1, 2004.

Electric Operations and Maintenance Expenses

Regulated electric operations and maintenance expenses increased $2.1 million in the quarter and $12.5 million in the nine months ended September 30, 2005 compared to the same periods of 2004 mostly due to higher compensation and benefit costs and the impact of inflation on other costs.

Regulated Gas Business

Our regulated gas business is discussed in detail in Item 1. Business—Gas Business section of our 2004 Annual Report on Form 10-K.

Results

	Quarter Ended September 30,						Nine Months Ended September 30,
	2005			2004			2005			2004
	(In millions)
Gas revenues	$	115.9		$	75.3		$	626.9		$	507.4
Gas purchased for resale expenses		(72.1	)		(31.6	)		(422.5	)		(307.1	)
Operations and maintenance expenses		(33.1	)		(30.4	)		(97.1	)		(89.4	)
Depreciation and amortization		(11.7	)		(12.1	)		(35.5	)		(36.4	)
Taxes other than income taxes		(7.2	)		(7.1	)		(24.5	)		(23.8	)
(Loss) income from operations	$	(8.2	)	$	(5.9	)	$	47.3		$	50.7
Net (Loss) Income	$	(8.6	)	$	(8.8	)	$	17.3		$	15.7

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 16 provides a reconciliation of operating results by segment to our Consolidated Financial Statements.

Gas Revenues

The changes in gas revenues in 2005 compared to 2004 were caused by:

	Quarter Ended September 30, 2005 vs. 2004		Nine Months Ended September 30, 2005 vs. 2004
	(In millions)
Distribution volumes	$	0.2	$	(1.3	)
Base rates		—		0.1
Weather normalization		0.6		6.0
Gas cost adjustments		10.2		29.1
Total change in gas revenues from gas system sales		11.0		33.9
Off-system sales		29.6		85.5
Other		—		0.1
Total change in gas revenues	$	40.6	$	119.5

43

Distribution Volumes

The percentage changes in our distribution volumes, by type of customer, in 2005 compared to 2004 were:

	Quarter Ended September 30, 2005 vs. 2004		Nine Months Ended September 30, 2005 vs. 2004
Residential	(6.3	)%	(3.9	)%
Commercial	(9.0	)	(5.4	)
Industrial	57.2		26.2

        During the quarter ended September 30, 2005 compared to the same period in 2004, we distributed less gas to residential and commercial customers mostly due to decreased usage per customer partially offset by an increased number of customers. We distributed more gas to industrial customers mostly due to increased usage per customer.

        During the nine months ended September 30, 2005 compared to the same period of 2004, we distributed less gas to residential and commercial customers mostly due to decreased usage per customer partially offset by an increased number of customers and colder weather in the first six months of 2005. We distributed more gas to industrial customers mostly due to increased usage per customer.

Base Rates

On April 29, 2005, BGE filed an application for a $52.7 million annual increase in our gas base rates. The Maryland PSC held hearings on our application in September 2005 and is expected to issue an order by late December 2005. We cannot provide assurance that the Maryland PSC will approve the rate increase request, or if it does, that it will grant BGE the full amount requested.

Weather Normalization

The Maryland PSC allows us to record a monthly adjustment to our gas distribution revenues to eliminate the effect of abnormal weather patterns on our gas distribution 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 2004 Annual Report on Form 10-K.

        Gas cost adjustment revenues increased during the quarter ended September 30, 2005 compared to the same period of 2004 because we sold more gas at higher prices.

        Gas cost adjustment revenues increased during the nine months ended September 30, 2005 compared to the same period of 2004 because we sold gas at higher prices, partially offset by less gas sold.

Off-System Gas Sales

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

        Revenues from off-system gas sales increased during the quarter and nine months ended September 30, 2005 compared to the same periods of 2004 because we sold more gas at higher prices.

Gas Purchased For Resale Expenses

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

        Gas costs increased during the quarter and nine months ended September 30, 2005 compared to the same periods of 2004 because we purchased more gas at higher prices.

Gas Operations and Maintenance Expenses

Regulated gas operations and maintenance expenses increased $2.7 million in the quarter and $7.7 million in the nine months ended September 30, 2005 compared to the same periods of 2004 mostly due to higher compensation and benefit costs and the impact of inflation on other costs.

44

Other Nonregulated Businesses

Results

		Quarter Ended September 30,						Nine Months Ended September 30,
		2005			2004			2005			2004
		(In millions)
Revenues		$	49.3		$	46.3		$	144.4		$	144.8
Operating expenses			(36.7	)		(47.4	)		(109.1	)		(130.8	)
Depreciation and amortization			(10.4	)		(6.0	)		(28.2	)		(16.2	)
Taxes other than income taxes			(0.6	)		(0.1	)		(1.4	)		(1.3	)
Income (loss) from operations		$	1.6		$	(7.2	)	$	5.7		$	(3.5	)
(Loss) income from continuing operations, after-tax		$	(0.1	)	$	(6.7	)	$	0.3		$	(9.6	)
	Income from discontinued operations, after-tax		1.6			1.1			4.5			3.9
Net Income (Loss)		$	1.5		$	(5.6	)	$	4.8		$	(5.7	)

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

Above amounts include intercompany transactions eliminated in our Consolidated Financial Statements. The Information by Operating Segment section within the Notes to Consolidated Financial Statements on page 16 provides a reconciliation of operating results by segment to our Consolidated Financial Statements.

As previously discussed in our 2004 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 losses.

        In September 2005, we decided to sell Constellation Power International Investments, Ltd. Our international investments include our interests in a Panamanian electric distribution facility and in a fund that holds interests in two South American energy projects.

        We completed the sale of our international investments on October 3, 2005 and we will recognize a pre-tax gain of approximately $23 million, or $15 million after-tax, in the fourth quarter of 2005.

        We discuss the sale of our international investments in more detail in the Notes to Consolidated Financial Statements beginning on page 14.

Consolidated Nonoperating Income
and Expenses

Other Income

Other income increased $16.7 million during the quarter ended September 30, 2005, and $27.9 million during the nine months ended September 30, 2005 compared to the same periods of 2004 primarily because of higher interest and investment income due to a higher cash balance and higher decommissioning trust asset earnings.

Fixed Charges

Total fixed charges decreased $4.1 million during the quarter ended September 30, 2005 and $15.8 million during the nine months ended September 30, 2005 compared to the same periods of 2004 mostly because of the benefit of lower interest rates due to interest rate swaps entered into during the third quarter of 2004 and a lower level of debt outstanding. We discuss the interest rate swaps in more detail in the Notes to Consolidated Financial Statements beginning on page 24.

        During the nine months ended September 30, 2005, total fixed charges at BGE decreased $3.1 million compared to the same period of 2004 mostly because of a lower level of debt outstanding.

Income Taxes

During the quarter ended September 30, 2005, our income taxes decreased $23.7 million compared to the same period of 2004 mostly because of a decrease in taxable income and an increase in synthetic fuel tax credits claimed.

        During the nine months ended September 30, 2005, our income taxes increased $22.9 million compared to the same period of 2004 mostly because of the recognition of $35.9 million synthetic fuel tax credits claimed in 2004 related to 2003 production. This increase was partially offset by $13.4 million of higher synthetic fuel tax credits claimed in 2005 compared to 2004, which reduced our total income taxes. We discuss our synthetic fuel tax credits in more detail in the Notes to Consolidated Financial Statements section on page 18.

        Income taxes at BGE increased $8.3 million during the quarter ended September 30, 2005, and $6.2 million during the nine months ended September 30, 2005 compared to the same periods of 2004 mostly because of an increase in taxable income.

45

Financial Condition

Cash Flows

The following table summarizes our cash flows for 2005 and 2004, excluding the impact of changes in intercompany balances.

		2005 Segment Cash Flows									Consolidated Cash Flows
		Nine Months Ended September 30, 2005									Nine Months Ended September 30,
		Merchant			Regulated			Other			2005			2004
		(In millions)
Operating Activities
	Net income	$	285.8		$	137.3		$	4.8		$	427.9		$	404.8
	Non-cash adjustments to net income		296.5			189.5			28.7			514.7			667.1
	Changes in working capital		208.3			(15.3	)		(38.2	)		154.8			(287.2	)
	Pension and postemployment benefits*											4.0			(8.8	)
	Other		(25.8	)		(24.4	)		48.1			(2.1	)		(26.8	)
Net cash provided by operating activities			764.8			287.1			43.4			1,099.3			749.1
Investing activities
	Investments in property, plant and equipment		(255.5	)		(198.1	)		(23.3	)		(476.9	)		(496.4	)
	Asset acquisitions and business combinations, net of cash acquired		(216.0	)		—			(22.1	)		(238.1	)		(457.0	)
	Contributions to nuclear decommissioning trust funds		(13.2	)		—			—			(13.2	)		(17.7	)
	Proceeds from sale of discontinued operations		217.6			—			—			217.6			72.7
	Sale of investments and other assets		0.1			0.1			1.7			1.9			29.6
	Issuances of loans receivable		(82.8	)		—			—			(82.8	)		—
	Other investments		(41.0	)		(14.6	)		3.4			(52.2	)		(16.3	)
Net cash used in investing activities			(390.8	)		(212.6	)		(40.3	)		(643.7	)		(885.1	)
Cash flows from operating activities less cash flows from investing activities		$	374.0		$	74.5		$	3.1			455.6			(136.0	)
Financing Activities*
	Net repayment of debt											(328.4	)		(188.5	)
	Proceeds from issuance of common stock											66.5			271.7
	Common stock dividends paid											(169.1	)		(139.7	)
	Proceeds from acquired contracts											403.3			—
	Other											5.6			0.1
Net cash used in financing activities												(22.1	)		(56.4	)
Net Increase (Decrease) in Cash and Cash Equivalents											$	433.5		$	(192.4	)

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

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

Cash Flows from Operating Activities

Cash provided by operating activities was $1,099.3 million in 2005 compared to $749.1 million in 2004. Changes in working capital had a positive impact of $154.8 million on cash flow from operations in 2005 compared to a negative impact of $287.2 million in 2004. The net increase of $442.0 million was primarily due to an increase of $547.1 million in cash from customer deposits mostly due to changes in collateral requirements resulting from higher commodity prices during the third quarter of 2005. This increase was partially offset by an increase of $135.0 million in cash used related to commodity purchases at our merchant energy business, primarily related to physical gas transactions.

        This increase in cash from changes in working capital was partially offset by a decrease in non-cash adjustments to net income of $152.4 million in 2005 compared to 2004 primarily due to a decrease in loss from discontinued operations and change in deferred taxes.

Cash Flows from Investing Activities

Cash used in investing activities was $643.7 million in 2005 compared to $885.1 million in 2004. The decrease in cash used in 2005 compared to 2004 was primarily due to less cash paid for asset acquisitions and business combinations of $218.9 million in 2005 compared to 2004, and an increase in cash proceeds from the sale of discontinued operations of $144.9 million, primarily due to the sale of Oleander in 2005 for $217.6 million. These decreases in cash used in investing activities were partially offset by approximately $211 million for investments in gas properties as discussed in more detail in the Notes to the Consolidated Financial Statements on page 15 and an increase of $82.8 million in issuances of loans receivable related to a customer contract restructuring, which is discussed in more detail in the Notes to the Consolidated Financial Statements beginning on page 11.

46

Cash Flows from Financing Activities

Cash used in financing activities was $22.1 million in 2005 compared to $56.4 million in 2004. The decrease in cash used in 2005 compared to 2004 was mostly due to proceeds from acquired contracts of $403.3 million during 2005 associated with power purchase agreements entered into by our merchant energy business. We discuss cash flows from customer contract restructurings in more detail in the Notes to the Consolidated Financial Statements beginning on page 11. This decrease in cash used in financing activities was partially offset by a reduction in proceeds from the issuance of common stock, an increase in cash used for repayments of long-term debt, and higher dividend payments in 2005 compared to 2004.

Available Sources of Funding

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

Constellation Energy

In addition to our cash balance, we have a commercial paper program under which we can issue short-term notes to fund our subsidiaries. At September 30, 2005, we had approximately $2.6 billion of credit under three facilities. These facilities include:

•

an $800.0 million three-year revolving credit facility that expires in June 2007,

•

a $300.0 million five-year revolving credit facility that expires in June 2009, and

•

a $1.5 billion five-year revolving credit facility that expires in June 2010.

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

        These revolving credit facilities allow the issuance of letters of credit up to approximately $2.6 billion. At September 30, 2005, letters of credit that totaled $1.9 billion were issued under all of our facilities, which results in approximately $0.7 billion of unused credit facilities.

        During the fourth quarter of 2005, we expect to amend and extend the terms of our $800.0 million and our $300.0 million facilities. We expect to amend the $800.0 million facility into a $1.0 billion facility and the $300.0 million facility into a $750.0 million facility, both expiring in the fourth quarter of 2010.

BGE

BGE maintains $200.0 million in annual committed credit facilities, expiring May 2006 through November 2006, in order to allow commercial paper to be issued. BGE can borrow directly from the banks or use the facilities to allow commercial paper to be issued. As of September 30, 2005, BGE had no outstanding commercial paper, which results in $200.0 million in unused credit facilities.

47

Capital Resources

Our estimated annual amounts for the years 2005 and 2006 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 2005 and 2006 include estimates of spending for existing and anticipated projects. We continuously review and modify those estimates. Actual requirements may vary from the estimates included in the table below because of a number of factors including:

•

regulation, legislation, and competition,

•

BGE load requirements,

•

environmental protection standards,

•

the type and number of projects selected for construction or acquisition,

•

the effect of market conditions on those projects,

•

the cost and availability of capital,

•

the availability of cash from operations, and

•

business decisions to invest in capital projects.

        Our estimates are also subject to additional factors. Please see the Forward Looking Statements section on page 53. We discuss the potential impact of environmental legislation in more detail in Item 1. Business—Environmental Matters section of our 2004 Annual Report on Form 10-K. We discuss regulations recently adopted by the EPA and their impact on our capital requirements in the Environmental Matters section on page 28.

Calendar Year Estimates			2005		2006
			(In millions)
Nonregulated Capital Requirements:
	Merchant energy
		Generation plants	$	170	$	175
		Nuclear fuel		130		120
		Environmental controls		5		45
		Portfolio acquisitions/investments		220		155
		Technology/other		175		115
	Total merchant energy capital requirements			700		610
	Other nonregulated capital requirements			30		5
	Total nonregulated capital requirements			730		615
Regulated Capital Requirements:
	Regulated electric			245		280
	Regulated gas			55		50
	Total regulated capital requirements			300		330
Total capital requirements			$	1,030	$	945

The above amounts do not include the Cogenex business combination. We discuss the acquisition of Cogenex in more detail in the Notes to Consolidated Financial Statements on page 15.

        Our estimated 2005 capital requirements increased since December 31, 2004 primarily due to approximately $211 million of investments made in gas properties during the second quarter of 2005. We discuss these investments in more detail in the Notes to the Consolidated Financial Statements on page 15.

Capital Requirements

Merchant Energy Business

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

•

improvements to generating plants,

•

nuclear fuel costs,

•

costs of complying with the Environmental Protection Agency (EPA), Maryland, and Pennsylvania nitrogen oxide (NO_x) and sulfur dioxide (SO₂) emissions regulations,

•

portfolio acquisitions, upstream gas investments, and other investments, and

•

enhancements to our information technology infrastructure.

Regulated Electric and Gas

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

Funding for Capital Requirements

We discuss our funding for capital requirements in our 2004 Annual Report on Form 10-K.

Contractual Payment Obligations and
Committed Amounts

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

        Our total contractual payment obligations as of September 30, 2005, increased $909.9 million during the first nine months of 2005 primarily due to an increase in fuel and transportation obligations partially offset by a decrease in long-term debt. Our fuel and transportation obligations increased mostly because of increased gas prices due to supply and demand imbalances and hurricane-related disruptions in the Gulf Coast and new contracts related to gas and nuclear fuel procurement. We detail our contractual payment obligations as of September 30, 2005 in the following table:

48

			Payments
			2005		2006- 2007		2008- 2009		There- after		Total
			(In millions)
Contractual Payment Obligations
Long-term debt:1
	Nonregulated
		Principal	$	5.4	$	640.8	$	503.8	$	2,256.1	$	3,406.1
		Interest		51.7		395.1		335.0		1,612.5		2,394.3
	Total			57.1		1,035.9		838.8		3,868.6		5,800.4
	BGE
		Principal		18.0		565.4		307.5		589.2		1,480.1
		Interest		22.4		138.7		78.3		806.6		1,046.0
	Total			40.4		704.1		385.8		1,395.8		2,526.1
BGE preference stock				—		—		—		190.0		190.0
Operating leases2				36.7		283.6		136.4		355.1		811.8
Purchase obligations:3
	Purchased capacity and energy4			235.8		903.1		500.6		164.7		1,804.2
	Fuel and transportation			804.8		2,256.5		320.0		257.3		3,638.6
	Other			69.8		114.3		65.1		176.4		425.6
Other noncurrent liabilities:
	Postretirement and postemployment benefits5			9.6		77.5		85.2		208.7		381.0
	Other			—		—		—		—		—
Total contractual payment obligations			$	1,254.2	$	5,375.0	$	2,331.9	$	6,616.6	$	15,577.7

1 Amounts in long-term debt reflect the original maturity date. Investors may require us to repay $282.3 million early through put options and remarketing features. Interest on variable rate debt is included based on the September 30, 2005 forward curve for interest rates.

2 Our operating lease commitments include future payment obligations under certain power purchase agreements as discussed further in Note 11 of our 2004 Annual Report on Form 10-K.

3 Contracts to purchase goods or services that specify all significant terms. Amounts related to certain purchase obligations are based on future purchase expectations which may differ from actual purchases.

4 Our contractual obligations for purchased capacity and energy are shown on a gross basis for certain transactions, including both the fixed payment portions of tolling contracts and estimated variable payments under unit-contingent power purchase agreements. We have recorded $9.0 million of liabilities related to purchased capacity and energy obligations at September 30, 2005 in our Consolidated Balance Sheets.

5 Amounts related to postretirement and postemployment benefits are for unfunded plans and reflect present value amounts consistent with the determination of the related liabilities recorded on the Consolidated Balance Sheets.

        The table below presents our contingent obligations. Our contingent obligations increased $2,818.0 million during the first nine months of 2005, primarily due to additional letters of credit issued and guarantees made by the parent company for subsidiary obligations to third parties. We issued additional letters of credit and parental guarantees during the third quarter of 2005 mostly because of changes in collateral requirements with counterparties as a result of higher commodity prices. In addition, the increase in letters of credit and parental guarantees was to support the growth of our merchant energy business. These amounts do not represent incremental consolidated Constellation Energy obligations; rather, they primarily represent parental guarantees of certain subsidiary obligations to third parties. Our calculation of the fair value of subsidiary obligations covered by the $7,207.9 million of parent company guarantees was $2,958.2 million at September 30, 2005. Accordingly, if the parent company was required to fund subsidiary obligations, the total amount based on September 30, 2005 market prices would be $2,958.2 million.

	Expiration
	2005		2006- 2007		2008- 2009		There- after		Total
	(In millions)
Contingent Obligations
Letters of credit	$	1,228.2	$	692.8	$	—	$	—	$	1,921.0
Guarantees—competitive supply1		3,082.1		2,239.4		324.2		1,562.2		7,207.9
Other guarantees, net2		0.4		5.6		15.3		1,243.9		1,265.2
Total contingent obligations	$	4,310.7	$	2,937.8	$	339.5	$	2,806.1	$	10,394.1

1 While the face amount of these guarantees is $7,207.9 million, we do not expect to fund the full amount. In the event the parent were required to fulfill subsidiary obligations, our calculation of the fair value of obligations covered by these guarantees was $2,958.2 million at September 30, 2005.

2 Other guarantees in the above table are shown net of liabilities of $25.0 million recorded at September 30, 2005 in our Consolidated Balance Sheets.

Liquidity Provisions

In many cases, customers of our wholesale marketing 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.

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

        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.

49

        Under counterparty contracts related to our wholesale marketing and risk management operation, we are obligated to post collateral if Constellation Energy's senior, unsecured credit ratings decline below established contractual levels. Based on contractual provisions, we estimate that we would have additional collateral obligations based on downgrades to the following credit ratings for our Senior Unsecured Debt:

Credit Ratings Downgraded to	Incremental Obligations		Cumulative Obligations
	(In millions)
BBB-/Baa3	$	533	$	533
Below investment grade		1,236		1,769

        Based on market conditions and contractual obligations at the time of a downgrade, we could be required to post collateral in an amount that could exceed the amounts specified above, which could be material. We assess the risk of being downgraded to below investment grade as remote. However, we actively monitor our collateral obligations and liquidity. We discuss our credit facilities in the Available Sources of Funding section on page 47.

        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, 2005, the debt to capitalization ratio as defined in the credit agreements was no greater than 54.1%. Certain credit facilities of BGE contain provisions requiring BGE to maintain a ratio of debt to capitalization equal to or less than 65%. At September 30, 2005, the debt to capitalization ratio for BGE as defined in these credit agreements was 44.2%.

Off-Balance Sheet Arrangements

We discuss our off-balance sheet arrangements in our 2004 Annual Report on Form 10-K.

Market Risk

Commodity Risk

We measure the sensitivity of our wholesale marketing and risk management mark-to-market energy contracts to potential changes in market prices using value at risk. Value at risk represents the potential pre-tax loss in the fair value of our wholesale marketing and risk management mark-to-market energy assets and liabilities over one and ten-day holding periods. We discuss value at risk in more detail in the Market Risk section of our 2004 Annual Report on Form 10-K. The table below is the value at risk associated with our wholesale marketing and risk management operation's mark-to-market energy assets and liabilities, including both trading and non-trading activities.

		Nine Months Ended September 30, 2005
		(In millions)
99% Confidence Level, One-Day Holding Period
	Average	$	4.7
	High		12.3
95% Confidence Level, One-Day Holding Period
	Average		3.6
	High		9.4
95% Confidence Level, Ten-Day Holding Period
	Average		11.2
	High		29.6

        We experienced higher value at risk during the nine months ended September 30, 2005 compared to the twelve months ended December 31, 2004, primarily due to higher commodity prices.

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

	Nine Months Ended September 30, 2005
	(In millions)
Average	$	4.3
High		11.4

        Due to the inherent limitations of statistical measures such as value at risk and the seasonality of changes in market prices, the value at risk calculation may not reflect the full extent of our commodity price risk exposure. Additionally, actual changes in the value of options may differ from the value at risk calculated using a linear approximation inherent in our calculation method.

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

Wholesale Credit Risk

We actively manage the credit portfolio of our wholesale marketing and risk management operation to attempt to reduce the impact of counterparty default. As of September 30, 2005 and December 31, 2004, the credit portfolio of our wholesale marketing and risk management operation had the following public credit ratings:

		September 30, 2005		December 31, 2004
Rating
	Investment Grade1	65	%	62	%
	Non-Investment Grade	15		15
	Not Rated	20		23

1 Includes counterparties with an investment grade rating by at least one of the major credit rating agencies. If split rating exists, the lower rating is used.

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        Compared to December 31, 2004, we experienced an improvement in the credit quality of our publicly rated wholesale marketing and risk management portfolio. The improvement is primarily due to more long dated transactions with investment grade counterparties.

        In addition to the credit ratings provided by the major credit rating agencies, we utilize internal credit ratings to evaluate the creditworthiness of our wholesale customers, including those companies that do not have public credit ratings. The Not Rated category in the table on the previous page includes counterparties that do not have public credit ratings and include governmental entities, municipalities, cooperatives, power pools, and other load-serving entities, and marketers for which we determine creditworthiness based on internal credit ratings.

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

	September 30, 2005		December 31, 2004
Investment Grade Equivalent	81	%	74	%
Non-Investment Grade	19		26

        Compared to December 31, 2004, the credit quality of our wholesale marketing and risk management portfolio has improved. The improvement is primarily due to more long-dated transactions with investment grade counterparties.

        A portion of our wholesale credit risk is related to transactions that are recorded in our Consolidated Balance Sheets. These transactions primarily consist of open positions from our wholesale marketing and risk management operation that are accounted for using mark-to-market accounting, as well as amounts owed by wholesale counterparties for transactions that settled but have not yet been paid. The following table highlights the credit quality and exposures related to these activities at September 30, 2005:

Rating	Total Exposure Before Credit Collateral		Credit Collateral		Net Exposure		Number of Counterparties Greater than 10% of Net Exposure	Net Exposure of Counterparties Greater than 10% of Net Exposure
	(Dollars in millions)
Investment grade	$	385	$	11	$	374	1	$	309
Split rating		11		—		11	—		—
Non-investment grade		1,915		265		1,650	—		—
Internally rated—investment grade		380		2		378	—		—
Internally rated—non-investment grade		56		35		21	—		—
Total	$	2,747	$	313	$	2,434	1	$	309

        Our net exposure to non-investment grade counterparties increased $1,586 million compared to December 31, 2004 primarily as a result of higher commodity prices.

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

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

        We continue to examine plans to achieve our strategies and to further strengthen our balance sheet and enhance our liquidity. We discuss our liquidity in the Financial Condition section beginning on page 46.

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

We discuss our exposure to interest rate risk, retail credit risk, foreign currency risk, and equity price risk in the Market Risk section of our 2004 Annual Report on Form 10-K.

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Item 3. Quantitative and Qualitative Disclosures About Market Risk

We discuss the following information related to our market risk:

•

SFAS No. 133 hedging activities section in the Notes to Consolidated Financial Statements beginning on page 24,

•

activities of our wholesale marketing and risk management operation in the Merchant Energy Business section of Management's Discussion and Analysis beginning on page 32,

•

evaluation of commodity and credit risk in the Market Risk section of Management's Discussion and Analysis beginning on page 50, and

•

changes to our business environment in the Business Environment section of Management's Discussion and Analysis beginning on page 27.

Item 4. Controls and Procedures

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

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

Evaluation of Disclosure Controls and Procedures

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

Changes in Internal Control over Financial Reporting

During the quarter ended September 30, 2005, there has been no change in either Constellation Energy's or BGE's internal control over financial reporting (as such term is defined in Rules 13a-15(f) and 15d—15(f) under the Exchange Act) that has materially affected, or is reasonably likely to materially affect, either Constellation Energy's, or BGE's, internal control over financial reporting.

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PART II. OTHER INFORMATION

Item 1. Legal Proceedings

We discuss our Legal Proceedings in the Notes to Consolidated Financial Statements beginning on page 21.

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds

The following table presents shares surrendered by employees to satisfy tax withholding obligations on vested restricted stock.

Period	Total Number of Shares Purchased	Average Price Paid for Shares		Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs	Maximum Number of Shares that May Yet Be Purchased Under the Plans and Programs
July 1 – July 31, 2005	490	$	57.45	—	—
August 1 – August 31, 2005	817		59.06	—	—
September 1 – September 30, 2005	1,493		60.41	—	—
Total	2,800	$	59.50	—	—

Item 5. Other Information

Forward Looking Statements

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

•

the timing and extent of changes in commodity prices and volatilities for energy and energy related products including coal, natural gas, oil, electricity, nuclear fuel, and emission allowances,

•

the liquidity and competitiveness of wholesale markets for energy commodities,

•

the effect of weather and general economic and business conditions on energy supply, demand, and prices,

•

the ability to attract and retain customers in our competitive supply activities and to adequately forecast their energy usage,

•

the timing and extent of deregulation of, and competition in, the energy markets, and the rules and regulations adopted on a transitional basis in those markets,

•

uncertainties associated with estimating natural gas reserves, developing properties, and extracting natural gas,

•

regulatory or legislative developments that affect deregulation, transmission or distribution rates and revenues, demand for energy, or increases in costs, including costs related to nuclear power plants, safety, or environmental compliance,

•

the inability of Baltimore Gas and Electric Company (BGE) to recover all its costs associated with providing electric residential customers service during the electric rate freeze period,

•

the conditions of the capital markets, interest rates, availability of credit, liquidity, and general economic conditions, as well as Constellation Energy Group's (Constellation Energy) and BGE's ability to maintain their current credit ratings,

•

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

•

operational factors affecting commercial operations of our generating facilities (including nuclear facilities) and BGE's transmission and distribution facilities, including catastrophic weather-related damages, unscheduled outages or repairs, unanticipated changes in fuel costs or availability, unavailability of coal or gas transportation or electric transmission services, workforce issues, terrorism, liabilities associated with catastrophic events, and other events beyond our control,

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•

the actual outcome of uncertainties associated with assumptions and estimates using judgment when applying critical accounting policies and preparing financial statements, including factors that are estimated in determining the fair value of energy contracts, such as the ability to obtain market prices and, in the absence of verifiable market prices, the appropriateness of models and model inputs (including, but not limited to, estimated contractual load obligations, unit availability, forward commodity prices, interest rates, correlation and volatility factors),

•

changes in accounting principles or practices,

•

losses on the sale or write down of assets due to impairment events or changes in management intent with regard to either holding or selling certain assets, and

•

cost and other effects of legal and administrative proceedings that may not be covered by insurance, including environmental liabilities.

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

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

Amendment to Change in Control Severance Agreement

Constellation Energy maintains Change in Control Severance Agreements (the "Agreements") with the following named executive officers: Mayo A. Shattuck III, E. Follin Smith, Michael J. Wallace, Thomas V. Brooks and Thomas F. Brady (the "Named Executive Officers"). Reference is made to the description of the Agreements that is included in the Company's Proxy Statement filed with the Securities and Exchange Commission on April 13, 2005 (file number 1-12869), and copies of the Agreements that were previously filed as exhibits to our filings with the Securities and Exchange Commission as: Exhibits 10(e) and 10(f) to our Quarterly Report on Form 10-Q for the quarter ended September 30, 2004 (file numbers 1-12869 and 1-1910), Exhibit 10(c) to our Quarterly Report on Form 10-Q for the quarter ended June 30, 2004 (file numbers 1-12869 and 1-1910), Exhibit 10(f) to our Quarterly Report on Form 10-Q for the quarter ended March 31, 2004 (file numbers 1-12869 and 1-1910) and Exhibit 10(s) to our Annual Report on Form 10-K for the fiscal year ended December 31, 2004 (file number 1-12869), respectively.

        Effective November 4, 2005, the Compensation Committee of the Board of Directors of Constellation Energy approved the amendment of the Agreements to provide certain additional protections or benefits to the Named Executive Officers in connection with a Change in Control (as defined in the Agreements) of Constellation Energy (the Company), including the following:

(a)

an extension of the period during which a Named Executive Officer may terminate his or her employment for good reason from six months after the occurrence of the event giving rise to good reason to the duration of the term of the protection period under the Agreement (which is two years following a Change in Control (the "Protection Period"));



(b)

a commitment that if a Named Executive Officer continues to work for the Company or its successor following a Change in Control and subsequently is terminated by the Company without cause or terminates his or her employment for good reason during the Protection Period (a "Qualifying Termination"), the severance and supplemental pension benefits payable to the Named Executive Officer on the Qualifying Termination will be no less than what they would have been had the Named Executive Officer's employment terminated immediately following the Change in Control;



(c)

the addition of three years to the Named Executive Officer's age for purposes of calculating the present value of the applicable Named Executive Officer's supplemental retirement benefit;



(d)

that the benefits under the Agreement will be provided to the estate of a Named Executive Officer who dies after providing the Company with notice of good reason during the Protection Period;



(e)

a commitment to provide certain continuing medical and dental coverage and life insurance (or the economic equivalent of such continuing coverage) following a Qualifying Termination;



(f)

a commitment to continue to maintain director's and officer's coverage and related indemnities following any Change in Control;



(g)

a mutual release of claims by the Named Executive Officer and the Company in connection with a Qualifying Termination; and



(h)

in the event of a Change in Control, the Company will, subject to any required shareholder approvals, issue replacement option grants to the Named Executive Officers who are employed by the Company as of the Change in Control by issuing the same number of options

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(as adjusted to reflect the transaction that resulted in the Change in Control) with the same vesting terms and expiration date as options for which the gain over the exercise price has been paid in cash and the option has lapsed under the Company's equity incentive plans, except that (i) the exercise price will be the higher of the exercise price of the lapsed option (as adjusted to reflect the transaction that resulted in the Change in Control) or the fair market value of the stock underlying the replacement options at the time the replacement options are granted, and (ii) the replacement options will not vest as a result of the Change in Control but will, to the extent not already vested, fully vest after the Change in Control upon a Qualifying Termination.

        The Compensation Committee also approved the amendment of the Agreements to provide (i) that payment of any amounts under the Agreement that would be treated as non-qualified deferred compensation under Section 409A of the Internal Revenue Code (the "Code") will be delayed for six months after the date of a Named Executive Officer's Qualifying Termination (or, if earlier, the date the Named Executive Officer dies) if required under Section 409A of the Code, (ii) that the Company will not, without the agreement of the Named Executive Officer, take any action that would expose any payment or benefit under the Agreement or any plan, arrangement or other agreement to the additional tax of Section 409A of the Code and will hold the Named Executive Officer harmless for any action in violation of this provision and (iii) that if the Company or Named Executive Officer believes any benefit or right under the Agreement does not comply with the requirements of Section 409A of the Code, the Company and the Named Executive Officer will negotiate reasonably and in good faith to amend the terms of such arrangement such that it does comply (with the most limited possible economic effect on the Named Executive and the Company).

55

Item 6. Exhibits

Exhibit No. 10(a)	Description of Material Terms of Amendment to Change in Control Severance Agreement.
Exhibit No. 12(a)	Constellation Energy Group, Inc. Computation of Ratio of Earnings to Fixed Charges.
Exhibit No. 12(b)	Baltimore Gas and Electric Company Computation of Ratio of Earnings to Fixed Charges and Computation of Ratio of Earnings to Combined Fixed Charges and Preferred and Preference Dividend Requirements.
Exhibit No. 31(a)	Certification of Chairman of the Board, President and Chief Executive Officer of Constellation Energy Group, Inc. pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
Exhibit No. 31(b)	Certification of Executive Vice President, Chief Financial Officer, and Chief Administrative Officer of Constellation Energy Group, Inc. pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
Exhibit No. 31(c)	Certification of President and Chief Executive Officer of Baltimore Gas and Electric Company pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
Exhibit No. 31(d)	Certification of Senior Vice President and Chief Financial Officer of Baltimore Gas and Electric Company pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
Exhibit No. 32(a)	Certification of Chairman of the Board, President and Chief Executive Officer of Constellation Energy Group, Inc. pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
Exhibit No. 32(b)	Certification of Executive Vice President, Chief Financial Officer, and Chief Administrative Officer of Constellation Energy Group, Inc. pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
Exhibit No. 32(c)	Certification of President and Chief Executive Officer of Baltimore Gas and Electric Company pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
Exhibit No. 32(d)	Certification of Senior Vice President and Chief Financial Officer of Baltimore Gas and Electric Company pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

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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 8, 2005	/s/  E. FOLLIN SMITHE. Follin Smith, Executive Vice President of Constellation Energy Group,  Inc. and Senior Vice President of Baltimore Gas and Electric Company, and as Principal Financial Officer of each Registrant

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QuickLinks

PART 1—FINANCIAL INFORMATION
Item 1—Financial Statements
CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED)
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)
CONSOLIDATED BALANCE SHEETS
CONSOLIDATED BALANCE SHEETS
CONSOLIDATED STATEMENTS OF CASH FLOWS
CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED)
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)
CONSOLIDATED BALANCE SHEETS
CONSOLIDATED BALANCE SHEETS
CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Basis of Presentation
Variable Interest Entities
Customer Contract Restructuring
Earnings Per Share
Stock-Based Compensation
Accretion of Asset Retirement Obligations
Workforce Reduction
Discontinued Operations
International Investments
Oleander
Business Combination
Asset Acquisition
Information by Operating Segment

Pension and Postretirement Benefits
Financing Activities
Income Taxes
Commitments, Guarantees, and Contingencies
Long-Term Power Sales Contracts
Guarantees
Environmental Matters
Legal Proceedings
Insurance
SFAS No. 133 Hedging Activities
Interest Rates
Commodity Prices
Accounting Standards Issued
SFAS No. 123 Revised
FIN 47
Accounting Standards Adopted
SFAS No. 153
Related Party Transactions—BGE
Income Statement
Balance Sheet

Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations
Introduction and Overview

Business Environment
Regulation by the Maryland PSC
Regulation in Other States
Federal Regulation
Accounting Standards Issued and Adopted
Events of 2005
Commodity Prices
Discontinued Operations
Business Combination and Asset Acquisition
Pension Plan Assets

Results of Operations for the Quarter and Nine Months Ended September 30, 2005 Compared with the Same Periods of 2004
Quarter Ended September 30, 2005
Nine Months Ended September 30, 2005
Merchant Energy Business
Regulated Electric Business
Regulated Gas Business
Other Nonregulated Businesses
Consolidated Nonoperating Income and Expenses
Financial Condition
Cash Flows
Available Sources of Funding
Capital Resources
Capital Requirements
Funding for Capital Requirements
Contractual Payment Obligations and Committed Amounts
Liquidity Provisions
Off-Balance Sheet Arrangements
Market Risk
Commodity Risk
Wholesale Credit Risk
Interest Rate Risk, Retail Credit Risk, Foreign Currency Risk, and Equity Price Risk
Item 3. Quantitative and Qualitative Disclosures About Market Risk
Item 4. Controls and Procedures
PART II OTHER INFORMATION

PART II. OTHER INFORMATION
Item 1. Legal Proceedings
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds
Item 5. Other Information
Forward Looking Statements
Amendment to Change in Control Severance Agreement

Item 6. Exhibits

SIGNATURE